10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

ý 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 1-7414

NORTHWEST PIPELINE LLC

(Exact name of registrant as specified in its charter)

DELAWARE	26-1157701
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
295 Chipeta Way Salt Lake City, Utah	84108
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (801) 583-8800

Securities registered pursuant to Section 12(b) of the Act: None

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  ¨    No  þ

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  þ

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  þ    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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  þ    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) 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. þ

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	¨	Accelerated filer	¨
Non-accelerated filer	þ (Do not check if a smaller reporting company)	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  þ

DOCUMENTS INCORPORATED BY REFERENCE:

None

THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION (I)(1)(a) AND (b) OF FORM 10-K AND IS THEREFORE FILING THIS FORM 10-K WITH THE REDUCED DISCLOSURE FORMAT.

NORTHWEST PIPELINE LLC

FORM 10-K

TABLE OF CONTENTS

	Page
PART I
Item 1. BUSINESS	3
Item 1A. RISK FACTORS	5
Item 1B. UNRESOLVED STAFF COMMENTS	16
Item 2. PROPERTIES	16
Item 3. LEGAL PROCEEDINGS	17
Item 4. MINE SAFETY DISCLOSURES	17
PART II
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	17
Item 6. SELECTED FINANCIAL DATA (Omitted)	17
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	17
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	19
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	20
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	40
Item 9A. CONTROLS AND PROCEDURES	40
Item 9B. OTHER INFORMATION	41
PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE (Omitted)	42
Item 11. EXECUTIVE COMPENSATION (Omitted)	42
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS (Omitted)	42
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE (Omitted)	42
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES	42
PART IV
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	43

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DEFINITIONS

We use the following gas measurements in this report:

Dth-means dekatherm.

Mdth-means thousand dekatherms.

MMdth-means million dekatherms.

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PART I

Item 1. BUSINESS

Northwest Pipeline LLC (Northwest) is indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). On February 2, 2015, WPZ was merged into Access Midstream Partners, L.P. (ACMP), another publicly traded limited partnership consolidated by Williams. ACMP was the surviving partnership and was subsequently renamed WPZ. At December 31, 2015, Williams holds an approximate 60 percent interest in WPZ, comprised of an approximate 58 percent limited partner interest and all of WPZ’s 2 percent general partner interest.

On September 28, 2015, Williams publicly announced in a press release that it had entered into an Agreement and Plan of Merger (Merger Agreement) with Energy Transfer Equity, L.P. (Energy Transfer) and certain of its affiliates. The Merger Agreement provides that, subject to the satisfaction of customary closing conditions, Williams will be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger) with ETC surviving the ETC Merger. Energy Transfer formed ETC as a limited partnership that will be treated as a corporation for U.S. federal income tax purposes. Immediately following the completion of the ETC Merger, ETC will contribute to Energy Transfer all of the assets and liabilities of Williams in exchange for the issuance by Energy Transfer to ETC of a number of Energy Transfer Class E common units equal to the number of ETC common shares issued to Williams stockholders in the ETC Merger (ETC Exchange). WPZ expects to retain its current name and remain a publicly traded limited partnership following the ETC Merger.

In this report, Northwest is at times referred to in the first person as “we,” “us,” or “our.”

GENERAL

We own and operate a natural gas pipeline system that extends from the San Juan Basin in northwestern New Mexico and southwestern Colorado through the states of Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on the Canadian border near Sumas, Washington. We provide natural gas transportation services for markets in Washington, Oregon, Idaho, Wyoming, Nevada, Utah, Colorado, New Mexico, California and Arizona, either directly or indirectly through interconnections with other pipelines. Our principal business is the interstate transportation of natural gas, which is regulated by the Federal Energy Regulatory Commission (FERC).

Our system includes approximately 3,900 miles of mainline and lateral transmission pipeline and 41 transmission compressor stations. Our compression facilities have a combined sea level-rated capacity of approximately 472,000 horsepower. At December 31, 2015, we had long-term firm transportation contracts and storage redelivery agreements, with aggregate capacity reservations of approximately 3.8 MMdth of natural gas per day.

We own a one-third interest in the Jackson Prairie underground storage facility located near Chehalis, Washington. We have a contract with a third party under which we contract for natural gas storage services in an underground storage reservoir in the Clay Basin Field located in Daggett County, Utah. We also own and operate a Liquefied Natural Gas (LNG) storage facility near Plymouth, Washington. We have approximately 14.2 MMdth of working natural gas storage capacity through these three storage facilities, which is substantially utilized for third-party natural gas. These natural gas storage facilities enable us to balance daily receipts and deliveries and provide storage services to our customers.

We transport and store natural gas for a broad mix of customers, including local natural gas distribution companies, municipal utilities, direct industrial users, electric power generators, and natural gas marketers and producers. Our firm transportation and storage contracts are generally long-term contracts with various expiration dates and account for the major portion of our business. Additionally, we offer interruptible and short-term firm transportation services. During 2015, our three largest customers were Puget Sound Energy, Inc., Northwest Natural Gas Company, and Cascade Natural Gas Corporation, which accounted for approximately 25.0 percent, 10.8 percent, and 10.2 percent, respectively, of our total operating revenues for the year ended December 31, 2015. No other customer accounted for more than 10 percent of our total operating revenues during that period.

Our rates are subject to the rate-making policies of the FERC. We provide a significant portion of our transportation and storage services pursuant to long-term firm contracts that obligate our customers to pay us monthly capacity reservation fees, which are fees that are owed for reserving an agreed upon amount of pipeline or storage capacity regardless of the amount of pipeline or storage capacity actually utilized by a customer. When a customer utilizes the capacity it has reserved under a firm transportation contract, we also collect a volumetric fee based on the quantity of natural gas transported. These volumetric fees are typically a small percentage of the total fees received under a firm contract. We also derive a small portion of our revenues from short-term firm and interruptible contracts under which customers pay fees for transportation, storage and other related

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services. The high percentage of our revenue derived from capacity reservation fees helps mitigate the risk of revenue fluctuations caused by changing supply and demand conditions.

RATE MATTERS

Our transportation rates are established through the FERC ratemaking process. Key determinants in the ratemaking process are (1) costs of providing service, including depreciation expense, (2) allowed rate of return, including the equity component of the capital structure and related income taxes, and (3) contract volume and throughput assumptions. The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the reservation and commodity rates also impact profitability. As a result of these proceedings, certain revenues may be collected subject to refund. We record estimates of rate refund liabilities considering our and third-party regulatory proceedings, advice of counsel, and other risks.

Our rates became effective January 1, 2013, and will remain in effect for 5 years.

REGULATION

FERC Regulation

Our interstate transmission and storage activities are subject to regulation by the FERC under the Natural Gas Act of 1938 (NGA), as amended, and under the Natural Gas Policy Act of 1978 (NGPA), as amended, and, as such, our rates and charges for the transportation of natural gas in interstate commerce, the extension, enlargement or abandonment of jurisdictional facilities, and accounting, among other things, are subject to regulation. We hold certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of pipelines, facilities and properties under the NGA. The FERC’s Standards of Conduct govern the relationship between natural gas transmission providers and marketing function employees as defined by the rule. The standards of conduct are intended to prevent natural gas transmission providers from preferentially benefiting gas marketing functions by requiring the employees of a transmission provider that perform transmission functions to function independently from gas marketing employees and by restricting the information that transmission providers may provide to gas marketing employees. Under the Energy Policy Act of 2005, the FERC is authorized to impose civil penalties of up to $1 million per day for each violation of its rules.

Environmental Matters

Our operations are subject to federal environmental laws and regulations as well as the state and local laws and regulations adopted by the jurisdictions in which we operate. We could incur liability to governments or third parties for any unlawful discharge of pollutants into the air, soil, or water, as well as liability for cleanup costs. Materials could be released into the environment in several ways including, but not limited to:

• Leakage from gathering systems, underground gas storage caverns, pipelines, transportation facilities, and storage tanks;

• Damage to facilities resulting from accidents during normal operations;

• Damages to equipment and facilities resulting from storm events or natural disasters; and

• Blowouts, cratering, and explosions.

In addition, we may be liable for environmental damage caused by former operators of our properties.

We believe compliance with current environmental laws and regulations will not have a material adverse effect on our capital expenditures, earnings, or competitive position. However, environmental laws and regulations could affect our business in various ways from time to time, including incurring capital and maintenance expenditures, fines, and penalties, and creating the need to seek relief from the FERC for rate increases to recover the costs of certain capital expenditures and operation and maintenance expenses.

For additional information regarding the potential impact of federal, state, or local regulatory measures on our business and specific environmental issues, please refer to “Risk Factors –Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities, and expenditures, and could exceed current expectations,” and “Item 8. Financial Statements and Supplementary Data – Notes to Financial Statements: Note 3. Contingent Liabilities and Commitments – Environmental Matters.”

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Safety and Maintenance

Our operations are subject to the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Improvement Act of 2002, and the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011 (Pipeline Safety Act), which regulate safety requirements in the design, construction, operation, and maintenance of interstate natural gas transmission facilities. The U.S. Department of Transportation (USDOT) administers federal pipeline safety laws.

Federal pipeline safety laws authorize USDOT to establish minimum safety standards for pipeline facilities and persons engaged in the transportation of gas or hazardous liquids by pipeline. These safety standards apply to the design, construction, testing, operation, and maintenance of gas and hazardous liquids pipeline facilities affecting interstate or foreign commerce. USDOT has also established reporting requirements for operators of gas and hazardous liquid pipeline facilities, as well as provisions for establishing the qualification of pipeline personnel and requirements for managing the integrity of gas transmission and distribution lines and certain hazardous liquid pipelines. To ensure compliance with these provisions, USDOT performs pipeline safety inspections and has the authority to initiate enforcement actions.

On January 3, 2012, the Pipeline Safety Act was enacted. The Pipeline Safety Act requires USDOT to complete a number of reports in preparation for potential rulemakings. The issues addressed in these rulemaking provisions include, but are not limited to, the use of automatic or remotely-controlled shut-off valves on new or replaced transmission line facilities, modifying the requirements for pipeline leak detection systems, and expanding the scope of the pipeline integrity management requirements. USDOT is considering these and other provisions in currently pending rulemaking proceedings.

Pipeline Integrity Regulations We have developed an Integrity Management Plan in compliance with the USDOT Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for transmission pipelines that could affect high consequence areas in the event of pipeline failure. The Integrity Management Plan includes a baseline assessment plan along with periodic reassessments to be completed within required timeframes. In meeting the integrity regulations, we identified high consequence areas as defined by the rule.

Reassessments of the original segments have begun as required by regulations. As new pipelines are constructed and new high consequence areas are created, additional pipeline segments are required to be added to the baseline assessment plan. These segments are also on schedule as required. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

EMPLOYEES

Northwest has no employees. Operations, management, and certain administrative services are provided by Williams and its affiliates.

TRANSACTIONS WITH AFFILIATES

We engage in transactions with WPZ, Williams, and other Williams’ subsidiaries. Please see “Item 8. Financial Statements and Supplementary Data — Notes to Financial Statements: Note 1. Summary of Significant Accounting Policies” and “Note 7. Transactions with Major Customers and Affiliates.”

Item 1A. RISK FACTORS

FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE

“SAFE HARBOR” PROVISIONS OF

THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

The reports, filings, and other public announcements of Northwest Pipeline LLC, may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act). These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions, and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

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All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe, or anticipate will exist or may occur in the future are forward-looking statements. Forward-looking statements can be identified by various forms of words or phrases such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “assumes,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “guidance,” “outlook,” “in service date,” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

• The status, expected timing and expected outcome of the proposed ETC Merger;

• Events which may occur subsequent to the proposed ETC Merger including events which directly impact our business;

• Amounts and nature of future capital expenditures;

• Expansion and growth of our business and operations;

• Financial condition and liquidity;

• Business strategy;

• Cash flow from operations or results of operations;

• Rate case filings;

• Natural gas prices, supply, and demand; and

• Demand for our services.

Forward-looking statements are based on numerous assumptions, uncertainties, and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

• The timing and likelihood of completion of the proposed ETC Merger, including the satisfaction of conditions to the completion of the proposed ETC Merger;

• Energy Transfer’s plans for us, following the completion of the proposed ETC Merger;

• Disruption from the proposed ETC Merger making it more difficult to maintain business and operational relationships;

• Availability of supplies, market demand, and volatility of prices;

• Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);

• The strength and financial resources of our competitors and the effects of competition;

• Whether we are able to successfully identify, evaluate, and execute investment opportunities;

• Development of alternative energy sources;

• The impact of operational and development hazards and unforeseen interruptions;

• Costs of, changes in, or the results of laws, government regulations (including safety and environmental regulations), environmental liabilities, litigation and rate proceedings;

• Our allocated costs for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates;

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• Changes in maintenance and construction costs;

• Changes in the current geopolitical situation;

• Our exposure to the credit risks of our customers and counterparties;

• Risks related to financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of capital;

• Risks associated with weather and natural phenomena, including climate conditions;

• Acts of terrorism, including cybersecurity threats and related disruptions; and

• Additional risks described in our filings with the Securities and Exchange Commission (SEC).

Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or to announce publicly any revisions to any of the forward-looking statements to reflect future events or developments.

In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. These factors are described in the following section.

RISK FACTORS

You should carefully consider the following risk factors in addition to the other information in this report. If any of the risks discussed below occur, our business, prospects, financial condition, results of operations, cash flows and, in some cases our reputation, could be materially adversely affected. Each of these factors could adversely affect our business, operating results, and financial condition as well as adversely affect the value of an investment in our securities.

Throughout these risk factors reference is made to Williams and the potential impact Williams may have on our business, financial condition and operating results. As noted herein, Williams has entered into the Energy Transfer Merger Agreement with Energy Transfer and certain of its affiliates. Should the ETC Merger and the ETC Exchange each be consummated, references throughout these risk factors to Williams would instead refer to Energy Transfer or ETC, as applicable.

Risks Inherent to Our Industry and Business

Our natural gas transportation and storage activities involve numerous risks and hazards that might result in accidents and unforeseen interruptions.

Our operations are subject to all the risks and hazards typically associated with the transportation and storage of natural gas including, but not limited to:

• Fires, blowouts, cratering, and explosions;

• Uncontrolled releases of natural gas;

• Pollution and other environmental risks;

• Aging infrastructure and mechanical problems;

• Damages to pipelines and pipeline blockages or other pipeline interruptions;

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• Operator error; and

• Damage caused by third party activity, such as operation of construction equipment.

Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations, loss of services to our customers, reputational damage, and substantial losses to us. The location of certain segments of our pipeline in or near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks. An event such as those described above could cause considerable harm and have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance.

Certain of our services are subject to long-term, fixed-price contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.

We provide some services pursuant to long-term, fixed-price contracts. It is possible that costs to perform services under such contracts will exceed the revenues we collect for our services. Although most of the services are priced at cost-based rates that are subject to adjustment in rate cases, under the FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” that may be above or below the FERC regulated cost-based rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs that could be produced by inflation or other factors relating to the specific facilities being used to perform the services.

We may not be able to extend or replace expiring natural gas transportation and storage contracts at favorable rates, on a long-term basis or at all.

Our primary exposure to market risk occurs at the time the terms of existing transportation and storage contracts expire or are subject to termination. Upon expiration or termination of our existing contracts, we may not be able to extend such contracts with existing customers or obtain replacement contracts at favorable rates, on a long-term basis or at all. Failure to extend or replace a significant portion of our existing contracts may have a material adverse effect on our business, financial condition, results of operations and cash flows. Our ability to extend or replace existing customer contracts on favorable terms is subject to a number of factors, some of which are beyond our control, including:

• The level of existing and new competition to deliver natural gas to our markets and competition from alternative fuel sources such as electricity, coal, fuel oils, or nuclear energy;

• Pricing, demand, availability, and margins for natural gas in our markets;

• Whether the market will continue to support long-term firm contracts;

• The effects of regulation on us, our customers, and our contracting practices; and

• The ability to understand our customers’ expectations, efficiently and reliably deliver high quality services, and effectively manage customer relationships. The result of these efforts will impact our reputation and positioning in the market.

Competitive pressures could lead to decreases in the volume of natural gas contracted for or transported through our pipeline system.

The principal elements of competition among natural gas transportation and storage assets are rates, terms of service, access to natural gas supplies, flexibility, and reliability. Although most of our pipeline system’s current capacity is fully contracted, the FERC has taken certain actions to strengthen market forces in the interstate natural gas pipeline industry that have led to increased competition throughout the industry. Similarly, a highly liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. As a result, pipeline capacity is being used more efficiently, and peaking and storage services are increasingly effective substitutes for annual pipeline capacity. As a result, we could experience some “turnback” of firm capacity as the primary terms of existing agreements expire. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we or our remaining customers may have to bear the costs associated with the turned back capacity.

We compete primarily with other interstate pipelines and storage facilities in the transportation and storage of natural gas. Some of our competitors may have greater financial resources and access to greater supplies of natural gas than we do. Some of these competitors may expand or construct transportation and storage systems that would create additional competition for natural gas supplies or the services we provide to our customers. Moreover, WPZ and its other affiliates, including Williams, may not be

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limited in their ability to compete with us. In a number of key markets, interstate pipelines are now facing competitive pressure from other major pipeline systems, enabling local distribution companies and end users to choose a transmission provider based on considerations other than location. Other entities could construct new pipelines or expand existing pipelines that could potentially serve the same markets as our pipeline system. Any such new pipelines could offer transportation services that are more desirable to shippers because of locations, facilities, or other factors. These new pipelines could charge rates or provide service to locations that would result in greater net profit for shippers and producers and thereby force us to lower the rates charged for service on our pipeline in order to extend our existing transportation service agreements or to attract new customers. We are aware of proposals by competitors to expand pipeline capacity in certain markets we also serve which, if the proposed projects proceed, could increase the competitive pressure upon us. Further, natural gas also competes with other forms of energy available to our customers, including electricity, coal, fuel oils, and other alternative energy sources. We may not be able to successfully compete against current and future competitors and any failure to do so could have a material adverse effect on our business, cash flows, and results of operations.

Any significant decrease in supplies of natural gas in the supply basins we access or in demand for those supplies in our traditional markets could adversely affect our business and operating results.

Our ability to maintain and expand our business depends on the level of drilling and production by third parties in our supply basins. Production from existing wells and natural gas supply basins with access to our pipeline will naturally decline over time. The amount of natural gas reserves underlying these existing wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. We do not obtain independent evaluations of natural gas reserves underlying such wells and supply basins with access to our pipeline. Accordingly, we do not have independent estimates of total reserves dedicated to our pipeline or the anticipated life of such reserves. In addition, low prices for natural gas, regulatory limitations, including environmental regulations, or the lack of available capital for these projects could adversely affect the development and production of additional reserves, as well as gathering, storage, pipeline transportation, and import and export of natural gas supplies. The competition for natural gas supplies to serve other markets could also reduce the amount of natural gas supply for our customers.

