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, 2013

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	15
Item 2. PROPERTIES	15
Item 3. LEGAL PROCEEDINGS	16
Item 4. MINE SAFETY DISCLOSURES	16
PART II
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	16
Item 6. SELECTED FINANCIAL DATA (Omitted)	16
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	16
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	18
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	19
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	38
Item 9A. CONTROLS AND PROCEDURES	38
Item 9B. OTHER INFORMATION	39
PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE (Omitted)	40
Item 11. EXECUTIVE COMPENSATION (Omitted)	40
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS (Omitted)	40
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE (Omitted)	40
Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES	40
PART IV
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	41

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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

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

Northwest is owned, through Williams Partners Operating LLC (WPO), by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). At December 31, 2013, Williams holds an approximate 64 percent interest in WPZ, comprised of an approximate 62 percent limited partner interest and all of WPZ’s 2 percent general partner interest.

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, 2013, we had long-term firm transportation contracts and storage redelivery agreements, with aggregate capacity reservations of approximately 3.9 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 2013, our two largest customers were Puget Sound Energy, Inc. and Northwest Natural Gas Company, which accounted for approximately 23.4 percent and 10.9 percent, respectively, of our total operating revenues for the year ended December 31, 2013. 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 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.

CAPITAL PROJECTS

South Seattle Lateral Delivery Expansion

The project to provide Puget Sound Energy an additional 64 Mdth per day of capacity on the South Seattle Lateral was put into service on November 1, 2013, at a cost of approximately $20 million.

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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. 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.

New rates became effective January 1, 2013, and will remain in effect for a minimum of 3 years and a maximum of 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;

• 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.”

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 regulates 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.

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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 the Pipeline Safety Act and has sought public comment on changes to the standards in its pipeline safety regulations.

Pipeline Integrity Regulations We have developed an Integrity Management Plan that we believe complies with the United States Department of Transportation 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 program 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 and developed our baseline assessment plan. The required pipeline segments originally identified for assessment were completed within the required timeframe.

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

Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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.

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 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 statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

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• 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:

• 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;

• 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 the result of any revisions to any of the forward-looking statements to reflect future events or developments.

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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. 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.

Risks Inherent to Our Industry and Business

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

Our operations are subject to all the risks and hazards typically associated with the transportation and storage of natural gas. These operating risks include, but are 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;

• operator error; and

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

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, discounted or negotiated rate 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 and are subject to termination. Upon expiration of the terms, we may not be able to extend 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.

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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

• our 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 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 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 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. 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

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business. Demand for natural gas is also affected by weather, future industrial and economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation, or 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 or competition in our markets may not allow us to recover 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 exceeds expectations and the FERC or competition in our markets do not allow us to recover 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 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 facilities, or our customers. 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.

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.

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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 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.

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, if at all. For the year ended December 31, 2013, our two largest customers were Puget Sound Energy, Inc. and Northwest Natural Gas Company. These customers accounted for approximately 23.4 percent and 10.9 percent, respectively, of our operating revenues for the year ended December 31, 2013. 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 may not be adequate to protect against 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 may not be adequate to fully 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. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off doubtful accounts. 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

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temporary or permanent interruption at any key pipeline interconnect 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.

Williams currently maintains excess liability insurance with limits of $610 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 (NGL) 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 recently implemented our project lifecycle process and refocused our 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;

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• 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 capital markets or obtain acceptable terms.

If realized, any of these risks 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 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.

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, 2013, was $694.2 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:

• 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 limiting our ability to expand or pursue our business activities and 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 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

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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 relationships with each of Williams and WPZ, our ability to obtain credit will be affected by Williams’ and WPZ’s credit ratings. If Williams or WPZ were to experience a deterioration in their respective credit standing or financial condition, our access to credit and our ratings could be adversely affected. Any future 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 recently been affected by concerns over U.S. fiscal policy, including uncertainty regarding federal spending and tax policy, as well as the U.S. federal government’s debt ceiling and the federal deficit. 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 manners 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.

A 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. Our ability to access capital markets could also be limited by a downgrade of our credit ratings as well as by economic, market, or other disruptions.

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

• acquisition or disposition of assets.

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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 Natural Gas Act of 1938, 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 pipelines 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 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 employees nearing retirement eligibility or with former employees might not be adequately preserved.

We expect that a significant percentage of employees will become eligible for retirement over the next three 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.

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

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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 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-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.

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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, 2013, we were owned, through WPO, by WPZ, and Williams held an approximate 64 percent interest in WPZ, comprised of an approximate 62 percent limited partner interest and all of WPZ’s 2 percent general partner interest.

We paid $91.0 million and $137.5 million in cash distributions during 2013 and 2012, 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 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

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generally accepted in the United States. The aggregate amounts of regulatory assets reflected in the Balance Sheet are $59.4 million and $62.8 million at December 31, 2013 and 2012, respectively. The aggregate amounts of regulatory liabilities reflected in the Balance Sheet are $19.9 million and $17.4 million at December 31, 2013 and 2012, 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 2013 and 2012. 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 $31.8 million, or 7 percent, as compared to 2012. This increase is primarily attributed to new rates, which became effective January 1, 2013.

Our transportation service and gas storage service accounted for 98 percent and 2 percent, respectively, of our operating revenues for 2013, and 97 percent and 3 percent, respectively, of our operating revenues for 2012.

Total operating expenses decreased $4.5 million, or 2 percent. This decrease is due primarily to i) lower labor costs of $3.8 million; ii) lower incentive compensation expense of $2.8 million; iii) lower contractual services of $2.5 million, primarily attributed to decreased expenditures on pipeline maintenance; and iv) lower group insurance expense of $2.1 million. These decreases were partially offset by i) lower capitalized labor and benefits of $2.8 million, attributed to lower capital spending; ii) higher depreciation of $2.7 million, attributed to property additions; and iii) higher charges from affiliates of $1.3 million.

The increase in our net income is primarily due to the increase in operating revenues associated with our new rates.

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 working capital and 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.

In July 2013, WPZ amended its $2.4 billion credit facility to increase the aggregate commitments to $2.5 billion and extend the maturity date to July 31, 2018. The amended credit facility may also, under certain conditions, be increased up to an additional $500 million. Total letter of credit capacity available to WPZ under the $2.5 billion credit facility is $1.3 billion. At December 31, 2013, no letters of credit have been issued and no loans are outstanding under the credit facility. We may borrow up to $500 million under the amended credit facility to the extent not otherwise utilized by WPZ and Transcontinental Gas Pipe Line Company, LLC. At December 31, 2013, the full $500 million under the credit facility was available to us.

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. The program allows a maximum outstanding amount at any time of $2 billion of unsecured commercial paper notes. At December 31, 2013, WPZ had $225 million in outstanding commercial paper.

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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, increase transmission or storage capacities from existing levels or enhance revenues. We anticipate 2014 capital expenditures will be $84 million. Of this total, $19 million is considered nondiscretionary due to legal, regulatory, and/or contractual requirements. In 2014, 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, 2013
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 discount	(776		)
Total long-term debt	$	694,224

Our total long-term debt at December 31, 2013 had a carrying value of $694.2 million and a fair market value of $806.1 million. As of December 31, 2013, the weighted-average interest rate on our long-term debt was 6.4 percent.

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	20
Statement of Comprehensive Income	21
Balance Sheet	22
Statement of Owners’ Equity	24
Statement of Cash Flows	25
Notes to Financial Statements	26

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Management Committee of

Northwest Pipeline LLC

We have audited the accompanying balance sheets of Northwest Pipeline LLC as of December 31, 2013 and 2012, 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, 2013. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule 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, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Ernst & Young LLP

Houston, Texas

February 26, 2014

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NORTHWEST PIPELINE LLC

STATEMENT OF COMPREHENSIVE INCOME

(Thousands of Dollars)

	Years Ended December 31,
	2013			2012			2011
OPERATING REVENUES	$	469,661		$	437,835		$	434,484
OPERATING EXPENSES:
General and administrative	62,473			68,997			56,226
Operation and maintenance	75,342			77,580			74,911
Depreciation	96,109			93,419			90,486
Regulatory debits (credits)	921			(494		)	(1,023		)
Taxes, other than income taxes	16,882			16,751			16,655
Total operating expenses	251,727			256,253			237,255
OPERATING INCOME	217,934			181,582			197,229
OTHER (INCOME) AND OTHER EXPENSES:
Interest expense	46,177			46,357			46,433
Allowance for equity and borrowed funds used during construction	(1,405		)	(2,291		)	(2,101		)
Miscellaneous other expenses, net	175			793			84
Total other (income) and other expenses	44,947			44,859			44,416
NET INCOME	172,987			136,723			152,813
CASH FLOW HEDGES:
Amortization of cash flow hedges into Interest expense	(62		)	(62		)	(62		)
COMPREHENSIVE INCOME	$	172,925		$	136,661		$	152,751

See accompanying notes.