Demand for our transportation services depends on the ability and willingness of shippers with access to our facilities to satisfy demand in the markets we serve by deliveries through our system. Any decrease in this demand could adversely affect our business. Demand for natural gas is also affected by weather, future industrial and economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation, and technological advances in fuel economy and energy generation devices, all of which are matters beyond our control.

A failure to obtain sufficient natural gas supplies or a reduction in demand for our services in the markets we serve could have a material adverse effect on our business, financial condition, and results of operations.

Significant prolonged changes in natural gas prices could affect supply and demand and cause a reduction in or termination of our long-term transportation and storage contracts or throughput on our system.

Higher natural gas prices over the long term could result in a decline in the demand for natural gas and, therefore, in our long-term transportation and storage contracts or throughput on our system. Also, lower natural gas prices over the long term could result in a decline in the production of natural gas resulting in reduced contracts or throughput on our system. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Our costs of testing, maintaining or repairing our facilities may exceed our expectations, and the FERC may not allow, or competition in our markets may prevent our recovery of such costs in the rates we charge for our services.

We have experienced and could experience in the future unexpected leaks or ruptures on our gas pipeline system. Either as a preventative measure or in response to a leak or another issue, we could be required by regulatory authorities to test or undertake modifications to our systems. If the cost of testing, maintaining, or repairing our facilities exceed expectations and the FERC does not allow us to recover, or competition in our markets prevents us from recovering, such costs in the rates that we charge for our services, such costs could have a material adverse impact on our business, financial condition, and results of operations.

Legal and regulatory proceedings and investigations relating to the energy industry have adversely affected our business and may continue to do so. The operation of our businesses might also be adversely affected by changes in government regulations or in their interpretation or implementation, or the introduction of new laws or regulations applicable to our businesses or our customers.

Public and regulatory scrutiny of the energy industry has resulted in the proposal and/or implementation of increased regulations. Such scrutiny has also resulted in various inquiries, investigations, and court proceedings, including litigation of

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energy industry matters. Both the shippers on our pipeline and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.

Certain inquiries, investigations, and court proceedings are ongoing. Adverse effects may continue as a result of the uncertainty of these ongoing inquiries, investigations, and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines and/or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our revenues and net income or increase our operating costs in other ways. Current legal proceedings or other matters including environmental matters, suits, regulatory appeals, and similar matters might result in adverse decisions against us, which among other outcomes, could result in the imposition of substantial penalties and fines and could damage our reputation. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.

In addition, existing regulations might be revised or reinterpreted and new laws and regulations might be adopted or become applicable to us, our customers, or our business activities. If new laws or regulations are imposed relating to oil and gas extraction, or if additional levels of reporting, regulation, or permitting moratoria are required or imposed, including those related to hydraulic fracturing, the volumes of natural gas that we transport could decline and our results of operations could be adversely affected.

Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities, and expenditures that could exceed our expectations.

Our operations are subject to extensive federal, state, tribal, and local laws and regulations governing environmental protection, endangered and threatened species, the discharge of materials into the environment, and the security of chemical and industrial facilities. Substantial costs, liabilities, delays, and other significant issues related to environmental laws and regulations are inherent in the gathering, transportation, and storage of natural gas as well as waste disposal practices and construction activities. New or amended environmental laws and regulations can also result in significant increases in the capital costs we incur to comply with such laws and regulations.

Failure to comply with laws, regulations, and permits may result in the assessment of administrative, civil, and/or criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, and delays in granting permits.

Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations for the remediation of contaminated areas and in connection with spills or releases of materials associated with natural gas, oil, and wastes on, under, or from our properties and facilities. Private parties, including the owners of properties through which our pipeline system passes and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third party hydrocarbon storage and processing or oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours.

We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.

In addition, climate change and the costs that may be associated with its impacts and with the regulation of emissions of greenhouse gases (GHG) have the potential to affect our business. Regulatory actions by the U.S. Environmental Protection Agency (EPA) or the passage of new climate change laws or regulations could result in increased costs to (i) operate and maintain our facilities, (ii) install new emissions controls on our facilities, and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Climate change and GHG regulation could also reduce demand for our services.

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We depend on certain key customers for a significant portion of our revenues. The loss of any of these key customers or the loss of any contracted volumes could result in a decline in our business.

We rely on a limited number of customers for a significant portion of our revenues. Although some of these customers are subject to long-term contracts, we may be unable to negotiate extensions or replacements of these contracts on favorable terms, or at all. For the year ended December 31, 2015, our three largest customers were Puget Sound Energy, Inc., Northwest Natural Gas Company, and Cascade Natural Gas Corporation. These customers accounted for approximately 25.0 percent, 10.8 percent, and 10.2 percent, respectively, of our operating revenues for the year ended December 31, 2015. The loss of all, or even a portion of, the revenues from contracted volumes supplied by our key customers, as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts, or otherwise, could have a material adverse effect on our business, results of operations, financial condition, and cash flows, unless we are able to acquire comparable volumes from other sources.

We are exposed to the credit risk of our customers and counterparties and our credit risk management will not be able to completely eliminate such risk.

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business. Generally, our customers are rated investment grade, are otherwise considered creditworthy, or are required to make pre-payments or provide security to satisfy credit concerns. However, our credit procedures and policies will not completely eliminate customer credit risk. Our customers and counterparties include industrial customers, local distribution companies, natural gas producers, and marketers whose creditworthiness may be suddenly and disparately impacted by, among other factors, commodity price volatility, deteriorating energy market conditions, and public and regulatory opposition to energy producing activities. The current low commodity price environment has, in particular, negatively impacted natural gas producers causing them significant economic stress including, in some cases, to file for bankruptcy protection or to renegotiate contracts. To the extent one or more of our key customers commences bankruptcy proceedings, our contracts with the customers may be subject to rejection under applicable provisions of the United States Bankruptcy Code, or may be renegotiated. Further, during any such bankruptcy proceeding, prior to assumption, rejection or renegotiation of such contracts, the bankruptcy court may temporarily authorize the payment of value for our services less than contractually required, which could have a material adverse effect on our business, results of operations, cash flows and financial condition. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties, or otherwise do not take sufficient mitigating actions, including obtaining sufficient collateral, deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off accounts receivable. Such write-downs or write-offs could negatively affect our operating results for the period in which they occur, and, if significant, could have a material adverse effect on our business, results of operations, cash flows, and financial condition.

If third-party pipelines and other facilities interconnected to our pipeline and facilities become unavailable to transport natural gas, our revenues could be adversely affected.

We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipeline and storage facilities for the benefit of our customers. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these pipelines or other facilities were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines or facilities, reduced operating pressures, lack of capacity, increased credit requirements or rates charged by such pipelines or facilities or other causes, we and our customers would have reduced capacity to transport, store or deliver natural gas to end use markets, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnection causing a material reduction in volumes transported on our pipeline or stored at our facilities could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We do not own all of the land on which our pipeline and facilities are located, which could disrupt our operations.

We do not own all of the land on which our pipeline and facilities have been constructed. As such, we are subject to the possibility of increased costs to retain necessary land use. In those instances in which we do not own the land on which our facilities are located, we obtain the rights to construct and operate our pipeline on land owned by third parties and governmental agencies for a specific period of time. Our loss of any of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and cash flows.

We do not insure against all potential risks and losses and could be seriously harmed by unexpected liabilities or by the inability of our insurers to satisfy our claims.

In accordance with customary industry practice, we maintain insurance against some, but not all, risks and losses, and only at levels we believe to be appropriate.

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Williams currently maintains excess liability insurance with limits of $820 million per occurrence and in the annual aggregate with a $2 million per occurrence deductible. This insurance covers Williams, its subsidiaries, and certain of its affiliates, including us, for legal and contractual liabilities arising out of bodily injury or property damage, including resulting loss of use to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability for full limits, with the first $135 million of insurance also providing gradual pollution liability coverage for natural gas and natural gas liquids operations.

Although we maintain property insurance on certain physical assets that we own, lease, or are responsible to insure, the policy may not cover the full replacement cost of all damaged assets or the entire amount of business interruption loss we may experience. In addition, certain perils may be excluded from coverage or sub-limited. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. We may elect to self-insure a portion of our risks. We do not insure our onshore underground pipelines for physical damage, except at certain locations such as river crossings and compressor stations. All of our insurance is subject to deductibles.

In addition to the insurance coverage described above, Williams is a member of Oil Insurance Limited (OIL), an energy industry mutual insurance company, which provides coverage for damage to our property. As an insured member of OIL, Williams shares in the losses among other OIL members even if our property is not damaged. As a result, we may share in any losses incurred by Williams.

The occurrence of any risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows, and our ability to repay our debt.

We may not be able to grow or effectively manage our growth.

As part of our growth strategy, we consider acquisition opportunities and engage in significant capital projects. We have a project lifecycle process and an investment evaluation process. These are processes we use to identify, evaluate, and execute on acquisition opportunities and capital projects. We may not always have sufficient and accurate information to identify and value potential opportunities and risks or our investment evaluation process may be incomplete or flawed. Regarding potential acquisitions, suitable acquisition candidates may not be available on terms and conditions we find acceptable or, where multiple parties are trying to acquire an acquisition candidate, we may not be chosen as the acquirer. If we are able to acquire a targeted business, we may not be able to successfully integrate the acquired businesses and realize anticipated benefits in a timely manner. Our growth may also be dependent upon the construction of new natural gas gathering, transportation, compression, processing, or treating pipelines and facilities, NGL transportation, fractionation, or storage facilities, or olefins processing facilities, as well as the expansion of existing facilities. We also face all the risks associated with construction. These risks include the inability to obtain skilled labor, equipment, materials, permits, rights-of-way, and other required inputs in a timely manner such that projects are completed on time and the risk that construction cost overruns could cause total project costs to exceed budgeted costs. Additional risks associated with growing our business include, among others, that:

• Changing circumstances and deviations in variables could negatively impact our investment analysis, including our projections of revenues, earnings, and cash flow relating to potential investment targets, resulting in outcomes which are materially different than anticipated;

• We could be required to contribute additional capital to support acquired businesses or assets. We may assume liabilities that were not disclosed to us that exceed our estimates and for which contractual protections are either unavailable or prove inadequate;

• Acquisitions could disrupt our ongoing business, distract management, divert financial and operational resources from existing operations, and make it difficult to maintain our current business standards, controls, and procedures; and

• Acquisitions and capital projects may require substantial new capital, either by the issuance of debt or equity, and we may not be able to access credit or capital markets or obtain acceptable terms.

If realized, any of these risks, including impairments, could have an adverse impact on our results of operations, financial position, or cash flows.

Failure of our service providers or disruptions to outsourcing relationships might negatively impact our ability to conduct our business.

We rely on Williams and other third parties for certain services necessary for us to be able to conduct our business. We have a limited ability to control these operations and the associated costs. Certain of Williams’ accounting and information technology functions that we rely on are currently provided by third party vendors, and sometimes from service centers outside of the United

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States. Services provided pursuant to these agreements could be disrupted. Similarly, the expiration of such agreements or the transition of services between providers could lead to loss of institutional knowledge or service disruptions. Our reliance on Williams and others as service providers and on Williams’ outsourcing relationships, and our limited ability to control certain costs, could have a material adverse effect on our business, results of operations, and financial condition.

The pendency of the proposed ETC Merger between Energy Transfer and Williams could adversely affect our business and operations.

The proposed ETC Merger between Energy Transfer and Williams may create a significant distraction for the management team and board of directors of Williams and require Williams to expend significant time and resources. As certain members of Williams’ management team also serve on our management team we may encounter the same management distraction and constraints. In connection with the proposed ETC Merger some of our customers or vendors may delay or defer decisions, which could negatively impact our revenues, earnings, cash flows and expenses regardless of whether the proposed ETC Merger is completed. Similarly, current and prospective employees of Williams and its affiliates that provide services to us may experience uncertainty about their future roles following the proposed ETC Merger, which may materially adversely affect Williams’ ability to attract and retain such key personnel during the pendency of the proposed ETC Merger. If Energy Transfer and Williams fail to complete the proposed ETC Merger, it may be difficult and expensive for Williams to recruit and hire replacements for departed employees. The proposed ETC Merger, its effects and related matters may also distract the Williams employees that provide services to us from day-to-day operations and require substantial commitments of time and resources. Moreover, the proposed ETC Merger may disrupt our business by causing uncertainty among our suppliers, customers and investors. In addition, due to operating covenants in the Merger Agreement, we may be unable, during the pendency of the proposed ETC Merger, to pursue certain strategic transactions, undertake certain significant capital projects, undertake certain significant financing transactions and otherwise pursue other actions that are not in the ordinary course of business. Such risks relating to vendors, customers, employees and those risks arising from operating covenants in the Merger Agreement will also apply to varying degrees our affiliates and thereby have a corresponding impact on us.

Risks Related to Strategy and Financing

Restrictions in our debt agreements and the amount of our indebtedness may affect our future financial and operating flexibility.

Our total outstanding long-term debt, as of December 31, 2015, was $693.4 million.

The agreements governing our indebtedness contain covenants that restrict our ability to incur certain liens to support indebtedness and our ability to merge or consolidate or sell all or substantially all of our assets. In addition, certain of our debt agreements contain various covenants that restrict or limit, among other things, our ability to make certain distributions during the continuation of an event of default and our ability to enter into certain affiliate transactions and certain restrictive agreements and to change the nature of our business. Certain of our debt agreements also contain, and those we enter into in the future may contain, financial covenants and other limitations with which we will need to comply. Williams’ and WPZ’s debt agreements contain similar covenants with respect to such entities and their respective subsidiaries, including us.

Our debt service obligations and the covenants described above could have important consequences. For example, they could, among other things:

• Make it more difficult for us to satisfy our obligations with respect to our indebtedness, which could in turn result in an event of default on such indebtedness;

• Impair our ability to obtain additional financing in the future for working capital, capital expenditures, general limited liability company purposes, or other purposes;

• Diminish our ability to withstand a continued or future downturn in our business or the economy generally;

• Require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, general limited liability company purposes, or other purposes; and

• Limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate, including by limiting our ability to expand or pursue our business activities and by preventing us from engaging in certain transactions that might otherwise be considered beneficial to us.

Our ability to comply with our debt covenants, to repay, extend or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance. Our ability to refinance existing debt obligations or obtain future

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credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to comply with these covenants, meet our debt service obligations, or obtain future credit on favorable terms, or at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital, or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.

Our failure to comply with the covenants in the documents governing our indebtedness could result in events of default, which could render such indebtedness due and payable. We may not have sufficient liquidity to repay our indebtedness in such circumstances. In addition, cross-default or cross-acceleration provisions in our debt agreements could cause a default or acceleration to have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. For more information regarding our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity.”

Our ability to obtain credit in the future could be affected by Williams’ and WPZ’s credit ratings.

Substantially all of Williams’ and WPZ’s operations are conducted through their respective subsidiaries. Each of Williams’ and WPZ’s cash flows are substantially derived from loans, dividends and distributions paid to them by their subsidiaries. Their cash flows are typically utilized to service debt and pay dividends or distributions on their equity, with the balance, if any, reinvested in their respective subsidiaries as loans or contributions to capital. Due to our relationship with each of Williams and WPZ, our ability to obtain credit will be affected by Williams’ and WPZ’s credit ratings. Both Williams and WPZ have recently been downgraded. If Williams or WPZ were to experience a further deterioration in its respective credit standing or financial condition, our access to capital and our ratings could be adversely affected. Any further downgrading of a Williams or WPZ credit rating could result in a downgrading of our credit rating. A downgrading of a Williams or WPZ credit rating could limit our ability to obtain financing in the future upon favorable terms, if at all.

Difficult conditions in the global financial markets and the economy in general could negatively affect our business and results of operations.

Our business may be negatively impacted by adverse economic conditions or future disruptions in the global financial markets. Included among these potential negative impacts are industrial or economic contraction leading to reduced energy demand and lower prices for our products and services and increased difficulty in collecting amounts owed to us by our customers. We have availability under the credit facility, but our ability to borrow under that facility could be impaired if one or more of our lenders fails to honor its contractual obligation to lend to us. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures. In addition, financial markets have periodically been affected by concerns over U.S. fiscal and monetary policies. These concerns, as well as actions taken by the U.S. federal government in response to these concerns, could significantly and adversely impact the global and U.S. economies and financial markets, which could negatively impact us in the manner described above.

A downgrade of our credit ratings, which are determined outside of our control by independent third parties, could impact our liquidity, access to capital, and our costs of doing business.

Our credit ratings have recently been downgraded. Any further downgrade of our credit ratings might increase our cost of borrowing and could require us to provide collateral to our counterparties, negatively impacting our available liquidity. In addition, our ability to access capital markets could be limited by a downgrade of our credit ratings.

Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria such as business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are subject to revision or withdrawal at any time by the ratings agencies.

WPZ can exercise substantial control over our distribution policy and our business and operations and may do so in a manner that is adverse to our interests.

Because we are an indirect wholly-owned subsidiary of WPZ, WPZ exercises substantial control over our business and operations and makes determinations with respect to, among other things, the following:

• Payment of distributions and repayment of advances;

• Decisions on financings and our capital raising activities;

• Mergers or other business combinations; and

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• Acquisition or disposition of assets.

WPZ could decide to increase distributions or advances to our member consistent with existing debt covenants. This could adversely affect our liquidity.

Risks Related to Regulations That Affect Our Industry

Our natural gas transportation and storage operations are subject to regulation by the FERC, which could have an adverse impact on our ability to establish transportation and storage rates that would allow us to recover the full cost of operating our pipeline, including a reasonable rate of return.

In addition to regulation by other federal, state, and local regulatory authorities, under the NGA, our interstate pipeline transportation and storage services and related assets are subject to regulation by the FERC. Federal regulation extends to such matters as:

• Transportation of natural gas in interstate commerce;

• Rates, operating terms, types of services offered to customers, and conditions of service;

• The types of services we may offer to our customers;

• Certification and construction of new interstate pipeline and storage facilities;

• Acquisition, extension, disposition, or abandonment of existing interstate pipelines and storage facilities;

• Accounts and records;

• Depreciation and amortization policies;

• Relationships with affiliated companies who are involved in marketing functions of the natural gas business; and

• Market manipulation in connection with interstate sales, purchases, or transportation of natural gas.

Regulatory or administrative actions in these areas, including successful complaints or protests against our rates, can affect our business in many ways, including by decreasing existing tariff rates or setting future tariff rates to levels such that revenues are inadequate to recover increases in operating costs or to sustain an adequate return on capital investments, decreasing volumes in our pipelines, increasing our costs and otherwise altering the profitability of our business.

The outcome of future rate cases will determine the amount of income taxes that we will be allowed to recover.

In May 2005, the FERC issued a statement of general policy permitting a pipeline to include in its cost-of-service computations an income tax allowance provided that an entity or individual has an actual or potential income tax liability on income from the pipeline’s public utility assets. The extent to which owners of pipelines have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis in rate cases where the amounts of the allowances will be established.