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NORTHWEST PIPELINE LLC

BALANCE SHEET

(Thousands of Dollars)

	December 31, 2013		December 31, 2012
ASSETS
CURRENT ASSETS:
Cash	$	133	$	117
Receivables:
Trade	42,776		39,836
Affiliated companies	40,427		1,683
Advances to affiliate	119,168		29,322
Other	1,627		6,700
Materials and supplies, less reserves of $17 at December 31, 2013 and $81 at December 31, 2012	10,269		10,137
Exchange gas due from others	2,751		3,426
Exchange gas offset	—		1,277
Prepayments and other	3,555		3,353
Total current assets	220,706		95,851
PROPERTY, PLANT AND EQUIPMENT, at cost	3,205,576		3,163,489
Less-Accumulated depreciation	1,220,737		1,159,944
Total property, plant and equipment, net	1,984,839		2,003,545
OTHER ASSETS:
Deferred charges	6,408		7,918
Regulatory assets	58,141		60,298
Total other assets	64,549		68,216
Total assets	$	2,270,094	$	2,167,612

See accompanying notes.

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NORTHWEST PIPELINE LLC

BALANCE SHEET

(Thousands of Dollars)

	December 31, 2013		December 31, 2012
LIABILITIES AND OWNER’S EQUITY
CURRENT LIABILITIES:
Payables:
Trade	$	24,013	$	18,383
Affiliated companies	11,136		10,912
Accrued liabilities:
Taxes, other than income taxes	10,974		10,961
Interest	4,045		4,045
Exchange gas due to others	5,847		6,572
Exchange gas offset	572		—
Customer advances	6,371		2,232
Other	1,965		2,235
Total current liabilities	64,923		55,340
LONG-TERM DEBT	694,224		694,027
OTHER NONCURRENT LIABILITIES:
Asset retirement obligations	60,753		67,557
Regulatory liabilities	19,252		17,395
Other	7,479		5,055
Total other noncurrent liabilities	87,484		90,007
CONTINGENT LIABILITIES AND COMMITMENTS (Note 3)
OWNER’S EQUITY:
Owner’s capital	1,073,892		1,060,592
Retained earnings	349,419		267,432
Accumulated other comprehensive income	152		214
Total owner’s equity	1,423,463		1,328,238
Total liabilities and owner’s equity	$	2,270,094	$	2,167,612

See accompanying notes.

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STATEMENT OF OWNER’S EQUITY

(Thousands of Dollars)

	Years Ended December 31,
	2013			2012			2011
Owner’s capital:
Balance at beginning of period	$	1,060,592		$	1,051,962		$	1,046,862
Capital contributions from parent	13,300			8,630			5,100
Balance at end of period	1,073,892			1,060,592			1,051,962
Retained earnings:
Balance at beginning of period	267,432			268,209			242,396
Net income	172,987			136,723			152,813
Cash distributions to parent	(91,000		)	(137,500		)	(127,000		)
Balance at end of period	349,419			267,432			268,209
Accumulated other comprehensive income (loss):
Balance at beginning of period	214			276			338
Cash flow hedges:
Reclassification of unrecognized gain into earnings	(62		)	(62		)	(62		)
Balance at end of period	152			214			276
Total owner’s equity	$	1,423,463		$	1,328,238		$	1,320,447

See accompanying notes.

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STATEMENT OF CASH FLOWS

(Thousands of Dollars)