Risks Related to Employees, Outsourcing of Non-Core Support Activities, and Technology

Institutional knowledge residing with current Williams’ employees nearing retirement eligibility or with former Williams’ employees might not be adequately preserved.

We expect that a significant percentage of Williams’ employees will become eligible for retirement over the next several years. In our business, institutional knowledge resides with employees who have many years of service. As these employees reach retirement age, or their service is no longer available, Williams may not be able to replace them with employees of comparable knowledge and experience. In addition, Williams may not be able to retain or recruit other qualified individuals, and Williams’ efforts at knowledge transfer could be inadequate. If knowledge transfer, recruiting and retention efforts are inadequate, access to significant amounts of internal historical knowledge and expertise could become unavailable to us.

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Our allocation from Williams for costs for its defined benefit pension plans and other postretirement benefit plans are affected by factors beyond our and Williams’ control.

As we have no employees, employees of Williams and its affiliates provide services to us. As a result, we are allocated a portion of Williams’ costs in defined benefit pension plans covering substantially all of Williams’ or its affiliates’ employees providing services to us, as well as a portion of the costs of other postretirement benefit plans covering certain eligible participants providing services to us. The timing and amount of our allocations under the defined benefit pension plans depend upon a number of factors that Williams controls, including changes to pension plan benefits, as well as factors outside of Williams’ control, such as asset returns, interest rates and changes in pension laws. Changes to these and other factors that can significantly increase our allocations could have a significant adverse effect on our financial condition and results of operations.

Risks Related to Weather, Other Natural Phenomena and Business Disruption

Our assets and operations, as well as our customers’ assets and operations, can be affected by weather and other natural phenomena.

Our assets and operations and our customers’ assets and operations can be adversely affected by hurricanes, floods, earthquakes, landslides, tornadoes and other natural phenomena and weather conditions, including extreme or unseasonable temperatures, making it more difficult for us to realize the historic rates of return associated with our assets and operations. A significant disruption in our or our customers’ operations or the occurrence of a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations, and financial condition.

Acts of terrorism could have a material adverse effect on our financial condition, results of operations and cash flows.

Given the volatile nature of the commodities we transport and store, our assets and the assets of our customers and others in our industry may be targets of terrorist activities. A terrorist attack could create significant price volatility, disrupt our business, limit our access to capital markets, or cause significant harm to our operations, such as full or partial disruption to our ability to transport natural gas. Acts of terrorism, as well as events occurring in response to or in connection with acts of terrorism, could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our financial condition, results of operations, and cash flows.

Our business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions.

We rely on our information technology infrastructure to process, transmit and store electronic information, including information we use to safely operate our assets. While we believe that we maintain appropriate information security policies and protocols, we face cybersecurity and other security threats to our information technology infrastructure, which could include threats to our operational industrial control systems and safety systems that operate our pipelines, plants and assets. We could face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists,” or private individuals. The age, operating systems or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cybersecurity threats. We could also face attempts to gain access to information related to our assets through attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations or information.

Breaches in our information technology infrastructure or physical facilities, or other disruptions including those arising from theft, vandalism, fraud, or unethical conduct, could result in damage to our assets, unnecessary waste, safety incidents, damage to the environment, reputational damage, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position and results of operations.

Item 1B. UNRESOLVED STAFF COMMENTS

None.

Item 2. PROPERTIES

Our gas pipeline facilities are generally owned in fee. However, a substantial portion of such facilities is constructed and maintained on and across properties owned by others pursuant to rights-of-way, easements, permits, licenses or consents. Our compressor stations, with associated facilities, are located in whole or in part upon lands owned by us and upon sites held under leases or permits issued or approved by public authorities. Land owned by others, but used by us under rights-of-way, easements, permits, leases, licenses, or consents, includes land owned by private parties, federal, state, and local governments, quasi-

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governmental agencies, or Native American tribes. The Plymouth LNG facility is located on lands owned in fee simple by us. Various credit arrangements restrict the sale or disposal of a major portion of our pipeline system. We lease our company offices in Salt Lake City, Utah.

Item 3. LEGAL PROCEEDINGS

The information called for by this item is provided in “Item 8. Financial Statements and Supplementary Data – Notes to Financial Statements: Note 3. Contingent Liabilities and Commitments.”

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

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

At December 31, 2015, we were indirectly owned by Williams Partners L.P., and Williams held an approximate 60 percent interest in Williams Partners L.P., comprised of an approximate 58 percent limited partner interest and all of WPZ’s 2 percent general partner interest.

We paid $168.0 million and $234.0 million in cash distributions during 2015 and 2014, respectively.

Item 6. SELECTED FINANCIAL DATA

Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K, this information is omitted.

Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

GENERAL

The following discussion of critical accounting estimates, results of operations, and capital resources and liquidity should be read in conjunction with the financial statements and notes thereto included within “Part II, Item 8” of this report.

CRITICAL ACCOUNTING ESTIMATES

Our financial statements reflect the selection and application of accounting policies that require management to make significant estimates and assumptions. We believe that the following are the most critical judgment areas in the application of accounting policies that currently affect our financial condition and results of operations.

Regulatory Accounting

We are regulated by the FERC. The Accounting Standards Codification Topic 980, Regulated Operations (Topic 980) provides that rate-regulated public utilities account for and report regulatory assets and liabilities consistent with the economic effect of the way in which regulators establish rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Accounting for businesses that are regulated and apply the provisions of Topic 980 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset retirement obligations and other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, our management has determined that it is appropriate to apply the accounting prescribed by Topic 980 and, accordingly, the accompanying financial statements include the effects of the types

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of transactions described above that result from regulatory accounting requirements. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Balance Sheet and included in the Statement of Comprehensive Income for the period in which the discontinuance of regulatory accounting treatment occurs, unless otherwise required to be recorded under other provisions of accounting principles generally accepted in the United States. The aggregate amounts of regulatory assets reflected in the Balance Sheet are $45.1 million and $53.2 million at December 31, 2015 and 2014, respectively. The aggregate amounts of regulatory liabilities reflected in the Balance Sheet are $26.8 million and $27.4 million at December 31, 2015 and 2014, respectively. A summary of regulatory assets and liabilities is included in Note 9 of Notes to Financial Statements.

RESULTS OF OPERATIONS

Analysis of Financial Results

This analysis discusses financial results of our operations for the years 2015 and 2014. Variances due to changes in natural gas prices and transportation volumes have little impact on revenues, because under our rate design methodology, the majority of overall cost of service is recovered through firm capacity reservation charges in our transportation rates.

Our operating revenues increased $2.9 million, or 1 percent, in 2015 as compared with 2014. This increase is primarily associated with higher commodity transportation revenues, due to an increase in off-system deliveries in 2015. Transportation service and gas storage service accounted for 98 percent and 2 percent, respectively, of our operating revenues for both 2015 and 2014.

Total operating expenses decreased $3.4 million, or 1 percent, in 2015 as compared with 2014. Decreases in contractual and other services and supplies of $2.1 million, resulting primarily from decreased pipeline maintenance and repairs, and charges from affiliates of $5.2 million were offset by increases in labor related expenses of $2.2 million and depreciation of $1.4 million, resulting primarily from property additions.

The increase in our net income is primarily due to the factors noted above.

Effects of Inflation

We generally have experienced increased costs due to the effect of inflation on the cost of labor, materials and supplies, and property, plant, and equipment. A portion of the increased labor and materials and supplies cost can directly affect income through increased operation and maintenance expenses. The cumulative impact of inflation over a number of years has resulted in increased costs for current replacement of productive facilities. The majority of our property, plant, and equipment and materials and supplies inventory is subject to ratemaking treatment, and under current FERC practices, recovery is limited to historical costs. We believe that we will be allowed to recover and earn a return based on increased actual costs incurred when existing facilities are replaced. Cost-based regulation along with competition and other market factors limit our ability to price services or products based upon inflation’s effect on costs.

CAPITAL RESOURCES AND LIQUIDITY

Method of Financing

We fund our capital requirements with cash flows from operating activities, equity contributions from WPZ, collection of advances made to WPZ, accessing capital markets, and, if required, borrowings under the credit facility and advances from WPZ.

We may raise capital through private debt offerings, as well as offerings registered pursuant to offering-specific registration statements. Interest rates, market conditions, and industry conditions will affect future amounts raised, if any, in the capital markets. We anticipate that we will be able to access public and private debt markets on terms commensurate with our credit ratings to finance our capital requirements, when needed.

We, along with WPZ and Transcontinental Gas Pipe Line Company, LLC (Transco), are co-borrowers under a $3.5 billion unsecured credit facility. Total letter of credit capacity available to WPZ under the credit facility is $1.125 billion. We may borrow up to $500 million under the credit facility to the extent not otherwise utilized by WPZ and Transco.

We are a participant in WPZ’s cash management program, and we make advances to and receive advances from WPZ. At December 31, 2015, our advances to WPZ totaled approximately $171.9 million. These advances are represented by demand notes.

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Please see “Item 8. Financial Statements and Supplementary Data – Notes to Financial Statements: Note 4. Debt, Financing Arrangements, and Leases – Credit Facility and Note 7. Transactions with Major Customers and Affiliates – Related Party Transactions.”

Capital Expenditures

We categorize our capital expenditures as either maintenance capital expenditures or expansion capital expenditures. Maintenance capital expenditures are those expenditures required to maintain the existing operating capacity and service capability of our assets, including replacement of system components and equipment that are worn, obsolete, completing their useful life, or necessary to remain in compliance with environmental laws and regulations. Expansion capital expenditures improve the service capability of the existing assets, extend useful lives, increase transmission or storage capacities from existing levels, reduce costs, or enhance revenues. We anticipate 2016 capital expenditures will be approximately $83 million. Of this total, approximately $16 million is considered nondiscretionary due to legal, regulatory, and/or contractual requirements. In 2016, we expect to fund our capital expenditures with cash from operations.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

Our interest rate risk exposure is limited to our long-term debt. All of our interest on long-term debt is fixed in nature, except the interest on our revolver borrowings, as shown on the following table (in thousands of dollars):

	December 31, 2015
Fixed rates on long-term debt:
5.95% senior unsecured notes due 2017	$	185,000
6.05% senior unsecured notes due 2018	250,000
7.00% senior unsecured notes due 2016	175,000
7.125% unsecured debentures due 2025	85,000
	695,000
Unamortized debt issuance costs	(1,197		)
Unamortized debt discount	(383		)
Total long-term debt	$	693,420

Our total long-term debt at December 31, 2015 had a carrying value of $693.4 million and a fair market value of $721.9 million. As of December 31, 2015, the weighted-average interest rate on our long-term debt was 6.4 percent.

19

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	21
Statement of Comprehensive Income	22
Balance Sheet	23
Statement of Owner's Equity	25
Statement of Cash Flows	26
Notes to Financial Statements	27

20

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Management Committee of

Northwest Pipeline LLC

We have audited the accompanying balance sheet of Northwest Pipeline LLC as of December 31, 2015 and 2014, and the related statements of comprehensive income, owner’s equity, and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes 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. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Northwest Pipeline LLC at December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Houston, Texas

February 24, 2016

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NORTHWEST PIPELINE LLC

STATEMENT OF COMPREHENSIVE INCOME

(Thousands of Dollars)

	Years Ended December 31,
	2015			2014			2013
OPERATING REVENUES	$	472,994		$	470,050		$	469,661
OPERATING EXPENSES:
General and administrative	57,105			62,085			62,473
Operation and maintenance	73,128			74,191			75,342
Depreciation	100,554			99,138			96,109
Regulatory debits	2,550			1,487			921
Taxes, other than income taxes	17,151			16,987			16,882
Total operating expenses	250,488			253,888			251,727
OPERATING INCOME	222,506			216,162			217,934
OTHER (INCOME) AND OTHER EXPENSES:
Interest expense	46,024			46,095			46,177
Allowance for equity and borrowed funds used during construction	(1,619		)	(573		)	(1,405		)
Miscellaneous other (income) expenses, net	(595		)	87			175
Total other (income) and other expenses	43,810			45,609			44,947
NET INCOME	178,696			170,553			172,987
CASH FLOW HEDGES:
Amortization of cash flow hedges into Interest expense	(62		)	(62		)	(62		)
COMPREHENSIVE INCOME	$	178,634		$	170,491		$	172,925

See accompanying notes.

22

NORTHWEST PIPELINE LLC

BALANCE SHEET

(Thousands of Dollars)

	December 31, 2015		December 31, 2014
ASSETS
CURRENT ASSETS:
Cash	$	169	$	154
Receivables:
Trade	42,669		42,759
Affiliated companies	1,441		2,039
Advances to affiliate	171,867		135,054
Other	14,051		1,249
Materials and supplies	10,183		10,066
Exchange gas due from others	3,733		4,184
Exchange gas offset	201		—
Prepayments and other	6,164		4,881
Total current assets	250,478		200,386
PROPERTY, PLANT AND EQUIPMENT, at cost	3,306,205		3,269,617
Less-Accumulated depreciation	1,367,632		1,288,530
Total property, plant and equipment, net	1,938,573		1,981,087
OTHER ASSETS:
Deferred charges	2,110		2,768
Regulatory assets	40,853		49,923
Total other assets	42,963		52,691
Total assets	$	2,232,014	$	2,234,164

See accompanying notes.

23

NORTHWEST PIPELINE LLC

BALANCE SHEET

(Thousands of Dollars)

	December 31, 2015		December 31, 2014
LIABILITIES AND OWNER’S EQUITY
CURRENT LIABILITIES:
Payables:
Trade	$	14,363	$	12,709
Affiliated companies	11,959		13,143
Accrued liabilities:
Taxes, other than income taxes	11,033		11,246
Interest	4,045		4,045
Exchange gas due to others	2,252		6,406
Exchange gas offset	—		3,941
Customer advances	5,573		2,363
Other	3,417		1,799
Long-term debt due within one year	174,837		—
Total current liabilities	227,479		55,652
LONG-TERM DEBT	518,583		692,488
OTHER NONCURRENT LIABILITIES:
Asset retirement obligations	82,454		94,678
Regulatory liabilities	26,802		23,375
Other	6,108		8,017
Total other noncurrent liabilities	115,364		126,070
CONTINGENT LIABILITIES AND COMMITMENTS (Note 3)
OWNER’S EQUITY:
Owner’s capital	1,073,892		1,073,892
Retained earnings	296,668		285,972
Accumulated other comprehensive income	28		90
Total owner’s equity	1,370,588		1,359,954
Total liabilities and owner’s equity	$	2,232,014	$	2,234,164

See accompanying notes.

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NORTHWEST PIPELINE LLC

STATEMENT OF OWNER’S EQUITY

(Thousands of Dollars)

	Years Ended December 31,
	2015			2014			2013
Owner’s capital:
Balance at beginning of period	$	1,073,892		$	1,073,892		$	1,060,592
Capital contributions from parent	—			—			13,300
Balance at end of period	1,073,892			1,073,892			1,073,892
Retained earnings:
Balance at beginning of period	285,972			349,419			267,432
Net income	178,696			170,553			172,987
Cash distributions to parent	(168,000		)	(234,000		)	(91,000		)
Balance at end of period	296,668			285,972			349,419
Accumulated other comprehensive income (loss):
Balance at beginning of period	90			152			214
Cash flow hedges:
Reclassification of unrecognized gain into earnings	(62		)	(62		)	(62		)
Balance at end of period	28			90			152
Total owner’s equity	$	1,370,588		$	1,359,954		$	1,423,463

See accompanying notes.

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NORTHWEST PIPELINE LLC

STATEMENT OF CASH FLOWS

(Thousands of Dollars)

	Years Ended December 31,
	2015			2014			2013
OPERATING ACTIVITIES:
Net income	$	178,696		$	170,553		$	172,987
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation	100,554			99,138			96,109
Regulatory debits	2,550			1,487			921
Gain on sale of property, plant and equipment	—			(70		)	—
Amortization of deferred charges and credits	762			894			1,720
Allowance for equity funds used during construction	(1,099		)	(391		)	(945		)
Changes in current assets and liabilities:
Trade and other accounts receivable	(137		)	395			2,133
Affiliated receivables	598			38,388			(38,744		)
Exchange gas due from others	7,349			(1,433		)	153
Materials and supplies	(117		)	203			(132		)
Other current assets	(1,283		)	(1,326		)	(202		)
Trade accounts payable	158			(4,958		)	(212		)
Affiliated payables	(1,184		)	2,007			224
Exchange gas due to others	(8,095		)	2,179			(153		)
Other accrued liabilities	5,410			(3,095		)	3,885
Changes in noncurrent assets and liabilities:
Deferred charges	(2,633		)	(2,087		)	(7,448		)
Noncurrent liabilities	9,164			11,000			9,819
Net cash provided by operating activities	290,693			312,884			240,115
FINANCING ACTIVITIES:
Capital contributions from parent	—			—			13,300
Cash distributions to parent	(168,000		)	(234,000		)	(91,000		)
Other	—			(622		)	(1,318		)
Net cash used in financing activities	(168,000		)	(234,622		)	(79,018		)
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures, net of equity AFUDC*	(86,289		)	(79,413		)	(83,317		)
Contributions and advances for construction costs	1,499			3,056			6,326
Disposal of property, plant and equipment, net	(1,075		)	5,728			5,756
Advances to affiliates, net	(36,813		)	(15,886		)	(89,846		)
Proceeds from insurance	—			8,274			—
Net cash used in investing activities	(122,678		)	(78,241		)	(161,081		)
NET INCREASE IN CASH	15			21			16
CASH AT BEGINNING OF PERIOD	154			133			117
CASH AT END OF PERIOD	$	169		$	154		$	133
____________________________________
* Increases to property, plant and equipment	$	(73,931	)	$	(71,207	)	$	(88,123	)
Changes in related accounts receivable, accounts payable and accrued liabilities	(12,358		)	(8,206		)	4,806
Capital expenditures, net of equity AFUDC	$	(86,289	)	$	(79,413	)	$	(83,317	)

See accompanying notes.

26

NORTHWEST PIPELINE LLC

NOTES TO FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure and Control

Northwest Pipeline LLC (Northwest) is indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). On February 2, 2015, WPZ was merged into Access Midstream Partners, L.P. (ACMP), another publicly traded limited partnership consolidated by Williams. ACMP was the surviving partnership and was subsequently renamed WPZ. At December 31, 2015, Williams holds an approximate 60 percent interest in WPZ, comprised of an approximate 58 percent limited partner interest and all of the 2 percent general partner interest.

Northwest has no employees. Services are provided to Northwest by Williams and its affiliates. Northwest reimburses Williams and its affiliates for the costs of the employees including compensation and employee benefit plan costs and all related administrative costs.

In this report, Northwest is at times referred to in the first person as “we,” “us” or “our.”