	Years Ended December 31,
	2013			2012			2011
OPERATING ACTIVITIES:
Net income	$	172,987		$	136,723		$	152,813
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation	96,109			93,419			90,486
Regulatory debits (credits)	921			(494		)	(1,023		)
Loss on sale of property, plant and equipment	—			—			6
Amortization of deferred charges and credits	1,720			1,578			1,491
Allowance for equity funds used during construction	(945		)	(1,564		)	(1,438		)
Changes in current assets and liabilities:
Trade and other accounts receivable	2,133			(8,291		)	270
Affiliated receivables	(38,744		)	567			(132		)
Exchange gas due from others	153			(1,262		)	402
Materials and supplies	(132		)	351			1,231
Other current assets	(202		)	116			(54		)
Trade accounts payable	(212		)	6,305			(597		)
Affiliated payables	224			2,100			(1,462		)
Exchange gas due to others	(153		)	1,262			(402		)
Other accrued liabilities	3,885			169			827
Changes in noncurrent assets and liabilities:
Deferred charges	(7,448		)	(4,015		)	(2,829		)
Noncurrent liabilities	9,819			5,442			4,769
Net cash provided by operating activities	240,115			232,406			244,358
FINANCING ACTIVITIES:
Capital contributions from parent	13,300			8,630			5,100
Cash distributions to parent	(91,000		)	(137,500		)	(127,000		)
Other	(1,318		)	329			657
Net cash used in financing activities	(79,018		)	(128,541		)	(121,243		)
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures, net of equity AFUDC*	(76,991		)	(134,330		)	(115,111		)
Proceeds from sales	5,756			7,843			(993		)
Repayments from (advances to) affiliates, net	(89,846		)	22,702			(6,979		)
Net cash used in investing activities	(161,081		)	(103,785		)	(123,083		)
NET (DECREASE) INCREASE IN CASH	16			80			32
CASH AT BEGINNING OF PERIOD	117			37			5
CASH AT END OF PERIOD	$	133		$	117		$	37
____________________________________
* Increases to property, plant and equipment	$	(84,151	)	$	(132,445	)	$	(115,677	)
Changes in related accounts payable and accrued liabilities	7,160			(1,885		)	566
Capital expenditures, net of equity AFUDC	$	(76,991	)	$	(134,330	)	$	(115,111	)

See accompanying notes.

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NORTHWEST PIPELINE LLC

NOTES TO FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure and Control

On July 1, 2013, Northwest Pipeline GP converted from a Delaware general partnership to a Delaware limited liability company, Northwest Pipeline LLC (Northwest). Following the conversion, the sole member of Northwest, Williams Partners Operating LLC (WPO), a Delaware limited liability company, executed a limited liability company operating agreement. In connection with the conversion of Northwest to a limited liability company, the Amended and Restated Partnership Agreement of Northwest Pipeline GP was terminated.

Northwest is owned, through WPO, by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). At December 31, 2013, Williams holds an approximate 64 percent interest in WPZ, comprised of an approximate 62 percent limited partner interest and all of WPZ’s 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.”

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 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.)

Basis of Presentation

Certain prior period amounts reported within Total operating expenses in the Statement of Comprehensive Income have been reclassified to conform to the current presentation. For the years ended December 31, 2012 and 2011, the effect of the correction increased Operation and maintenance costs $2.2 million in each year, increased General and administrative expenses $0.5 million in each year, and decreased Taxes, other than income taxes $2.7 million in each year, with no net impact on Total operating expenses, Operating Income, or Net Income.

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.

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NOTES TO FINANCIAL STATEMENTS

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, 2013, we had no 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. We account for repair and maintenance costs under the guidance of FERC regulations. 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, 2013, 2012 and 2011 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.

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NOTES TO FINANCIAL STATEMENTS

We recorded regulatory debits totaling $0.9 million in 2013 and regulatory credits totaling $0.5 million in 2012 and $1.0 million in 2011 in the accompanying Statement of Comprehensive Income. These debits and credits relate primarily to the levelized depreciation 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 regulatory asset is being recovered through the net negative salvage component of depreciation included in our rates, and is being amortized to expense consistent with the amounts collected in rates. The regulatory asset balances as of December 31, 2013 and 2012 were $57.9 million and $51.9 million, respectively. The full amount of the regulatory asset is expected to be recovered in future rates.

The negative salvage component of accumulated depreciation ($51.2 million and $42.4 million at December 31, 2013 and 2012, respectively) was reclassified to a noncurrent regulatory asset and has been netted against the amount of the ARO regulatory asset expected to be collected in rates.

Impairment of Long-Lived Assets

We evaluate long-lived assets for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. When such a determination has been made, 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 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 Borrowed and Equity 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 2013 and $0.7 million for 2012 and 2011. The equity funds portion of AFUDC was $0.9 million, $1.6, million and $1.4 million for 2013, 2012, and 2011, respectively. Both are reflected in Other (Income) and Other Expenses. The composite rate used to capitalize AFUDC was approximately 9 percent for 2013, 2012, and 2011.