On September 28, 2015, Williams publicly announced in a press release that it had entered into an Agreement and Plan of Merger (Merger Agreement) with Energy Transfer Equity, L.P. (Energy Transfer) and certain of its affiliates. The Merger Agreement provides that, subject to the satisfaction of customary closing conditions, Williams will be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger) with ETC surviving the ETC Merger. Energy Transfer formed ETC as a limited partnership that will be treated as a corporation for U.S. federal income tax purposes. Immediately following the completion of the ETC Merger, ETC will contribute to Energy Transfer all of the assets and liabilities of Williams in exchange for the issuance by Energy Transfer to ETC of a number of Energy Transfer Class E common units equal to the number of ETC common shares issued to Williams stockholders in the ETC Merger. WPZ expects to retain its current name and remain a publicly traded limited partnership following the ETC Merger.

Nature of Operations

We own and operate an interstate pipeline system for the mainline transmission of natural gas. This system extends from the San Juan Basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on the Canadian border near Sumas, Washington.

Regulatory Accounting

Our natural gas pipeline operations are regulated by the Federal Energy Regulatory Commission (FERC). FERC regulatory policies govern the rates that each pipeline is permitted to charge customers for interstate transportation and storage of natural gas.

The Accounting Standards Codification (ASC) Regulated Operations (Topic 980) provides that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying Topic 980, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to customers in future periods. The accompanying financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. (See Note 9 for further discussion.)

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) litigation-related contingencies; 2) environmental remediation obligations; 3) impairment assessments of long-lived assets; 4) depreciation; and 5) asset retirement obligations.

Revenue Recognition

Our revenues are primarily from services pursuant to long term firm transportation and storage agreements. These agreements provide for a reservation charge based on the volume of contracted capacity and a volumetric charge based on the volume of gas delivered, both at rates specified in our FERC tariffs. We recognize revenues for reservation charges ratably over the contract

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NOTES TO FINANCIAL STATEMENTS

period regardless of the volume of natural gas that is transported or stored. Revenues for volumetric charges, from both firm and interruptible transportation services and storage injection and withdrawal services, are recognized based on volumes of natural gas scheduled for delivery at the agreed upon delivery point or based on volumes of natural gas scheduled for injection or withdrawal from the storage facility.

In the course of providing transportation services to our customers, we may receive or deliver different quantities of gas from shippers than the quantities delivered or received on behalf of those shippers. These transactions result in imbalances, which are typically settled through the receipt or delivery of gas in the future. Customer imbalances to be repaid or recovered in-kind are recorded as exchange gas due from others or due to others in the accompanying balance sheets. The difference between exchange gas due to us from customers and the exchange gas that we owe to customers is included in the exchange gas offset. These imbalances are valued at the average of the spot market rates at the Canadian border and the Rocky Mountain market as published in the SNL Financial “Bidweek Index - Spot Rates.” Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions.

As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and third-party regulatory proceedings, advice of counsel and other risks. At December 31, 2015, we had no such rate refund liabilities.

Environmental Matters

We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their future economic benefit and potential for rate recovery. We believe that expenditures required to meet applicable environmental laws and regulations are prudently incurred in the ordinary course of business and such expenditures would be permitted to be recovered through rates.

Property, Plant, and Equipment

Property, plant and equipment (plant), consisting principally of natural gas transmission facilities, is recorded at original cost. The FERC identifies installation, construction and replacement costs that are to be capitalized and included in our asset base for recovery in rates. Routine maintenance, repairs, and renewal costs are charged to income as incurred. Gains or losses from the ordinary sale or retirement of plant are charged or credited to accumulated depreciation; certain other gains or losses are recorded in operating income.

We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2015, 2014, and 2013 are as follows:

Category of Property
Storage Facilities	1.60	%	—	2.76%
Transmission Facilities	2.80	%	—	6.97%

The incrementally priced Evergreen Expansion Project, which was an expansion of our pipeline system, was placed in service on October 1, 2003. The levelized rate design of this project creates a consistent revenue stream over the related 25-year and 15-year customer contract terms. The related levelized depreciation is lower than book depreciation in the early years and higher than book depreciation in the later years of the contract terms. The depreciation component of the levelized incremental rates will equal the accumulated book depreciation by the end of the primary contract terms. The FERC has approved the accounting for the differences between book depreciation and the Evergreen Expansion Project’s levelized depreciation as a regulatory asset.

We recorded regulatory debits totaling $2.6 million in 2015, $1.5 million in 2014, and $0.9 million in 2013 in the accompanying Statement of Comprehensive Income. These debits relate primarily to the levelized depreciation adjustment for the Evergreen Project discussed above.

We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. Measurement of AROs includes, as a component of future expected costs, an estimate of the price that a third party would demand, and could

28

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NOTES TO FINANCIAL STATEMENTS

expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as market-risk premium. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and is offset by a regulatory asset. The gross regulatory asset balances associated with ARO as of December 31, 2015 and 2014 were $70.9 million and $63.7 million, respectively. The regulatory asset is expected to be fully recovered through the net negative salvage component of depreciation included in our rates; as such, the negative salvage component of accumulated depreciation ($69.3 million and $60.2 million at December 31, 2015 and 2014, respectively) has been reclassified and netted against the amount of the ARO regulatory asset.

Impairment of Long-Lived Assets

We evaluate long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When such a determination has been made, our management’s estimate of undiscounted future cash flows attributable to the assets is compared to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, the amount of the impairment recognized in the financial statements is determined by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements.

Allowance for Funds Used During Construction

Allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in process of construction and is included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. The FERC has prescribed a formula to be used in computing separate allowances for debt and equity AFUDC. The cost of debt portion of AFUDC was $0.5 million for 2015, $0.2 million for 2014, and $0.5 million for 2013. The equity funds portion of AFUDC was $1.1 million, $0.4 million, and $0.9 million for 2015, 2014, and 2013, respectively. Both are reflected in Other (Income) and Other Expenses.

Income Taxes

We generally are not a taxable entity for federal or state and local income tax purposes. The tax on net income is generally borne by unitholders of our ultimate parent, WPZ. Net income for financial statement purposes may differ significantly from taxable income of WPZ’s unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the WPZ partnership agreement. The aggregated difference in the basis of our assets for financial and tax reporting purposes cannot be readily determined because information regarding each of WPZ’s unitholder’s tax attributes in WPZ is not available to us.

Accounts Receivable and Allowance for Doubtful Receivables

Accounts receivable are stated at the historical carrying amount net of reserves or write-offs. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers’ financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables. Receivables determined to be uncollectible are reserved or written off in the period of such determination.

Materials and Supplies Inventory

All inventories are stated at lower of cost or market. We determine the cost of the inventories using the average cost method.

We perform an annual review of materials and supplies inventories, including an analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 2015 and 2014.

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NORTHWEST PIPELINE LLC

NOTES TO FINANCIAL STATEMENTS

Deferred Charges

We amortize deferred charges over varying periods consistent with the FERC approved accounting treatment and recovery for such deferred items. Unamortized debt expense, debt discount and losses on reacquired long-term debt are amortized by the bonds outstanding method over the related debt repayment periods.

Pension and Other Postretirement Benefits

We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 5 for further discussion.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us, and thus paid by us, is based on our share of net periodic benefit cost.

Contingent Liabilities

We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third-parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.

Cash Flows from Operating Activities and Cash Equivalents

We use the indirect method to report cash flows from operating activities, which requires adjustments to net income to reconcile to net cash flows provided by operating activities. We include short-term, highly-liquid investments that have an original maturity of three months or less as cash equivalents.

Interest Payments

Cash payments for interest, net of interest capitalized, were $45.3 million in 2015, $44.5 million in 2014, and $44.6 million in 2013.

Accounting Standards Issued But Not Yet Adopted

In January 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-01 “Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01). ASU 2016-01 addresses certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. The new standard is effective for interim and annual periods beginning after December 15, 2017. Early adoption is only permitted for certain applications. We are evaluating the impact of the new standard on our consolidated financial statements and our timing for adoption.

In July 2015, the FASB issued ASU 2015-11 "Simplifying the Measurement of Inventory" (ASU 2015-11). ASU 2015-11 simplifies the guidance on the subsequent measurement of inventory, excluding inventory measured using last in, first out or the retail inventory method. Under the new standard, in scope inventory should be measured at the lower of cost and net realizable value. The new standard is effective for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We measure inventory at the lower of cost or market; upon adoption, we will measure inventory at the lower of cost and net realizable value. We do not expect the new standard will have a material impact on the value of inventory reported in our financial statements.

In February 2015, the FASB issued ASU 2015-02 "Amendments to the Consolidation Analysis"(ASU 2015-02). ASU 2015-02 alters the models used to determine consolidation conclusions for certain entities, including limited partnerships, and may require additional disclosures. The standard is effective for financial statements issued for interim and annual reporting periods beginning after December 15, 2015, with either retrospective or modified retrospective presentation allowed. We do not expect the new standard will have a significant impact on our financial statements.

In May 2014, the FASB issued ASU 2014-09 establishing ASC Topic 606, "Revenue from Contracts with Customers" (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services

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NOTES TO FINANCIAL STATEMENTS

to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date" (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016. We continue to evaluate both the impact of this new standard on our financial statements and the transition method we will utilize for adoption.

2. RATE AND REGULATORY MATTERS

Rates

Our rates became effective January 1, 2013, and will remain in effect for 5 years.

3. CONTINGENT LIABILITIES AND COMMITMENTS

Environmental Matters

We are subject to the National Environmental Policy Act and other federal and state legislation regulating the environmental aspects of our business. Except as discussed below, our management believes that we are in substantial compliance with existing environmental requirements. Environmental expenditures are expensed or capitalized depending on their future economic benefit and potential for rate recovery. We believe that, with respect to any expenditures required to meet applicable standards and regulations, the FERC would grant the requisite rate relief so that substantially all of such expenditures would be permitted to be recovered through rates. As a result, we believe that compliance with applicable environmental requirements is not likely to have a material adverse effect upon our financial position or results of operations.

Beginning in the mid-1980s, we evaluated many of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation might be necessary. We identified polychlorinated biphenyl (PCB) contamination in air compressor systems, soils and related properties at certain compressor station sites. Similarly, we identified hydrocarbon impacts at these facilities due to the former use of earthen pits, lubricating oil leaks or spills, and excess pipe coating released to the environment. In addition, heavy metals have been identified at these sites due to the former use of mercury containing meters and paint and welding rods containing lead, cadmium, and arsenic. The PCBs were remediated pursuant to a Consent Decree with the U.S. Environmental Protection Agency (EPA) in the late 1980s, and we conducted a voluntary clean-up of the hydrocarbon and mercury impacts in the early 1990s. In 2005, the Washington Department of Ecology required us to re-evaluate our previous clean-ups in Washington. During 2006 to 2014, 143 meter stations were evaluated, of which 80 required remediation. As of December 31, 2015, all but one meter station has been remediated. Initial assessments have been completed at all thirteen compressor stations in Washington. Additional assessments are ongoing at three of these compressor stations. Remediation has been completed at nine of the thirteen compressor stations. On the basis of the findings to date, we estimate that environmental assessment and remediation costs will total approximately $4.6 million, measured on an undiscounted basis, and are expected to be incurred through 2019. At December 31, 2015 and 2014, we had accrued liabilities totaling approximately $4.6 million and $7.8 million, respectively, for these costs. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs.

In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. In May 2012, the EPA completed designation of new eight-hour ozone non-attainment areas. Based on the published designations, no Northwest facilities are located within the non-attainment areas. At this time, it is unknown whether future state regulatory actions associated with implementation of the 2008 ozone standard will impact our operations and increase the cost of additions to property, plant and equipment. Until any additional state regulatory actions are proposed, we are unable to estimate the cost of additions that may be required to meet any such new regulation.

In December 2014, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels. The EPA is anticipated to finalize any revisions in late 2015. Revisions to the ozone NAAQS will result in additional federal and state regulatory actions that may impact our operations. As a result, the cost of additions to property, plant, and equipment is expected to increase. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet new regulations.

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NOTES TO FINANCIAL STATEMENTS

On January 22, 2010, the EPA set a new one-hour nitrogen dioxide (NO2) NAAQS. The effective date of the new NO2 standard was April 12, 2010. On January 20, 2012, the EPA determined pursuant to available information that no area in the country is violating the 2010 NO2 NAAQS, and thus, designated all areas of the country as “unclassifiable/attainment.” Also, at that time, the EPA noted its plan to deploy an expanded NO2 monitoring network beginning in 2013. However, on October 5, 2012, the EPA proposed a graduated implementation of the monitoring network between January 1, 2014 and January 1, 2017. Once three years of data is collected from the new monitoring network, the EPA will reassess attainment status with the one-hour NO2 NAAQS. Until that time, the EPA or states may require ambient air quality modeling on a case by case basis to demonstrate compliance with the NO2 standard. Because we are unable to predict the outcome of the EPA’s or states’ future assessment using the new monitoring network, we are unable to estimate the cost of additions that may be required to meet this regulation.

Other Matters

Various other proceedings are pending against us and are considered incidental to our operations.

Summary

We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities are immaterial to our expected future annual results of operations, liquidity and financial position. These calculations have been made without consideration of any potential recovery from third-parties. We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss.

4. DEBT, FINANCING ARRANGEMENTS, AND LEASES

Long-Term Debt

Long-term debt, presented net of unamortized discount and unamortized debt issuance costs, consists of the following:

	December 31,
	2015			2014
	(Thousands of Dollars)
5.95% senior unsecured notes due 2017	$	185,000		$	185,000
6.05% senior unsecured notes due 2018	250,000			250,000
7% senior unsecured notes due 2016	175,000			175,000
7.125% unsecured debentures due 2025	85,000			85,000
Debt issuance costs	(1,197		)	(1,932		)
Unamortized debt discount	(383		)	(580		)
Total long-term debt, including current portion	$	693,420		$	692,488
Long-term debt due within one year	174,837			—
Total long-term debt	518,583			692,488

As of December 31, 2015, cumulative maturities of outstanding long-term debt (at face value) for the next five years are as follows:

	(Thousands of Dollars)
2016: 7% senior unsecured notes	$	175,000
2017: 5.95% senior unsecured notes	185,000
2018: 6.05% senior unsecured notes	250,000
Total	$	610,000

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NORTHWEST PIPELINE LLC

NOTES TO FINANCIAL STATEMENTS

The long-term debt due within one year at December 31, 2015 is associated with our $175 million7% senior unsecured notes that mature on June 15, 2016.

In 2006, we entered into certain forward starting interest rate swaps prior to our issuance of the 7% senior unsecured notes due 2016 to hedge the variability of forecasted interest payments arising from changes in interest rates prior to the issuance of this debt. The settlement resulted in a gain, recorded in Accumulated other comprehensive income, that is being amortized to reduce interest expense over the life of the related debt.

Restrictive Debt Covenants

At December 31, 2015, none of our debt instruments restrict the amount of distributions to our parent. Our debt agreements contain restrictions on our ability to incur secured debt beyond certain levels.

Credit Facility

On February 2, 2015, we, along with WPZ, Transco, the lenders named therein, and an administrative agent, entered into the Second Amended and Restated Credit Agreement with aggregate commitments available of $3.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. The maturity date of the facility is February 2, 2020. However, the co-borrowers may request up to two extensions of the maturity date, each for an additional one-year period, to allow a maturity date as late as February 2, 2022, under certain circumstances. The agreement allows for swing line loans up to an aggregate amount of $150 million, subject to available capacity under the credit facility, and letters of credit commitments available to WPZ of $1.125 billion. We are able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers. At December 31, 2015, no letters of credit were issued and $1.31 billion of loans to WPZ were outstanding under the credit facility. On December 18, 2015, we, along with WPZ, Transco, the lenders named therein, and an administrative agent, entered into the Amendment No. 1 to Second Amended and Restated Credit Agreement modifying the thresholds specified in the covenant related to the maximum ratio of WPZ’s consolidated indebtedness to consolidated EBITDA.

Under the credit facility, WPZ is required to maintain a ratio of debt to EBITDA (each as defined in the credit facility) that must be no greater than 5.75 to 1.0 for the quarters ending December 31, 2015, March 31, 2016, and June 30, 2016. The ratio must be no greater than 5.5 to 1.0 for the quarters ending September 30, 2016 and December 31, 2016. The ratio must be no greater than 5.0 to 1.0 for the quarter ending March 31, 2017 and each subsequent fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions have been executed, in which case the ratio must be no greater than 5.50 to 1.0. For us, the ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent. Measured as of December 31, 2015, we are in compliance with this financial covenant.

Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, a borrower’s ability to merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, enter into certain restrictive agreements, and allow any material change in the nature of its business.

If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments for the respective borrowers and accelerate the maturity of any loans of the defaulting borrower under the credit facility agreement and exercise other rights and remedies.

Other than swingline loans, each time funds are borrowed, the borrower must choose whether such borrowing will be an alternate base rate borrowing or a Eurodollar borrowing. If such borrowing is an alternate base rate borrowing, interest is calculated on the basis of the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 1/2 of 1 percent, and (c) a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus 1 percent, plus, in the case of each of (a), (b), and (c), an applicable margin. If the borrowing is a Eurodollar borrowing, interest is calculated on the basis of LIBOR for the relevant period plus an applicable margin. Interest on swingline loans is calculated as the sum of the alternate base rate plus an applicable margin. The borrower is required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings.

WPZ participates in a commercial paper program, and WPZ management considers amounts outstanding under this program to be a reduction of available capacity under the credit facility. On February 2, 2015, WPZ amended and restated the commercial paper program for the WPZ/ACMP merger and to allow a maximum outstanding of $3 billion. At December 31, 2015, WPZ had $499 million in outstanding commercial paper.

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NORTHWEST PIPELINE LLC

NOTES TO FINANCIAL STATEMENTS

Accounting Standards Issued and Adopted

In April 2015, the FASB issued ASU 2015-03 “Interest - Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03). ASU 2015-03 simplifies the presentation of debt issuance costs by requiring such costs be presented as a deduction from the corresponding debt liability. Subsequently, in August 2015, the FASB issued ASU 2015-15 “Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangement-Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting” (ASU 2015-15). In ASU 2015-15, the FASB stated that the guidance in ASU 2015-03 did not address the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, and entities are permitted to defer and present debt issuance costs related to line-of-credit arrangements as assets. The standards are effective for financial statements issued for interim and annual reporting periods beginning after December 15, 2015, and require retrospective presentation. Early adoption is permitted. We elected to early adopt these standards for the periods presented. Accordingly, $1.2 million and $1.9 million of debt issuance costs as of December 31, 2015 and 2014, respectively, are now reflected as a direct reduction of debt in our Balance Sheet.

Leases

Our leasing arrangements include mostly premise and equipment leases that are classified as operating leases.

Effective October 1, 2009, we entered into an agreement to lease office space from a third party. The agreement has an initial term of approximately 10 years, with an option to renew for an additional 5 or 10 year term.

Following are the estimated future minimum annual rental payments required under operating leases, which have initial or remaining noncancelable lease terms in excess of one year:

	(Thousands of Dollars)
2016	$	2,561
2017	2,619
2018	2,679
2019	2,740
Total	$	10,599

Operating lease rental expense, net of sublease revenues, amounted to $2.7 million, $2.5 million, and $2.3 million for 2015, 2014, and 2013, respectively.