Regulatory Allowance for Equity Funds Used During Construction

Prior to our conversion to a general partnership on October 1, 2007, we recorded a regulatory asset in connection with deferred income taxes associated with equity AFUDC. Following that conversion and continuing after our 2013 conversion to a limited liability company, we are no longer subject to income taxes. As a result, we do not record additions to the regulatory asset associated with equity AFUDC. The pre-conversion unamortized balance of this regulatory asset will continue to be amortized consistent with the amount being recovered in rates.

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.

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NOTES TO FINANCIAL STATEMENTS

Accounts Receivable and Allowance for Doubtful Receivables

Accounts receivable are stated at the historical carrying amount net of allowance for doubtful accounts. 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. As a result, 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.

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 $44.6 million in 2013, 2012, and 2011.

2. RATE AND REGULATORY MATTERS

Rate Case Settlement Filing

On April 26, 2012, the FERC unconditionally approved Northwest’s Stipulation and Settlement Agreement (Settlement) filed on March 15, 2012. The Settlement specified an annual cost of service of $466.5 million and established a new general system firm transportation rate of $0.44 per dekatherm, a 7.4 percent increase over the previous rate. New rates became effective January 1, 2013, and will remain in effect for a minimum of 3 years and a maximum of 5 years.

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NOTES TO FINANCIAL STATEMENTS

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 and mercury contamination at certain natural gas metering sites. 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. As of December 31, 2013, all of our meter stations have been remediated to Washington’s current environmental standards. In addition, assessment and remediation has been completed at seven of our thirteen compressor stations in Washington. On the basis of the findings to date, we estimate that environmental assessment and remediation costs will total approximately $8.7 million, measured on an undiscounted basis, and are expected to be incurred through 2018. At December 31, 2013 and 2012, we had accrued liabilities totaling approximately $8.7 million and $6.4 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. However, in September 2009, the EPA announced it would reconsider the 2008 NAAQS for ground-level ozone to ensure that the standards were clearly grounded in science, and were protective of both public health and the environment. As a result, the EPA delayed designation of new eight-hour ozone non-attainment areas under the 2008 standards until the reconsideration is complete. In January 2010, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels. In September 2011, the EPA announced that it was proceeding with required actions to implement the 2008 ozone standard and area designations. 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.

Additionally, in August 2010, the EPA promulgated National Emission Standards for hazardous air pollutants (NESHAP) regulations that will impact our operations. The emission control additions required to comply with the hazardous air pollutant regulations were completed in 2013, and there are estimated capital costs of $100,000 for potential modifications in 2014 to ensure compliance.

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. This standard is subject to challenges in federal court. 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.

Safety Matters

Pipeline Integrity Regulations We have developed an Integrity Management Plan that we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration final rule that was issued pursuant to the

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NOTES TO FINANCIAL STATEMENTS

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 Program 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 and developed our baseline assessment plan. The required pipeline segments originally identified for assessment were completed within the required timeframes.

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.

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.

Other Commitments

We have commitments for construction and acquisition of property, plant, and equipment of approximately $11.2 million at December 31, 2013.

4. DEBT, FINANCING ARRANGEMENTS, AND LEASES

Long-Term Debt

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

	December 31,
	2013		2012
	(Thousands of Dollars)
5.95% senior unsecured notes due 2017	$	184,790	$	184,726
6.05% senior unsecured notes due 2018	249,705		249,639
7% senior unsecured notes due 2016	174,864		174,809
7.125% unsecured debentures due 2025	84,865		84,853
Total long-term debt	$	694,224	$	694,027

As of December 31, 2013, 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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NOTES TO FINANCIAL STATEMENTS

In the second quarter of 2006, we entered into certain forward starting interest rate swaps prior to our issuance of fixed rate, long-term debt. The swaps, which were settled near the date of the June 2006 issuance of the 7% senior unsecured notes due 2016, hedged the variability of forecasted interest payments arising from changes in interest rates prior to the issuance of our fixed rate 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, 2013, 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

In July 2013, WPZ amended its $2.4 billion credit facility to increase the aggregate commitments to $2.5 billion and extend the maturity date to July 31, 2018. The amended credit facility may also, under certain conditions, be increased up to an additional $500 million. Total letter of credit capacity available to WPZ under the $2.5 billion credit facility is $1.3 billion. At December 31, 2013, no letters of credit have been issued and no loans are outstanding under the credit facility. We may borrow up to $500 million under the amended credit facility to the extent not otherwise utilized by WPZ and Transcontinental Gas Pipe Line Company, LLC. At December 31, 2013, the full $500 million under the credit facility was available to us.