5. BENEFIT PLANS

Certain of the benefit costs charged to us by Williams associated with employees who directly support us are described below. Additionally, allocated corporate expenses from Williams to us also include amounts related to these same employee benefits, which are not included in the amounts presented below. (See Note 7 for further discussion.)

Pension and Other Postretirement Benefit Plans

Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan, and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible employees. Pension cost charged to us by Williams was $4.4 million in 2015, $4.2 million in 2014, and $7.8 million in 2013.

Williams provides certain retiree health care and life insurance benefits for eligible participants that generally were employed by Williams on or before December 31, 1991. During 2015, 2014, and 2013, we received credits from Williams related to retiree health care and life insurance benefits of $3.4 million, $4.3 million and $1.7 million, respectively. These credits were recorded as regulatory liabilities.

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NORTHWEST PIPELINE LLC

NOTES TO FINANCIAL STATEMENTS

Defined Contribution Plan

Included in compensation expense is $2.2 million for 2015 and $2.0 million for 2014 and 2013 that Williams charged us for matching contributions to this plan.

Employee Stock-Based Compensation Plan Information

The Williams Companies, Inc. 2007 Incentive Plan, as amended and restated on February 23, 2010, (Plan) was approved by stockholders on May 20, 2010. The Plan provides for Williams’ common stock-based awards to both employees and nonmanagement directors. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets achieved.

Williams currently bills us directly for compensation expense related to stock-based compensation awards based on the fair value of the awards. We are also billed for our proportionate share of Williams’ and other affiliates’ stock-based compensation expense through various allocation processes.

Total stock-based compensation expense for the years ended December 31, 2015, 2014 and 2013 was $1.5 million, $1.2 million and $1.2 million, respectively, excluding amounts allocated from WPZ and Williams.

6. FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Cash and advances to affiliate—The carrying amounts approximate fair value, because of the short-term nature of these instruments.

Long-term debt – The disclosed fair value of our long-term debt, which we consider as a level 2 measurement, is determined by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The carrying amount and estimated fair value of our long-term debt, including current maturities, were $693.4 million and $721.9 million, respectively, at December 31, 2015, and $692.5 million and $766.5 million, respectively, at December 31, 2014.

7. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES

Concentration of Off-Balance-Sheet and Other Credit Risk

During the periods presented, more than 10 percent of our operating revenues were generated from each of the following customers:

	Years Ended December 31,
	2015		2014		2013
	(Thousands of Dollars)
Puget Sound Energy, Inc.	$	118,384	$	113,398	$	110,111
Northwest Natural Gas Company	50,857		50,631		51,085
Cascade Natural Gas Corporation	48,363		(a)		(a)

(a) Under 10 percent in 2014 and 2013.

Our major customers are located in the Pacific Northwest. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are regularly evaluated and historical collection losses have been minimal.

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NORTHWEST PIPELINE LLC

NOTES TO FINANCIAL STATEMENTS

Related Party Transactions

We are a participant in WPZ’s cash management program. At December 31, 2015 and 2014, the advances due to us by WPZ totaled approximately $171.9 million and $135.1 million, respectively. These advances are represented by demand notes and are classified as Current Assets in the accompanying Balance Sheet. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on WPZ’s excess cash at the end of each month, which was approximately 0.12 percent at December 31, 2015. The interest income from these advances was minimal during the years ended December 31, 2015, 2014, and 2013. Such interest income is included in Other (Income) and Other Expenses: Miscellaneous other (income) expenses, net on the accompanying Statement of Comprehensive Income.

We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams and its affiliates for all direct and indirect expenses incurred or payments made (including salary, bonus, incentive compensation, and benefits) in connection with these services. Employees of Williams also provide general administrative and management services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three factor formula, which considers revenues; property, plant, and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. We were billed $100.4 million, $102.4 million, and $106.7 million in the years ended December 31, 2015, 2014, and 2013, respectively, for these services. Such expenses are primarily included in General and administrative and Operation and maintenance expenses on the accompanying Statement of Comprehensive Income.

In 2015, 2014, and 2013, we incurred reimbursable costs of $0.6 million, $27.3 million, and $89.8 million, respectively, due from Williams Field Services related to the construction of a natural gas liquids pipeline, of which $0.5 million was outstanding at December 31, 2014 and a minimal amount was outstanding at December 31, 2015.

During 2015, 2014, and 2013, we declared and paid cash distributions to our parent of $168.0 million, $234.0 million, and $91.0 million, respectively. During January 2016, we declared and paid cash distributions of $57.0 million to our parent.

During 2013, we received contributions of $13.3 million from our parent to fund a portion of our expenditures for additions to property, plant, and equipment. No contributions were received in 2015 or 2014.

We have entered into various other transactions with certain related parties, the amounts of which were not significant. These transactions and the above-described transactions are made on the basis of commercial relationships and prevailing market prices or general industry practices.

8. ASSET RETIREMENT OBLIGATIONS

Our accrued asset retirement obligations relate to our gas storage and transmission facilities. At the end of the useful life of our facilities, we are legally obligated to remove certain transmission facilities including underground pipelines, major river spans, compressor stations and meter station facilities. These obligations also include restoration of the property sites after removal of the facilities from above and below the ground.

During 2015 and 2014, our overall asset retirement obligation changed as follows (in thousands):

	2015			2014
Beginning balance	$	94,678		$	60,753
Accretion	6,870			5,602
New obligations	2,721			157
Changes in estimates of existing obligations (1)	(21,815		)	28,171
Property Dispositions & Settlements	—			(5		)
Ending balance	$	82,454		$	94,678

(1) Changes in estimates of existing obligations are primarily due to the annual review process, which considers various factors including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining life of assets. The decrease in 2015 is primarily attributed to decreases in current estimates for removal costs and inflation rate and an increase

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NORTHWEST PIPELINE LLC

NOTES TO FINANCIAL STATEMENTS

in the discount rate. The increase in 2014 is primarily attributed to increases in current estimates for removal costs and inflation rate and a decrease in the discount rate.

9. REGULATORY ASSETS AND LIABILITIES

Our regulatory assets and liabilities result from our application of the provisions of Topic 980 and are reflected on our balance sheet. Current regulatory assets are included in Exchange gas offset and Prepayments and other. Current regulatory liabilities are included in Exchange gas offset. These balances are presented on our balance sheet on a gross basis and are recoverable or refundable over various periods. Below are the details of our regulatory assets and liabilities as of December 31, 2015 and 2014:

	2015			2014
	(Thousands of Dollars)
Current regulatory assets:
Environmental costs	$	1,300		$	1,300
Levelized depreciation	2,731			1,999
Fuel recovery	178			—
Total current regulatory assets	4,209			3,299
Noncurrent regulatory assets:
Environmental costs	(1,068		)	2,109
Grossed-up deferred taxes on equity funds used during construction	13,809			14,567
Levelized depreciation	26,493			29,775
Asset retirement obligations, net	1,619			3,472
Total noncurrent regulatory assets	40,853			49,923
Total regulatory assets	$	45,062		$	53,222
Current regulatory liabilities:
Fuel recovery	$	—		$	4,004
Noncurrent regulatory liabilities:
Postretirement benefits	26,802			23,375
Total regulatory liabilities	$	26,802		$	27,379

The significant regulatory assets and liabilities include:

Environmental Costs We have accrued liabilities for assessment and remediation activities to bring certain sites up to current environmental standards. The accrual for these liabilities is offset by a regulatory asset. The regulatory asset is being amortized to expense consistent with amounts collected in rates.

Levelized Depreciation Levelized depreciation allows contract revenue streams to remain constant over the primary contract terms by recognizing lower than book depreciation in the early years and higher than book depreciation in later years. The depreciation component of the levelized incremental rates will equal the accumulated book depreciation by the end of the primary contract terms. The difference between levelized depreciation and straight-line book depreciation is recorded as a FERC approved regulatory asset or liability and is eliminated over the levelization period.

Grossed-Up Deferred Taxes on Equity Funds Used During Construction The regulatory asset balance was established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. All amounts were generated during the period that we were a taxable entity. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long-lived asset to which they relate.

Asset Retirement Obligations This regulatory asset balance is established to offset depreciation of the ARO asset and changes in the ARO liability due to the passage of time. The regulatory asset is expected to be fully recovered through the net

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NORTHWEST PIPELINE LLC

NOTES TO FINANCIAL STATEMENTS

negative salvage component of depreciation included in our rates; as such, the negative salvage component of accumulated depreciation has been reclassified and netted against the amount of the ARO regulatory asset.

Fuel Recovery These amounts reflect the value of the cumulative volumetric difference between the gas retained from our customers and the gas consumed in operations. These amounts are not included in the rate base, but are expected to be recovered or refunded by changing the fuel reimbursement factor in subsequent fuel filings.

Postretirement Benefits We seek to recover the actuarially determined cost of postretirement benefits through rates that are set through periodic general rate filings. Any differences between the annual actuarially determined cost and amounts currently being recovered in rates are recorded as regulatory assets or liabilities and collected or refunded through future rate adjustments. These amounts are not included in the rate base, and we are not currently recovering postretirement benefit costs in our rates.

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NORTHWEST PIPELINE LLC

QUARTERLY FINANCIAL DATA

(Unaudited)

The following is a summary of unaudited quarterly financial data for 2015 and 2014:

	Quarter of 2015
	First		Second		Third		Fourth
	(Thousands of Dollars)
Operating revenues	$	119,264	$	115,946	$	116,933	$	120,851
Operating income	57,152		53,287		54,300		57,767
Net income	46,408		42,109		43,310		46,869

	Quarter of 2014
	First		Second		Third		Fourth
	(Thousands of Dollars)
Operating revenues	$	119,085	$	114,644	$	116,249	$	120,072
Operating income	57,025		48,903		56,003		54,231
Net income	45,483		37,656		44,488		42,926

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Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

Our management, including our Senior Vice President — West and our Vice President and Chief Accounting Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a—15(e) and 15d—15(e) of the Securities Exchange Act) (Disclosure Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.

Evaluation of Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Senior Vice President — West and our Vice President and Chief Accounting Officer. Based upon that evaluation, our Senior Vice President — West and our Vice President and Chief Accounting Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

There have been no changes during the fourth quarter of 2015 that have materially affected, or are reasonably likely to materially affect, our Internal Control over Financial Reporting.

Management’s Annual 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) and 15d – 15(f) under the Securities Exchange Act of 1934). Our internal control over financial reporting is designed to provide reasonable assurance to our management regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. 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 of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

All internal control systems, no matter how well designed, have inherent limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Under the supervision and with the participation of our management, including our Senior Vice President — West and our Vice President and Chief Accounting Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2015, based on 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, we concluded that, as of December 31, 2015, our internal control over financial reporting was effective.

40

This annual report does not include a report of our registered public accounting firm regarding internal control over financial reporting. A report by our registered public accounting firm is not required pursuant to rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report.

Item 9B. OTHER INFORMATION

None.

41

PART III

Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K, the information required by Items 10, 11, 12, and 13 is omitted.

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Fees for professional services provided by our independent auditors in each of the last two fiscal years in each of the following categories are:

	2015		2014
	(Thousands of Dollars)
Audit fees	$	739	$	737
Audit related fees	—		—
Tax fees	—		—
All other fees	—		—
	$	739	$	737

Fees for audit services include fees associated with the annual audit, the reviews for our quarterly reports on Form 10-Q, the reviews for other SEC and FERC filings, and accounting consultations.

As a wholly-owned subsidiary of WPZ, we do not have a separate audit committee. The policies and procedures for pre-approving audit and non-audit services of the Audit Committee of the Board of Directors of WPZ’s general partner have been set forth in WPZ’s 2015 annual report on Form 10-K, which is available on the SEC’s website at http://www.sec.gov and at http://investor.williams.com.

42

PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

	Page Reference to 2014 Form 10-K
(a) 1. and 2. Northwest Pipeline LLC financials
Index
Covered by reports of independent auditors:
Statement of Comprehensive Income for the Years Ended December 31, 2015, 2014, and 2013	22
Balance Sheet at December 31, 2015 and 2014	23
Statement of Owner's Equity for the Years Ended December 31, 2015, 2014, and 2013	25
Statement of Cash Flows for the Years Ended December 31, 2015, 2014, and 2013	26
Notes to Financial Statements	27
Not covered by reports of independent auditors:
Quarterly Financial Data (Unaudited)	39

All other schedules have been omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the financial statements and notes thereto.

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(a) 3 and b. Exhibits:

Exhibit	Description
2	Certificate of Conversion of Northwest Pipeline GP (Exhibit 2.1 to our current report on Form 8-K, filed July 3, 2013 (File No. 001-07414) and incorporated herein by reference).
3.1	Certificate of Formation of Northwest Pipeline LLC (Exhibit 2.2 to our current report on Form 8-K, filed July 3, 2013 (File No. 001-07414) and incorporated herein by reference).
3.2	Operating Agreement of Northwest Pipeline LLC (Exhibit 3.1 to our current report on Form 8-K, filed July 3, 2013 (File No. 001-07414) and incorporated herein by reference).
4.1	Senior Indenture, dated as of November 30, 1995 between Northwest Pipeline Corporation and Chemical Bank, relating to Northwest Pipeline’s 7.125% Debentures due 2025 (Exhibit 4.1 to our registration statement on Form S-3, filed September 14, 1995 (File No. 033-62639) and incorporated herein by reference).
4.2	Indenture, dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., relating to Northwest Pipeline’s $175 million aggregate principal amount of 7.0% Senior Notes due 2016 (Exhibit 4.1 to our current report on Form 8-K, filed June 23, 2006 (File No. 001-07414) and incorporated herein by reference).
4.3	Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York, as trustee, relating to $185 million aggregate principal amount of 5.95% Senior Notes due 2017 (Exhibit 4.1 to our current report on Form 8-K, filed April 6, 2007 (File No. 001-07414) and incorporated herein by reference).
4.4	Indenture, dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as trustee, relating to $250 million aggregate principal amount of 6.05% Senior Notes due 2018 (Exhibit 4.1 to our current report on Form 8-K, filed May 23, 2008 (File No. 001-07414) and incorporated herein by reference).
10.1	Administrative Services Agreement, dated January 24, 2008, between Northwest Pipeline GP and Northwest Pipeline Services, LLC (Exhibit 10.1 to our current report on Form 8-K, filed January 30, 2008 (File No. 001-07414) and incorporated herein by reference.
10.2	Assignment Agreement dated February 13, 2013, by and between Northwest Pipeline Services, LLC and Williams WPC-I, LLC, effective January 1, 2013 (Exhibit 10(b) to our annual report on Form 10-K, filed February 27, 2013 (File No. 001-07414) and incorporated herein by reference).
10.3	Second Amended and Restated Credit Agreement, dated as of February 2, 2015, between Williams Partners L.P. (formerly known as Access Midstream Partners, L.P.), Northwest Pipeline LLC, and Transcontinental Gas Pipeline Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A., as Administrative Agent (Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K, filed on February 3, 2015 (File No. 001-34831) and incorporated herein by reference).
10.4	Amendment No. 1 to Second Amended & Restated Credit Agreement dated December 18, 2015, between Williams Partners L.P., Northwest Pipeline LLC, Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on December 23, 2015 as Exhibit 10.1 to our current report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
31.1*	Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of The Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of The Sarbanes-Oxley Act of 2002.
32**	Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*	XBRL Taxonomy Definition Linkbase
101.LAB*	XBRL Taxonomy Extension Label Linkbase.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase.

44

* Filed herewith

** Furnished herewith

45

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 PIPELINE LLC
(Registrant)
By	/s/ Jeffrey P. Heinrichs
	Jeffrey P. Heinrichs
	Controller

Date: February 24, 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 in the capacities and on the dates indicated.

Signature	Title
/s/ Walter J. Bennett	Senior Vice President – West and Management Committee Member (Principal Executive Officer)
Walter J. Bennett
/s/ Ted T. Timmermans	Vice President and Chief Accounting Officer (Principal Financial Officer)
Ted T. Timmermans
/s/ Jeffrey P. Heinrichs	Controller (Principal Accounting Officer)
Jeffrey P. Heinrichs
/s/ Richard D. Rodekohr	Management Committee Member
Richard D. Rodekohr

Date: February 24, 2016

EXHIBIT INDEX

Exhibit	Description
2	Certificate of Conversion of Northwest Pipeline GP (Exhibit 2.1 to our current report on Form 8-K, filed July 3, 2013 (File No. 001-07414) and incorporated herein by reference).
3.1	Certificate of Formation of Northwest Pipeline LLC (Exhibit 2.2 to our current report on Form 8-K, filed July 3, 2013 (File No. 001-07414) and incorporated herein by reference).
3.2	Operating Agreement of Northwest Pipeline LLC (Exhibit 3.1 to our current report on Form 8-K, filed July 3, 2013 (File No. 001-07414) and incorporated herein by reference).
4.1	Senior Indenture, dated as of November 30, 1995 between Northwest Pipeline Corporation and Chemical Bank, relating to Northwest Pipeline’s 7.125% Debentures due 2025 (Exhibit 4.1 to our registration statement on Form S-3, filed September 14, 1995 (File No. 033-62639) and incorporated herein by reference).
4.2	Indenture, dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., relating to Northwest Pipeline’s $175 million aggregate principal amount of 7.0% Senior Notes due 2016 (Exhibit 4.1 to our current report on Form 8-K, filed June 23, 2006 (File No. 001-07414) and incorporated herein by reference).
4.3	Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York, as trustee, relating to $185 million aggregate principal amount of 5.95% Senior Notes due 2017 (Exhibit 4.1 to our current report on Form 8-K, filed April 6, 2007 (File No. 001-07414) and incorporated herein by reference).
4.4	Indenture, dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as trustee, relating to $250 million aggregate principal amount of 6.05% Senior Notes due 2018 (Exhibit 4.1 to our current report on Form 8-K, filed May 23, 2008 (File No. 001-07414) and incorporated herein by reference).
10.1	Administrative Services Agreement, dated January 24, 2008, between Northwest Pipeline GP and Northwest Pipeline Services, LLC (Exhibit 10.1 to our current report on Form 8-K, filed January 30, 2008 (File No. 001-07414) and incorporated herein by reference.
10.2	Assignment Agreement dated February 13, 2013, by and between Northwest Pipeline Services, LLC and Williams WPC-I, LLC, effective January 1, 2013 (Exhibit 10(b) to our annual report on Form 10-K, filed February 27, 2013 (File No. 001-07414) and incorporated herein by reference).
10.3	Second Amended and Restated Credit Agreement, dated as of February 2, 2015, between Williams Partners L.P. (formerly known as Access Midstream Partners, L.P.), Northwest Pipeline LLC, and Transcontinental Gas Pipeline Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A., as Administrative Agent (Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K, filed on February 3, 2015 (File No. 001-34831) and incorporated herein by reference).
10.4	Amendment No. 1 to Second Amended & Restated Credit Agreement dated December 18, 2015, between Williams Partners L.P., Northwest Pipeline LLC, Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on December 23, 2015 as Exhibit 10.1 to our current report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
31.1*	Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of The Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of The Sarbanes-Oxley Act of 2002.
32**	Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*	XBRL Taxonomy Definition Linkbase

101.LAB*	XBRL Taxonomy Extension Label Linkbase.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase.

* Filed herewith

** Furnished herewith

EX-31.1

Exhibit 31.1

SECTION 302 CERTIFICATION

I, Walter J. Bennett, certify that:

1. I have reviewed this annual report on Form 10-K of Northwest Pipeline LLC;

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(s) 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(s) 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 24, 2016

By:	/s/ Walter J. Bennett
	Walter J. Bennett
	Sr. Vice President—West
	(Principal Executive Officer)

EX-31.2

Exhibit 31.2

SECTION 302 CERTIFICATION

I, Ted T. Timmermans, certify that:

1. I have reviewed this annual report on Form 10-K of Northwest Pipeline LLC;

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(s) 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(s) 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 24, 2016

By:	/s/ Ted T. Timmermans
	Ted T. Timmermans
	Vice President and Chief Accounting Officer
	(Principal Financial Officer)

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Northwest Pipeline LLC (the “Company”) on Form 10-K for the period ending December 31, 2015 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies, in his capacity as an officer of the Company, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Walter J. Bennett

Walter J. Bennett

Senior Vice President—West

February 24, 2016

/s/ Ted T. Timmermans

Ted T. Timmermans

Vice President and Chief Accounting Officer

February 24, 2016

A signed original of this written statement required by Section 906 has been provided to, and will be retained by, the Company and furnished to the Securities and Exchange Commission or its staff upon request.

The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Report and shall not be considered filed as part of the Report.

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 24, 2016
Entity Information [Line Items]
Entity Registrant Name	Northwest Pipeline LLC
Entity Central Index Key	0000110019
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		0
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float		$ 0

XML

Statement of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
OPERATING REVENUES	$ 472,994	$ 470,050	$ 469,661
OPERATING EXPENSES:
General and administrative	57,105	62,085	62,473
Operation and maintenance	73,128	74,191	75,342
Depreciation	100,554	99,138	96,109
Regulatory debits	2,550	1,487	921
Taxes, other than income taxes	17,151	16,987	16,882
Total operating expenses	250,488	253,888	251,727
OPERATING INCOME	222,506	216,162	217,934
OTHER (INCOME) AND OTHER EXPENSES:
Interest expense	46,024	46,095	46,177
Allowance for equity and borrowed funds used during construction	(1,619)	(573)	(1,405)
Miscellaneous other (income) expenses, net	(595)	87	175
Total other (income) and other expenses	43,810	45,609	44,947
NET INCOME	178,696	170,553	172,987
CASH FLOW HEDGES:
Amortization of cash flow hedges into Interest expense	(62)	(62)	(62)
COMPREHENSIVE INCOME	$ 178,634	$ 170,491	$ 172,925

XML

Balance Sheet - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
CURRENT ASSETS:
Cash	$ 169	$ 154
Receivables:
Trade	42,669	42,759
Affiliated companies	1,441	2,039
Advances to affiliate	171,867	135,054
Other	14,051	1,249
Materials and supplies	10,183	10,066
Exchange gas due from others	3,733	4,184
Exchange gas offset	201	0
Prepayments and other	6,164	4,881
Total current assets	250,478	200,386
PROPERTY, PLANT AND EQUIPMENT, at cost	3,306,205	3,269,617
Less-Accumulated depreciation	1,367,632	1,288,530
Total property, plant and equipment, net	1,938,573	1,981,087
OTHER ASSETS:
Deferred charges	2,110	2,768
Regulatory assets	40,853	49,923
Total other assets	42,963	52,691
Total assets	2,232,014	2,234,164
Payables:
Trade	14,363	12,709
Affiliated companies	11,959	13,143
Accrued liabilities:
Taxes, other than income taxes	11,033	11,246
Interest	4,045	4,045
Exchange gas due to others	2,252	6,406
Exchange gas offset	0	3,941
Customer advances	5,573	2,363
Other	3,417	1,799
Long-term debt due within one year	174,837	0
Total current liabilities	227,479	55,652
LONG-TERM DEBT	518,583	692,488
OTHER NONCURRENT LIABILITIES:
Asset retirement obligations	82,454	94,678
Regulatory liabilities	26,802	23,375
Other	6,108	8,017
Total other noncurrent liabilities	$ 115,364	$ 126,070
CONTINGENT LIABILITIES AND COMMITMENTS (Note 3)
OWNER'S EQUITY:
Owner's capital	$ 1,073,892	$ 1,073,892
Retained earnings	296,668	285,972
Accumulated other comprehensive income	28	90
Total owner's equity	1,370,588	1,359,954
Total liabilities and owner's equity	$ 2,232,014	$ 2,234,164

XML

Statement of Owner's Equity Statement of Owner's Equity - USD ($) $ in Thousands	Total	Owner's capital	Retained earnings	Accumulated other comprehensive income (loss)
Balance at beginning of period at Dec. 31, 2012		$ 1,060,592	$ 267,432	$ 214
Capital contributions from parent	$ 13,300	13,300
Net income	172,987		172,987
Cash distributions to parent	(91,000)		(91,000)
Reclassification of unrecognized gain into earnings	(62)			(62)
Balance at end of period at Dec. 31, 2013	1,423,463	1,073,892	349,419	152
Capital contributions from parent	0	0
Net income	170,553		170,553
Cash distributions to parent	(234,000)		(234,000)
Reclassification of unrecognized gain into earnings	(62)			(62)
Balance at end of period at Dec. 31, 2014	1,359,954	1,073,892	285,972	90
Capital contributions from parent	0	0
Net income	178,696		178,696
Cash distributions to parent	(168,000)		(168,000)
Reclassification of unrecognized gain into earnings	(62)			(62)
Balance at end of period at Dec. 31, 2015	$ 1,370,588	$ 1,073,892	$ 296,668	$ 28

XML

Statement of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
OPERATING ACTIVITIES:
Net income	$ 178,696	$ 170,553	$ 172,987
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation	100,554	99,138	96,109
Regulatory debits	2,550	1,487	921
Gain on sale of property, plant and equipment	0	(70)	0
Amortization of deferred charges and credits	762	894	1,720
Allowance for equity funds used during construction	(1,099)	(391)	(945)
Changes in current assets and liabilities:
Trade and other accounts receivable	(137)	395	2,133
Affiliated receivables	598	38,388	(38,744)
Exchange gas due from others	7,349	(1,433)	153
Materials and supplies	(117)	203	(132)
Other current assets	(1,283)	(1,326)	(202)
Trade accounts payable	158	(4,958)	(212)
Affiliated payables	(1,184)	2,007	224
Exchange gas due to others	(8,095)	2,179	(153)
Other accrued liabilities	5,410	(3,095)	3,885
Changes in noncurrent assets and liabilities:
Deferred charges	(2,633)	(2,087)	(7,448)
Noncurrent liabilities	9,164	11,000	9,819
Net cash provided by operating activities	290,693	312,884	240,115
FINANCING ACTIVITIES:
Capital contributions from parent	0	0	13,300
Cash distributions to parent	(168,000)	(234,000)	(91,000)
Other	0	(622)	(1,318)
Net cash used in financing activities	(168,000)	(234,622)	(79,018)
Property, plant and equipment:
Capital expenditures, net of equity AFUDC	(86,289)	(79,413)	(83,317)
Contributions and Advances for Construction Costs	1,499	3,056	6,326
Disposal of property, plant, and equipment, net	(1,075)	5,728	5,756
Advances to affiliates, net	(36,813)	(15,886)	(89,846)
Proceeds from insurance	0	8,274	0
Net cash used in investing activities	(122,678)	(78,241)	(161,081)
NET INCREASE IN CASH	15	21	16
CASH AT BEGINNING OF PERIOD	154	133	117
CASH AT END OF PERIOD	169	154	133
Supplemental Cash Flow Elements [Abstract]
Increases to property, plant and equipment	(73,931)	(71,207)	(88,123)
Changes in accounts receivable, accounts payable, and accrued liabilities	(12,358)	(8,206)	4,806
Capital expenditures, net of equity AFUDC	$ (86,289)	$ (79,413)	$ (83,317)

XML

Summary of Significant Accounting Policies (Notes)

12 Months Ended

Dec. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure and Control

Northwest Pipeline LLC (Northwest) is indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). On February 2, 2015, WPZ was merged into Access Midstream Partners, L.P. (ACMP), another publicly traded limited partnership consolidated by Williams. ACMP was the surviving partnership and was subsequently renamed WPZ. At December 31, 2015, Williams holds an approximate 60 percent interest in WPZ, comprised of an approximate 58 percent limited partner interest and all of the 2 percent general partner interest.

Northwest has no employees. Services are provided to Northwest by Williams and its affiliates. Northwest reimburses Williams and its affiliates for the costs of the employees including compensation and employee benefit plan costs and all related administrative costs.

In this report, Northwest is at times referred to in the first person as “we,” “us” or “our.”

On September 28, 2015, Williams publicly announced in a press release that it had entered into an Agreement and Plan of Merger (Merger Agreement) with Energy Transfer Equity, L.P. (Energy Transfer) and certain of its affiliates. The Merger Agreement provides that, subject to the satisfaction of customary closing conditions, Williams will be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger) with ETC surviving the ETC Merger. Energy Transfer formed ETC as a limited partnership that will be treated as a corporation for U.S. federal income tax purposes. Immediately following the completion of the ETC Merger, ETC will contribute to Energy Transfer all of the assets and liabilities of Williams in exchange for the issuance by Energy Transfer to ETC of a number of Energy Transfer Class E common units equal to the number of ETC common shares issued to Williams stockholders in the ETC Merger. WPZ expects to retain its current name and remain a publicly traded limited partnership following the ETC Merger.

Nature of Operations

We own and operate an interstate pipeline system for the mainline transmission of natural gas. This system extends from the San Juan Basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on the Canadian border near Sumas, Washington.

Regulatory Accounting

Our natural gas pipeline operations are regulated by the Federal Energy Regulatory Commission (FERC). FERC regulatory policies govern the rates that each pipeline is permitted to charge customers for interstate transportation and storage of natural gas.

The Accounting Standards Codification (ASC) Regulated Operations (Topic 980) provides that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying Topic 980, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to customers in future periods. The accompanying financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. (See Note 9 for further discussion.)

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) litigation-related contingencies; 2) environmental remediation obligations; 3) impairment assessments of long-lived assets; 4) depreciation; and 5) asset retirement obligations.

Revenue Recognition

Our revenues are primarily from services pursuant to long term firm transportation and storage agreements. These agreements provide for a reservation charge based on the volume of contracted capacity and a volumetric charge based on the volume of gas delivered, both at rates specified in our FERC tariffs. We recognize revenues for reservation charges ratably over the contract period regardless of the volume of natural gas that is transported or stored. Revenues for volumetric charges, from both firm and interruptible transportation services and storage injection and withdrawal services, are recognized based on volumes of natural gas scheduled for delivery at the agreed upon delivery point or based on volumes of natural gas scheduled for injection or withdrawal from the storage facility.

In the course of providing transportation services to our customers, we may receive or deliver different quantities of gas from shippers than the quantities delivered or received on behalf of those shippers. These transactions result in imbalances, which are typically settled through the receipt or delivery of gas in the future. Customer imbalances to be repaid or recovered in-kind are recorded as exchange gas due from others or due to others in the accompanying balance sheets. The difference between exchange gas due to us from customers and the exchange gas that we owe to customers is included in the exchange gas offset. These imbalances are valued at the average of the spot market rates at the Canadian border and the Rocky Mountain market as published in the SNL Financial “Bidweek Index - Spot Rates.” Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions.

As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and third-party regulatory proceedings, advice of counsel and other risks. At December 31, 2015, we had no such rate refund liabilities.

Environmental Matters

We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their future economic benefit and potential for rate recovery. We believe that expenditures required to meet applicable environmental laws and regulations are prudently incurred in the ordinary course of business and such expenditures would be permitted to be recovered through rates.

Property, Plant, and Equipment

Property, plant and equipment (plant), consisting principally of natural gas transmission facilities, is recorded at original cost. The FERC identifies installation, construction and replacement costs that are to be capitalized and included in our asset base for recovery in rates. Routine maintenance, repairs, and renewal costs are charged to income as incurred. Gains or losses from the ordinary sale or retirement of plant are charged or credited to accumulated depreciation; certain other gains or losses are recorded in operating income.

We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2015, 2014, and 2013 are as follows:

Category of Property
Storage Facilities	1.60	%	—	2.76%
Transmission Facilities	2.80	%	—	6.97%

The incrementally priced Evergreen Expansion Project, which was an expansion of our pipeline system, was placed in service on October 1, 2003. The levelized rate design of this project creates a consistent revenue stream over the related 25-year and 15-year customer contract terms. The related levelized depreciation is lower than book depreciation in the early years and higher than book depreciation in the later years of the contract terms. The depreciation component of the levelized incremental rates will equal the accumulated book depreciation by the end of the primary contract terms. The FERC has approved the accounting for the differences between book depreciation and the Evergreen Expansion Project’s levelized depreciation as a regulatory asset.

We recorded regulatory debits totaling $2.6 million in 2015, $1.5 million in 2014, and $0.9 million in 2013 in the accompanying Statement of Comprehensive Income. These debits relate primarily to the levelized depreciation adjustment for the Evergreen Project discussed above.

We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. Measurement of AROs includes, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as market-risk premium. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and is offset by a regulatory asset. The gross regulatory asset balances associated with ARO as of December 31, 2015 and 2014 were $70.9 million and $63.7 million, respectively. The regulatory asset is expected to be fully recovered through the net negative salvage component of depreciation included in our rates; as such, the negative salvage component of accumulated depreciation ($69.3 million and $60.2 million at December 31, 2015 and 2014, respectively) has been reclassified and netted against the amount of the ARO regulatory asset.

Impairment of Long-Lived Assets

We evaluate long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When such a determination has been made, our management’s estimate of undiscounted future cash flows attributable to the assets is compared to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, the amount of the impairment recognized in the financial statements is determined by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements.

Allowance for Funds Used During Construction

Allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in process of construction and is included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. The FERC has prescribed a formula to be used in computing separate allowances for debt and equity AFUDC. The cost of debt portion of AFUDC was $0.5 million for 2015, $0.2 million for 2014, and $0.5 million for 2013. The equity funds portion of AFUDC was $1.1 million, $0.4 million, and $0.9 million for 2015, 2014, and 2013, respectively. Both are reflected in Other (Income) and Other Expenses.

Income Taxes

We generally are not a taxable entity for federal or state and local income tax purposes. The tax on net income is generally borne by unitholders of our ultimate parent, WPZ. Net income for financial statement purposes may differ significantly from taxable income of WPZ’s unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the WPZ partnership agreement. The aggregated difference in the basis of our assets for financial and tax reporting purposes cannot be readily determined because information regarding each of WPZ’s unitholder’s tax attributes in WPZ is not available to us.

Accounts Receivable and Allowance for Doubtful Receivables

Accounts receivable are stated at the historical carrying amount net of reserves or write-offs. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers’ financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables. Receivables determined to be uncollectible are reserved or written off in the period of such determination.

Materials and Supplies Inventory

All inventories are stated at lower of cost or market. We determine the cost of the inventories using the average cost method.

We perform an annual review of materials and supplies inventories, including an analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 2015 and 2014.

Deferred Charges

We amortize deferred charges over varying periods consistent with the FERC approved accounting treatment and recovery for such deferred items. Unamortized debt expense, debt discount and losses on reacquired long-term debt are amortized by the bonds outstanding method over the related debt repayment periods.

Pension and Other Postretirement Benefits

We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 5 for further discussion.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us, and thus paid by us, is based on our share of net periodic benefit cost.

Contingent Liabilities

We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third-parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.

Cash Flows from Operating Activities and Cash Equivalents

We use the indirect method to report cash flows from operating activities, which requires adjustments to net income to reconcile to net cash flows provided by operating activities. We include short-term, highly-liquid investments that have an original maturity of three months or less as cash equivalents.

Interest Payments

Cash payments for interest, net of interest capitalized, were $45.3 million in 2015, $44.5 million in 2014, and $44.6 million in 2013.

Accounting Standards Issued But Not Yet Adopted

In January 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-01 “Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01). ASU 2016-01 addresses certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. The new standard is effective for interim and annual periods beginning after December 15, 2017. Early adoption is only permitted for certain applications. We are evaluating the impact of the new standard on our consolidated financial statements and our timing for adoption.

In July 2015, the FASB issued ASU 2015-11 "Simplifying the Measurement of Inventory" (ASU 2015-11). ASU 2015-11 simplifies the guidance on the subsequent measurement of inventory, excluding inventory measured using last in, first out or the retail inventory method. Under the new standard, in scope inventory should be measured at the lower of cost and net realizable value. The new standard is effective for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We measure inventory at the lower of cost or market; upon adoption, we will measure inventory at the lower of cost and net realizable value. We do not expect the new standard will have a material impact on the value of inventory reported in our financial statements.

In February 2015, the FASB issued ASU 2015-02 "Amendments to the Consolidation Analysis"(ASU 2015-02). ASU 2015-02 alters the models used to determine consolidation conclusions for certain entities, including limited partnerships, and may require additional disclosures. The standard is effective for financial statements issued for interim and annual reporting periods beginning after December 15, 2015, with either retrospective or modified retrospective presentation allowed. We do not expect the new standard will have a significant impact on our financial statements.

In May 2014, the FASB issued ASU 2014-09 establishing ASC Topic 606, "Revenue from Contracts with Customers" (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date" (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016. We continue to evaluate both the impact of this new standard on our financial statements and the transition method we will utilize for adoption.

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Rate and Regulatory Matters (Notes)

12 Months Ended

Dec. 31, 2015

Public Utilities, Rate Matters [Abstract]

Public Utilities, Disclosure of Rate Matters [Text Block]

RATE AND REGULATORY MATTERS

Rates

Our rates became effective January 1, 2013, and will remain in effect for 5 years.

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Contingent Liabilities and Commitments (Notes)

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Contingent Liabilities and Commitments

CONTINGENT LIABILITIES AND COMMITMENTS

Environmental Matters

We are subject to the National Environmental Policy Act and other federal and state legislation regulating the environmental aspects of our business. Except as discussed below, our management believes that we are in substantial compliance with existing environmental requirements. Environmental expenditures are expensed or capitalized depending on their future economic benefit and potential for rate recovery. We believe that, with respect to any expenditures required to meet applicable standards and regulations, the FERC would grant the requisite rate relief so that substantially all of such expenditures would be permitted to be recovered through rates. As a result, we believe that compliance with applicable environmental requirements is not likely to have a material adverse effect upon our financial position or results of operations.

Beginning in the mid-1980s, we evaluated many of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation might be necessary. We identified polychlorinated biphenyl (PCB) contamination in air compressor systems, soils and related properties at certain compressor station sites. Similarly, we identified hydrocarbon impacts at these facilities due to the former use of earthen pits, lubricating oil leaks or spills, and excess pipe coating released to the environment. In addition, heavy metals have been identified at these sites due to the former use of mercury containing meters and paint and welding rods containing lead, cadmium, and arsenic. The PCBs were remediated pursuant to a Consent Decree with the U.S. Environmental Protection Agency (EPA) in the late 1980s, and we conducted a voluntary clean-up of the hydrocarbon and mercury impacts in the early 1990s. In 2005, the Washington Department of Ecology required us to re-evaluate our previous clean-ups in Washington. During 2006 to 2014, 143 meter stations were evaluated, of which 80 required remediation. As of December 31, 2015, all but one meter station has been remediated. Initial assessments have been completed at all thirteen compressor stations in Washington. Additional assessments are ongoing at three of these compressor stations. Remediation has been completed at nine of the thirteen compressor stations. On the basis of the findings to date, we estimate that environmental assessment and remediation costs will total approximately $4.6 million, measured on an undiscounted basis, and are expected to be incurred through 2019. At December 31, 2015 and 2014, we had accrued liabilities totaling approximately $4.6 million and $7.8 million, respectively, for these costs. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs.

In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. In May 2012, the EPA completed designation of new eight-hour ozone non-attainment areas. Based on the published designations, no Northwest facilities are located within the non-attainment areas. At this time, it is unknown whether future state regulatory actions associated with implementation of the 2008 ozone standard will impact our operations and increase the cost of additions to property, plant and equipment. Until any additional state regulatory actions are proposed, we are unable to estimate the cost of additions that may be required to meet any such new regulation.

In December 2014, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels. The EPA is anticipated to finalize any revisions in late 2015. Revisions to the ozone NAAQS will result in additional federal and state regulatory actions that may impact our operations. As a result, the cost of additions to property, plant, and equipment is expected to increase. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet new regulations.

On January 22, 2010, the EPA set a new one-hour nitrogen dioxide (NO2) NAAQS. The effective date of the new NO2 standard was April 12, 2010. On January 20, 2012, the EPA determined pursuant to available information that no area in the country is violating the 2010 NO2 NAAQS, and thus, designated all areas of the country as “unclassifiable/attainment.” Also, at that time, the EPA noted its plan to deploy an expanded NO2 monitoring network beginning in 2013. However, on October 5, 2012, the EPA proposed a graduated implementation of the monitoring network between January 1, 2014 and January 1, 2017. Once three years of data is collected from the new monitoring network, the EPA will reassess attainment status with the one-hour NO2 NAAQS. Until that time, the EPA or states may require ambient air quality modeling on a case by case basis to demonstrate compliance with the NO2 standard. Because we are unable to predict the outcome of the EPA’s or states’ future assessment using the new monitoring network, we are unable to estimate the cost of additions that may be required to meet this regulation.

Other Matters

Various other proceedings are pending against us and are considered incidental to our operations.

Summary

We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities are immaterial to our expected future annual results of operations, liquidity and financial position. These calculations have been made without consideration of any potential recovery from third-parties. We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss.

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Debt, Financing Arrangements, and Leases (Notes)

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Debt, Financing Arrangements, and Leases

DEBT, FINANCING ARRANGEMENTS, AND LEASES

Long-Term Debt

Long-term debt, presented net of unamortized discount and unamortized debt issuance costs, consists of the following:

	December 31,
	2015			2014
	(Thousands of Dollars)
5.95% senior unsecured notes due 2017	$	185,000		$	185,000
6.05% senior unsecured notes due 2018	250,000			250,000
7% senior unsecured notes due 2016	175,000			175,000
7.125% unsecured debentures due 2025	85,000			85,000
Debt issuance costs	(1,197		)	(1,932		)
Unamortized debt discount	(383		)	(580		)
Total long-term debt, including current portion	$	693,420		$	692,488
Long-term debt due within one year	174,837			—
Total long-term debt	518,583			692,488

As of December 31, 2015, cumulative maturities of outstanding long-term debt (at face value) for the next five years are as follows:

	(Thousands of Dollars)
2016: 7% senior unsecured notes	$	175,000
2017: 5.95% senior unsecured notes	185,000
2018: 6.05% senior unsecured notes	250,000
Total	$	610,000

The long-term debt due within one year at December 31, 2015 is associated with our $175 million7% senior unsecured notes that mature on June 15, 2016.

In 2006, we entered into certain forward starting interest rate swaps prior to our issuance of the 7% senior unsecured notes due 2016 to hedge the variability of forecasted interest payments arising from changes in interest rates prior to the issuance of this debt. The settlement resulted in a gain, recorded in Accumulated other comprehensive income, that is being amortized to reduce interest expense over the life of the related debt.

Restrictive Debt Covenants

At December 31, 2015, none of our debt instruments restrict the amount of distributions to our parent. Our debt agreements contain restrictions on our ability to incur secured debt beyond certain levels.

Credit Facility

On February 2, 2015, we, along with WPZ, Transco, the lenders named therein, and an administrative agent, entered into the Second Amended and Restated Credit Agreement with aggregate commitments available of $3.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. The maturity date of the facility is February 2, 2020. However, the co-borrowers may request up to two extensions of the maturity date, each for an additional one-year period, to allow a maturity date as late as February 2, 2022, under certain circumstances. The agreement allows for swing line loans up to an aggregate amount of $150 million, subject to available capacity under the credit facility, and letters of credit commitments available to WPZ of $1.125 billion. We are able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers. At December 31, 2015, no letters of credit were issued and $1.31 billion of loans to WPZ were outstanding under the credit facility. On December 18, 2015, we, along with WPZ, Transco, the lenders named therein, and an administrative agent, entered into the Amendment No. 1 to Second Amended and Restated Credit Agreement modifying the thresholds specified in the covenant related to the maximum ratio of WPZ’s consolidated indebtedness to consolidated EBITDA.

Under the credit facility, WPZ is required to maintain a ratio of debt to EBITDA (each as defined in the credit facility) that must be no greater than 5.75 to 1.0 for the quarters ending December 31, 2015, March 31, 2016, and June 30, 2016. The ratio must be no greater than 5.5 to 1.0 for the quarters ending September 30, 2016 and December 31, 2016. The ratio must be no greater than 5.0 to 1.0 for the quarter ending March 31, 2017 and each subsequent fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions have been executed, in which case the ratio must be no greater than 5.50 to 1.0. For us, the ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent. Measured as of December 31, 2015, we are in compliance with this financial covenant.

Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, a borrower’s ability to merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, enter into certain restrictive agreements, and allow any material change in the nature of its business.

If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments for the respective borrowers and accelerate the maturity of any loans of the defaulting borrower under the credit facility agreement and exercise other rights and remedies.

Other than swingline loans, each time funds are borrowed, the borrower must choose whether such borrowing will be an alternate base rate borrowing or a Eurodollar borrowing. If such borrowing is an alternate base rate borrowing, interest is calculated on the basis of the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 1/2 of 1 percent, and (c) a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus 1 percent, plus, in the case of each of (a), (b), and (c), an applicable margin. If the borrowing is a Eurodollar borrowing, interest is calculated on the basis of LIBOR for the relevant period plus an applicable margin. Interest on swingline loans is calculated as the sum of the alternate base rate plus an applicable margin. The borrower is required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings.

WPZ participates in a commercial paper program, and WPZ management considers amounts outstanding under this program to be a reduction of available capacity under the credit facility. On February 2, 2015, WPZ amended and restated the commercial paper program for the WPZ/ACMP merger and to allow a maximum outstanding of $3 billion. At December 31, 2015, WPZ had $499 million in outstanding commercial paper.

Accounting Standards Issued and Adopted

In April 2015, the FASB issued ASU 2015-03 “Interest - Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03). ASU 2015-03 simplifies the presentation of debt issuance costs by requiring such costs be presented as a deduction from the corresponding debt liability. Subsequently, in August 2015, the FASB issued ASU 2015-15 “Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangement-Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting” (ASU 2015-15). In ASU 2015-15, the FASB stated that the guidance in ASU 2015-03 did not address the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, and entities are permitted to defer and present debt issuance costs related to line-of-credit arrangements as assets. The standards are effective for financial statements issued for interim and annual reporting periods beginning after December 15, 2015, and require retrospective presentation. Early adoption is permitted. We elected to early adopt these standards for the periods presented. Accordingly, $1.2 million and $1.9 million of debt issuance costs as of December 31, 2015 and 2014, respectively, are now reflected as a direct reduction of debt in our Balance Sheet.

Leases

Our leasing arrangements include mostly premise and equipment leases that are classified as operating leases.

Effective October 1, 2009, we entered into an agreement to lease office space from a third party. The agreement has an initial term of approximately 10 years, with an option to renew for an additional 5 or 10 year term.

Following are the estimated future minimum annual rental payments required under operating leases, which have initial or remaining noncancelable lease terms in excess of one year:

	(Thousands of Dollars)
2016	$	2,561
2017	2,619
2018	2,679
2019	2,740
Total	$	10,599

Operating lease rental expense, net of sublease revenues, amounted to $2.7 million, $2.5 million, and $2.3 million for 2015, 2014, and 2013, respectively.

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Benefit Plans (Notes)

12 Months Ended

Dec. 31, 2015

Disclosure Text Block [Abstract]

Benefit Plans

BENEFIT PLANS

Certain of the benefit costs charged to us by Williams associated with employees who directly support us are described below. Additionally, allocated corporate expenses from Williams to us also include amounts related to these same employee benefits, which are not included in the amounts presented below. (See Note 7 for further discussion.)

Pension and Other Postretirement Benefit Plans

Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan, and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible employees. Pension cost charged to us by Williams was $4.4 million in 2015, $4.2 million in 2014, and $7.8 million in 2013.

Williams provides certain retiree health care and life insurance benefits for eligible participants that generally were employed by Williams on or before December 31, 1991. During 2015, 2014, and 2013, we received credits from Williams related to retiree health care and life insurance benefits of $3.4 million, $4.3 million and $1.7 million, respectively. These credits were recorded as regulatory liabilities.

Defined Contribution Plan

Included in compensation expense is $2.2 million for 2015 and $2.0 million for 2014 and 2013 that Williams charged us for matching contributions to this plan.

Employee Stock-Based Compensation Plan Information

The Williams Companies, Inc. 2007 Incentive Plan, as amended and restated on February 23, 2010, (Plan) was approved by stockholders on May 20, 2010. The Plan provides for Williams’ common stock-based awards to both employees and nonmanagement directors. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets achieved.

Williams currently bills us directly for compensation expense related to stock-based compensation awards based on the fair value of the awards. We are also billed for our proportionate share of Williams’ and other affiliates’ stock-based compensation expense through various allocation processes.

Total stock-based compensation expense for the years ended December 31, 2015, 2014 and 2013 was $1.5 million, $1.2 million and $1.2 million, respectively, excluding amounts allocated from WPZ and Williams.

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Financial Instruments (Notes)

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Financial Instruments

FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Cash and advances to affiliate—The carrying amounts approximate fair value, because of the short-term nature of these instruments.

Long-term debt – The disclosed fair value of our long-term debt, which we consider as a level 2 measurement, is determined by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The carrying amount and estimated fair value of our long-term debt, including current maturities, were $693.4 million and $721.9 million, respectively, at December 31, 2015, and $692.5 million and $766.5 million, respectively, at December 31, 2014.

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Transactions with Major Customers and Affiliates (Notes)

12 Months Ended

Dec. 31, 2015

Transactions with Major Customers and Affiliates [Abstract]

Transactions with Major Customers and Affiliates

TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES

Concentration of Off-Balance-Sheet and Other Credit Risk

During the periods presented, more than 10 percent of our operating revenues were generated from each of the following customers:

	Years Ended December 31,
	2015		2014		2013
	(Thousands of Dollars)
Puget Sound Energy, Inc.	$	118,384	$	113,398	$	110,111
Northwest Natural Gas Company	50,857		50,631		51,085
Cascade Natural Gas Corporation	48,363		(a)		(a)

(a) Under 10 percent in 2014 and 2013.

Our major customers are located in the Pacific Northwest. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are regularly evaluated and historical collection losses have been minimal.

Related Party Transactions

We are a participant in WPZ’s cash management program. At December 31, 2015 and 2014, the advances due to us by WPZ totaled approximately $171.9 million and $135.1 million, respectively. These advances are represented by demand notes and are classified as Current Assets in the accompanying Balance Sheet. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on WPZ’s excess cash at the end of each month, which was approximately 0.12 percent at December 31, 2015. The interest income from these advances was minimal during the years ended December 31, 2015, 2014, and 2013. Such interest income is included in Other (Income) and Other Expenses: Miscellaneous other (income) expenses, net on the accompanying Statement of Comprehensive Income.

We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams and its affiliates for all direct and indirect expenses incurred or payments made (including salary, bonus, incentive compensation, and benefits) in connection with these services. Employees of Williams also provide general administrative and management services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three factor formula, which considers revenues; property, plant, and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. We were billed $100.4 million, $102.4 million, and $106.7 million in the years ended December 31, 2015, 2014, and 2013, respectively, for these services. Such expenses are primarily included in General and administrative and Operation and maintenance expenses on the accompanying Statement of Comprehensive Income.

In 2015, 2014, and 2013, we incurred reimbursable costs of $0.6 million, $27.3 million, and $89.8 million, respectively, due from Williams Field Services related to the construction of a natural gas liquids pipeline, of which $0.5 million was outstanding at December 31, 2014 and a minimal amount was outstanding at December 31, 2015.

During 2015, 2014, and 2013, we declared and paid cash distributions to our parent of $168.0 million, $234.0 million, and $91.0 million, respectively. During January 2016, we declared and paid cash distributions of $57.0 million to our parent.

During 2013, we received contributions of $13.3 million from our parent to fund a portion of our expenditures for additions to property, plant, and equipment. No contributions were received in 2015 or 2014.

We have entered into various other transactions with certain related parties, the amounts of which were not significant. These transactions and the above-described transactions are made on the basis of commercial relationships and prevailing market prices or general industry practices.

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Asset Retirement Obligations (Notes)

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

Our accrued asset retirement obligations relate to our gas storage and transmission facilities. At the end of the useful life of our facilities, we are legally obligated to remove certain transmission facilities including underground pipelines, major river spans, compressor stations and meter station facilities. These obligations also include restoration of the property sites after removal of the facilities from above and below the ground.

During 2015 and 2014, our overall asset retirement obligation changed as follows (in thousands):

	2015			2014
Beginning balance	$	94,678		$	60,753
Accretion	6,870			5,602
New obligations	2,721			157
Changes in estimates of existing obligations (1)	(21,815		)	28,171
Property Dispositions & Settlements	—			(5		)
Ending balance	$	82,454		$	94,678

(1) Changes in estimates of existing obligations are primarily due to the annual review process, which considers various factors including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining life of assets. The decrease in 2015 is primarily attributed to decreases in current estimates for removal costs and inflation rate and an increase in the discount rate. The increase in 2014 is primarily attributed to increases in current estimates for removal costs and inflation rate and a decrease in the discount rate.

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Regulatory Assets and Liabilities (Notes)

12 Months Ended

Dec. 31, 2015

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

REGULATORY ASSETS AND LIABILITIES

Our regulatory assets and liabilities result from our application of the provisions of Topic 980 and are reflected on our balance sheet. Current regulatory assets are included in Exchange gas offset and Prepayments and other. Current regulatory liabilities are included in Exchange gas offset. These balances are presented on our balance sheet on a gross basis and are recoverable or refundable over various periods. Below are the details of our regulatory assets and liabilities as of December 31, 2015 and 2014:

	2015			2014
	(Thousands of Dollars)
Current regulatory assets:
Environmental costs	$	1,300		$	1,300
Levelized depreciation	2,731			1,999
Fuel recovery	178			—
Total current regulatory assets	4,209			3,299
Noncurrent regulatory assets:
Environmental costs	(1,068		)	2,109
Grossed-up deferred taxes on equity funds used during construction	13,809			14,567
Levelized depreciation	26,493			29,775
Asset retirement obligations, net	1,619			3,472
Total noncurrent regulatory assets	40,853			49,923
Total regulatory assets	$	45,062		$	53,222
Current regulatory liabilities:
Fuel recovery	$	—		$	4,004
Noncurrent regulatory liabilities:
Postretirement benefits	26,802			23,375
Total regulatory liabilities	$	26,802		$	27,379

The significant regulatory assets and liabilities include:

Environmental Costs We have accrued liabilities for assessment and remediation activities to bring certain sites up to current environmental standards. The accrual for these liabilities is offset by a regulatory asset. The regulatory asset is being amortized to expense consistent with amounts collected in rates.

Levelized Depreciation Levelized depreciation allows contract revenue streams to remain constant over the primary contract terms by recognizing lower than book depreciation in the early years and higher than book depreciation in later years. The depreciation component of the levelized incremental rates will equal the accumulated book depreciation by the end of the primary contract terms. The difference between levelized depreciation and straight-line book depreciation is recorded as a FERC approved regulatory asset or liability and is eliminated over the levelization period.

Grossed-Up Deferred Taxes on Equity Funds Used During Construction The regulatory asset balance was established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. All amounts were generated during the period that we were a taxable entity. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long-lived asset to which they relate.

Asset Retirement Obligations This regulatory asset balance is established to offset depreciation of the ARO asset and changes in the ARO liability due to the passage of time. The regulatory asset is expected to be fully recovered through the net negative salvage component of depreciation included in our rates; as such, the negative salvage component of accumulated depreciation has been reclassified and netted against the amount of the ARO regulatory asset.

Fuel Recovery These amounts reflect the value of the cumulative volumetric difference between the gas retained from our customers and the gas consumed in operations. These amounts are not included in the rate base, but are expected to be recovered or refunded by changing the fuel reimbursement factor in subsequent fuel filings.

Postretirement Benefits We seek to recover the actuarially determined cost of postretirement benefits through rates that are set through periodic general rate filings. Any differences between the annual actuarially determined cost and amounts currently being recovered in rates are recorded as regulatory assets or liabilities and collected or refunded through future rate adjustments. These amounts are not included in the rate base, and we are not currently recovering postretirement benefit costs in our rates.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Regulatory Accounting

Regulatory Accounting

Our natural gas pipeline operations are regulated by the Federal Energy Regulatory Commission (FERC). FERC regulatory policies govern the rates that each pipeline is permitted to charge customers for interstate transportation and storage of natural gas.

The Accounting Standards Codification (ASC) Regulated Operations (Topic 980) provides that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying Topic 980, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to customers in future periods. The accompanying financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. (See Note 9 for further discussion.)

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) litigation-related contingencies; 2) environmental remediation obligations; 3) impairment assessments of long-lived assets; 4) depreciation; and 5) asset retirement obligations.

Revenue Recognition

Revenue Recognition

Our revenues are primarily from services pursuant to long term firm transportation and storage agreements. These agreements provide for a reservation charge based on the volume of contracted capacity and a volumetric charge based on the volume of gas delivered, both at rates specified in our FERC tariffs. We recognize revenues for reservation charges ratably over the contract period regardless of the volume of natural gas that is transported or stored. Revenues for volumetric charges, from both firm and interruptible transportation services and storage injection and withdrawal services, are recognized based on volumes of natural gas scheduled for delivery at the agreed upon delivery point or based on volumes of natural gas scheduled for injection or withdrawal from the storage facility.

In the course of providing transportation services to our customers, we may receive or deliver different quantities of gas from shippers than the quantities delivered or received on behalf of those shippers. These transactions result in imbalances, which are typically settled through the receipt or delivery of gas in the future. Customer imbalances to be repaid or recovered in-kind are recorded as exchange gas due from others or due to others in the accompanying balance sheets. The difference between exchange gas due to us from customers and the exchange gas that we owe to customers is included in the exchange gas offset. These imbalances are valued at the average of the spot market rates at the Canadian border and the Rocky Mountain market as published in the SNL Financial “Bidweek Index - Spot Rates.” Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions.

As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and third-party regulatory proceedings, advice of counsel and other risks. At December 31, 2015, we had no such rate refund liabilities.

Environmental Matters

Environmental Matters

We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their future economic benefit and potential for rate recovery. We believe that expenditures required to meet applicable environmental laws and regulations are prudently incurred in the ordinary course of business and such expenditures would be permitted to be recovered through rates.

Property, Plant, and Equipment

Property, Plant, and Equipment

Property, plant and equipment (plant), consisting principally of natural gas transmission facilities, is recorded at original cost. The FERC identifies installation, construction and replacement costs that are to be capitalized and included in our asset base for recovery in rates. Routine maintenance, repairs, and renewal costs are charged to income as incurred. Gains or losses from the ordinary sale or retirement of plant are charged or credited to accumulated depreciation; certain other gains or losses are recorded in operating income.

We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2015, 2014, and 2013 are as follows:

Category of Property
Storage Facilities	1.60	%	—	2.76%
Transmission Facilities	2.80	%	—	6.97%

The incrementally priced Evergreen Expansion Project, which was an expansion of our pipeline system, was placed in service on October 1, 2003. The levelized rate design of this project creates a consistent revenue stream over the related 25-year and 15-year customer contract terms. The related levelized depreciation is lower than book depreciation in the early years and higher than book depreciation in the later years of the contract terms. The depreciation component of the levelized incremental rates will equal the accumulated book depreciation by the end of the primary contract terms. The FERC has approved the accounting for the differences between book depreciation and the Evergreen Expansion Project’s levelized depreciation as a regulatory asset.

We recorded regulatory debits totaling $2.6 million in 2015, $1.5 million in 2014, and $0.9 million in 2013 in the accompanying Statement of Comprehensive Income. These debits relate primarily to the levelized depreciation adjustment for the Evergreen Project discussed above.

We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. Measurement of AROs includes, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as market-risk premium. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and is offset by a regulatory asset. The gross regulatory asset balances associated with ARO as of December 31, 2015 and 2014 were $70.9 million and $63.7 million, respectively. The regulatory asset is expected to be fully recovered through the net negative salvage component of depreciation included in our rates; as such, the negative salvage component of accumulated depreciation ($69.3 million and $60.2 million at December 31, 2015 and 2014, respectively) has been reclassified and netted against the amount of the ARO regulatory asset.

Impairment of Long-Lived Assets

Impairment of Long-Lived Assets

We evaluate long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When such a determination has been made, our management’s estimate of undiscounted future cash flows attributable to the assets is compared to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, the amount of the impairment recognized in the financial statements is determined by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements.

Allowance for Funds Used During Construction

Allowance for Funds Used During Construction

Allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in process of construction and is included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. The FERC has prescribed a formula to be used in computing separate allowances for debt and equity AFUDC. The cost of debt portion of AFUDC was $0.5 million for 2015, $0.2 million for 2014, and $0.5 million for 2013. The equity funds portion of AFUDC was $1.1 million, $0.4 million, and $0.9 million for 2015, 2014, and 2013, respectively. Both are reflected in Other (Income) and Other Expenses.

Income Taxes

Income Taxes

We generally are not a taxable entity for federal or state and local income tax purposes. The tax on net income is generally borne by unitholders of our ultimate parent, WPZ. Net income for financial statement purposes may differ significantly from taxable income of WPZ’s unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the WPZ partnership agreement. The aggregated difference in the basis of our assets for financial and tax reporting purposes cannot be readily determined because information regarding each of WPZ’s unitholder’s tax attributes in WPZ is not available to us.

Accounts Receivable and Allowance for Doubtful Receivables

Accounts Receivable and Allowance for Doubtful Receivables

Accounts receivable are stated at the historical carrying amount net of reserves or write-offs. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers’ financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables. Receivables determined to be uncollectible are reserved or written off in the period of such determination.

Materials and Supplies Inventory

Materials and Supplies Inventory

All inventories are stated at lower of cost or market. We determine the cost of the inventories using the average cost method.

We perform an annual review of materials and supplies inventories, including an analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 2015 and 2014.

Deferred Charges

Deferred Charges

We amortize deferred charges over varying periods consistent with the FERC approved accounting treatment and recovery for such deferred items. Unamortized debt expense, debt discount and losses on reacquired long-term debt are amortized by the bonds outstanding method over the related debt repayment periods.

Pension and Other Postretirement Benefits

Pension and Other Postretirement Benefits

We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 5 for further discussion.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us, and thus paid by us, is based on our share of net periodic benefit cost.

Contingent Liabilities

Contingent Liabilities

We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third-parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.

Cash Equivalents

We include short-term, highly-liquid investments that have an original maturity of three months or less as cash equivalents.

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Financial Instruments (Policies)

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Fair value of financial instruments

Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Cash and advances to affiliate—The carrying amounts approximate fair value, because of the short-term nature of these instruments.

Long-term debt – The disclosed fair value of our long-term debt, which we consider as a level 2 measurement, is determined by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The carrying amount and estimated fair value of our long-term debt, including current maturities, were $693.4 million and $721.9 million, respectively, at December 31, 2015, and $692.5 million and $766.5 million, respectively, at December 31, 2014.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Depreciation rates

We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2015, 2014, and 2013 are as follows:

Category of Property
Storage Facilities	1.60	%	—	2.76%
Transmission Facilities	2.80	%	—	6.97%

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Debt, Financing Arrangements, and Leases (Tables)

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Long-term debt instruments

Long-term debt, presented net of unamortized discount and unamortized debt issuance costs, consists of the following:

	December 31,
	2015			2014
	(Thousands of Dollars)
5.95% senior unsecured notes due 2017	$	185,000		$	185,000
6.05% senior unsecured notes due 2018	250,000			250,000
7% senior unsecured notes due 2016	175,000			175,000
7.125% unsecured debentures due 2025	85,000			85,000
Debt issuance costs	(1,197		)	(1,932		)
Unamortized debt discount	(383		)	(580		)
Total long-term debt, including current portion	$	693,420		$	692,488
Long-term debt due within one year	174,837			—
Total long-term debt	518,583			692,488

Maturities of long-term debt

As of December 31, 2015, cumulative maturities of outstanding long-term debt (at face value) for the next five years are as follows:

	(Thousands of Dollars)
2016: 7% senior unsecured notes	$	175,000
2017: 5.95% senior unsecured notes	185,000
2018: 6.05% senior unsecured notes	250,000
Total	$	610,000

Future minimum annual rental payments

Following are the estimated future minimum annual rental payments required under operating leases, which have initial or remaining noncancelable lease terms in excess of one year:

	(Thousands of Dollars)
2016	$	2,561
2017	2,619
2018	2,679
2019	2,740
Total	$	10,599

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Transactions with Major Customers and Affiliates (Tables)

12 Months Ended

Dec. 31, 2015

Transactions with Major Customers and Affiliates [Abstract]

Schedule of revenue by major customers

During the periods presented, more than 10 percent of our operating revenues were generated from each of the following customers:

	Years Ended December 31,
	2015		2014		2013
	(Thousands of Dollars)
Puget Sound Energy, Inc.	$	118,384	$	113,398	$	110,111
Northwest Natural Gas Company	50,857		50,631		51,085
Cascade Natural Gas Corporation	48,363		(a)		(a)

(a) Under 10 percent in 2014 and 2013.

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

Schedule of change in asset retirement obligation

During 2015 and 2014, our overall asset retirement obligation changed as follows (in thousands):

	2015			2014
Beginning balance	$	94,678		$	60,753
Accretion	6,870			5,602
New obligations	2,721			157
Changes in estimates of existing obligations (1)	(21,815		)	28,171
Property Dispositions & Settlements	—			(5		)
Ending balance	$	82,454		$	94,678

(1) Changes in estimates of existing obligations are primarily due to the annual review process, which considers various factors including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining life of assets. The decrease in 2015 is primarily attributed to decreases in current estimates for removal costs and inflation rate and an increase in the discount rate. The increase in 2014 is primarily attributed to increases in current estimates for removal costs and inflation rate and a decrease in the discount rate.

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2015

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets and Liabilities [Table Text Block]

Our regulatory assets and liabilities result from our application of the provisions of Topic 980 and are reflected on our balance sheet. Current regulatory assets are included in Exchange gas offset and Prepayments and other. Current regulatory liabilities are included in Exchange gas offset. These balances are presented on our balance sheet on a gross basis and are recoverable or refundable over various periods. Below are the details of our regulatory assets and liabilities as of December 31, 2015 and 2014:

	2015			2014
	(Thousands of Dollars)
Current regulatory assets:
Environmental costs	$	1,300		$	1,300
Levelized depreciation	2,731			1,999
Fuel recovery	178			—
Total current regulatory assets	4,209			3,299
Noncurrent regulatory assets:
Environmental costs	(1,068		)	2,109
Grossed-up deferred taxes on equity funds used during construction	13,809			14,567
Levelized depreciation	26,493			29,775
Asset retirement obligations, net	1,619			3,472
Total noncurrent regulatory assets	40,853			49,923
Total regulatory assets	$	45,062		$	53,222
Current regulatory liabilities:
Fuel recovery	$	—		$	4,004
Noncurrent regulatory liabilities:
Postretirement benefits	26,802			23,375
Total regulatory liabilities	$	26,802		$	27,379

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Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2015 USD ($) employee	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Parent, total ownership percentage	60.00%
Parent, limited partner ownership percentage	58.00%
Parent, general partner ownership percentage	2.00%
Entity number of employees | employee	0
Revenue Recognition [Abstract]
Reserve for rate refund, Current	$ 0
Reserve for rate refund, Noncurrent	0
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory debits	2,550,000	$ 1,487,000	$ 921,000
Regulatory assets	40,853,000	49,923,000
Capitalized Interest Costs, Including Allowance for Funds Used During Construction [Abstract]
Allowance for funds used during construction, debt	500,000	200,000	500,000
Allowance for funds used during construction, equity	1,099,000	391,000	945,000
Interest Payments [Abstract]
Cash payments for interest, net of interest capitalized	45,300,000	44,500,000	44,600,000
Levelized depreciation [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory debits	2,600,000	1,500,000	$ 900,000
Regulatory assets	26,493,000	29,775,000
Asset retirement obligation [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets	70,900,000	63,700,000
Negative salvage [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets	$ (69,300,000)	$ (60,200,000)
Storage Facilities [Member] | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciaton rates	1.60%	1.60%	1.60%
Storage Facilities [Member] | Maximum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciaton rates	2.76%	2.76%	2.76%
Transmission Facilities [Member] | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciaton rates	2.80%	2.80%	2.80%
Transmission Facilities [Member] | Maximum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciaton rates	6.97%	6.97%	6.97%

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Rate and Regulatory Matters (Details)	12 Months Ended
	Dec. 31, 2015
Public Utilities, General Disclosures [Line Items]
Duration of effective period of rates	5 years

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Contingent Liabilities and Commitments (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Environmental Matters
Environmental assessment and remediation costs, undiscounted	$ 4.6
Accrued environmental liabilities	$ 4.6	$ 7.8

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Debt, Financing Arrangements, and Leases (Details)				12 Months Ended
	Dec. 18, 2015	Feb. 02, 2015 USD ($)	Oct. 02, 2009	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Debt Instrument [Line Items]
Debt issuance costs				$ (1,197,000)	$ (1,932,000)
Unamortized debt discount				(383,000)	(580,000)
Total long-term debt, including current portion				693,420,000	692,488,000
Long-term debt due within one year				174,837,000	0
Total long-term debt				$ 518,583,000	692,488,000
7% senior unsecured notes				7.00%
Maturities of long-term debt
2016: 7% senior unsecured notes				$ 175,000,000
2017: 5.95% senior unsecured notes				185,000,000
2018: 6.05% senior unsecured notes				250,000,000
Total				610,000,000
Line of Credit Facility [Line Items]
Lease, initial term			10 years
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2016				2,561,000
2017				2,619,000
2018				2,679,000
2019				2,740,000
Total				10,599,000
Operating Leases, Rent Expense, Net [Abstract]
Operating lease rent expense, net of sublease revenues				2,700,000	2,500,000	$ 2,300,000
Minimum [Member]
Line of Credit Facility [Line Items]
Lease, renewal term			5 years
Maximum [Member]
Line of Credit Facility [Line Items]
Lease, renewal term			10 years
Williams Partners L.P. [Member]
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity		$ 3,500,000,000
Additional amount by which credit facility can be increased		500,000,000
Line of credit facility, remaining borrowing capacity		$ 500,000,000
Maximum Ratio Of Debt To Capitalization		65.00%
Commercial paper				499,000,000
Williams Partners L.P. [Member] | Rate addition to federal funds effective rate [Member]
Line of Credit Facility [Line Items]
Line of credit facility, basis spread on variable rate		0.50%
Williams Partners L.P. [Member] | Rate addition to London interbank offered rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Line of credit facility, basis spread on variable rate		1.00%
$3.5 billion credit facility | Williams Partners L.P. [Member]
Line of Credit Facility [Line Items]
Letters of credit outstanding, amount				0
Line of credit facility, amount outstanding				1,310,000,000
Swing Line Advances [Member] | Williams Partners L.P. [Member]
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity		$ 150,000,000
Letter of credit [Member] | Williams Partners L.P. [Member]
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity		1,125,000,000
Commercial paper [Member] | Williams Partners L.P. [Member]
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity		$ 3,000,000,000
Dec 2015, Mar & Jun 2016 [Member] | Williams Partners L.P. [Member]
Line of Credit Facility [Line Items]
Maximum ratio of debt to EBITDA	5.75
Sep & Dec 2016 [Member] | Williams Partners L.P. [Member]
Line of Credit Facility [Line Items]
Maximum ratio of debt to EBITDA	5.5
Mar 2017 & Subsequent Quarters [Member] | Williams Partners L.P. [Member]
Line of Credit Facility [Line Items]
Maximum ratio of debt to EBITDA	5.0
Debt to EBITDA, after acquisitions, ratio	5.5
5.95% senior unsecured notes due 2017 [Member]
Debt Instrument [Line Items]
Long-term debt				185,000,000	185,000,000
6.05% senior unsecured notes due 2018 [Member]
Debt Instrument [Line Items]
Long-term debt				250,000,000	250,000,000
7% senior unsecured notes due 2016 [Member]
Debt Instrument [Line Items]
Long-term debt				175,000,000	175,000,000
7.125% unsecured debentures due 2025 [Member]
Debt Instrument [Line Items]
Long-term debt				$ 85,000,000	$ 85,000,000

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Debt, Financing Arrangements, and Leases Accounting Standards Issued and Adopted (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
Unamortized Debt Issuance Expense	$ 1,197	$ 1,932

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Benefit Plans (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Salaries, Wages and Officers' Compensation [Abstract]
Stock-based compensation expense	$ 1,500	$ 1,200	$ 1,200
Defined Benefit Plan Disclosure [Line Items]
Pension cost	4,400	4,200	7,800
Regulatory liabilities	26,802	23,375
Defined contribution plan matching contributions expense	2,200	2,000	2,000
Retiree health care and life insurance benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory liabilities	$ 3,400	$ 4,300	$ 1,700

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Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Carrying amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, including current maturities	$ 693.4	$ 692.5
Estimate of fair value [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, including current maturities	$ 721.9	$ 766.5

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Transactions with Major Customers and Affiliates (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Jan. 31, 2016 USD ($)	Dec. 31, 2015 USD ($) employee	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Related Party Transaction [Line Items]
Advances to affiliate		$ 171,867	$ 135,054
Related party transaction, rate		0.12%
Entity number of employees | employee		0
Related party transaction, expenses from transactions with related party		$ 100,400	102,400	$ 106,700
Cash distributions to parent		168,000	234,000	91,000
Contributions from parent		0	0	13,300
Williams Field Services [Member]
Related Party Transaction [Line Items]
Reimbursable costs		600	27,300	89,800
Related party transaction, due from (to) related party			500
Williams Partners L.P. [Member]
Related Party Transaction [Line Items]
Advances to affiliate		171,900	135,100
Subsequent Event [Member]
Related Party Transaction [Line Items]
Cash distributions to parent	$ 57,000
Puget Sound Energy, Inc. [Member]
Revenue, Major Customer [Line Items]
Operating revenues		118,384	113,398	110,111
Northwest Natural Gas Company [Member]
Revenue, Major Customer [Line Items]
Operating revenues		50,857	$ 50,631	$ 51,085
Cascade Natural Gas Corporation [Member]
Revenue, Major Customer [Line Items]
Operating revenues		$ 48,363

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 94,678	$ 60,753
Accretion	6,870	5,602
New obligations	2,721	157
Changes in estimates of existing obligations (1)	(21,815)	28,171
Property Dispositions & Settlements	0	(5)
Ending balance	$ 82,454	$ 94,678

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Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Regulatory Assets [Line Items]
Current regulatory assets	$ 4,209	$ 3,299
Noncurrent regulatory assets	40,853	49,923
Total regulatory assets	45,062	53,222
Regulatory Liabilities [Line Items]
Noncurrent regulatory liabilities	26,802	23,375
Total regulatory liabilities	26,802	27,379
Fuel recovery [Member]
Regulatory Liabilities [Line Items]
Current regulatory liabilities	0	4,004
Postretirement benefits [Member]
Regulatory Liabilities [Line Items]
Noncurrent regulatory liabilities	26,802	23,375
Environmental costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	1,300	1,300
Noncurrent regulatory assets	(1,068)	2,109
Levelized depreciation [Member]
Regulatory Assets [Line Items]
Current regulatory assets	2,731	1,999
Noncurrent regulatory assets	26,493	29,775
Fuel Recovery [Member]
Regulatory Assets [Line Items]
Current regulatory assets	178	0
Grossed-up deferred taxes on equity funds used during construction [Member]
Regulatory Assets [Line Items]
Noncurrent regulatory assets	13,809	14,567
Asset retirement obligations, net [Member]
Regulatory Assets [Line Items]
Noncurrent regulatory assets	$ 1,619	$ 3,472