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 5.0 to 1.00. For the fiscal quarter and the two following fiscal quarters in which one or more acquisitions for a total aggregate purchase price equal to or greater than $50 million has been executed, WPZ is required to maintain a ratio of debt to EBITDA of no greater than 5.5 to 1.00. At December 31, 2013, WPZ is in compliance with these financial covenants. For us, the ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent. At December 31, 2013, we are in compliance with this financial covenant.

Each time funds are borrowed, the borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.’s alternate base rate plus an applicable margin, or a periodic fixed rate equal to London Interbank Offered Rate (LIBOR) plus an applicable margin. The borrower is required to pay a commitment fee (currently 0.20 percent) 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. The credit facility contains various covenants that limit, among other things, a borrower’s and its respective 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, make investments 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 all borrowers and accelerate the maturity of any loans of the defaulting borrower under the credit facility and exercise other rights and remedies.

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. The program allows a maximum outstanding amount at any time of $2 billion of unsecured commercial paper notes. At December 31, 2013, WPZ had $225 million in outstanding commercial paper.

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.

32

NORTHWEST PIPELINE LLC

NOTES TO FINANCIAL STATEMENTS

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)
2014	$	2,344
2015	2,370
2016	2,396
2017	2,423
2018	2,449
Thereafter	2,463
Total	$	14,445

Operating lease rental expense, net of sublease revenues, amounted to $2.3 million, $2.2 million, and $2.4 million for 2013, 2012, and 2011, 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 $7.8 million in 2013, $7.3 million in 2012, and $5.7 million in 2011.

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 2013 and 2011, we received credits from Williams related to retiree health care and life insurance benefits of $1.7 million and $1.1 million, respectively. The credit in 2012 was minimal. These credits were recorded to our regulatory liability.

Defined Contribution Plan

Included in compensation expense is $2.0 million in 2013, $2.5 million in 2012, and $2.4 million in 2011 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, included in administrative and general expenses, for the years ended December 31, 2013, 2012 and 2011 was $1.2 million, $1.6 million and $1.3 million, respectively, excluding amounts allocated from WPZ and Williams.

33

NORTHWEST PIPELINE LLC

NOTES TO FINANCIAL STATEMENTS

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 $694.2 million and $806.1 million, respectively, at December 31, 2013, and $694.0 million and $840.2 million, respectively, at December 31, 2012.

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,
	2013		2012		2011
	(Thousands of Dollars)
Puget Sound Energy, Inc.	$	110,111	$	100,799	$	99,116
Northwest Natural Gas Company	51,085		47,297		47,322

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, 2013 and 2012, the advances due to us by WPZ totaled approximately $119.2 million and $29.3 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 0.01 percent at December 31, 2013. The interest income from these advances was minimal during the years ended December 31, 2013, 2012, and 2011. Such interest income is included in Other (Income) and Other Expenses: Miscellaneous other 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 $112.1 million, $113.0 million, and $98.0 million in the years ended December 31, 2013, 2012, and 2011, 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.

During the periods presented, our revenues include transportation transactions and rental of communication facilities with subsidiaries of Williams. Combined revenues for these activities, for the years ended December 31, 2013 and 2012, were minimal. Combined revenues for these activities for the year ended December 31, 2011 were $24.7 million. The reduction in revenues from 2011 is a result of Williams’ spin-off of its former exploration and production business, which was completed on December 31, 2011. These revenues, associated with transportation transactions, are now reflected with the revenues from outside parties. In

34

NORTHWEST PIPELINE LLC

NOTES TO FINANCIAL STATEMENTS

2013, we incurred reimbursable costs of $89.8 million due from Williams Field Services related to the construction of a natural gas liquids pipeline, of which $38.6 million was outstanding at December 31, 2013.

During 2013, 2012, and 2011, we declared and paid equity distributions to our parent of $91.0 million, $137.5 million, and $127.0 million, respectively. During January 2014, we declared and paid equity distributions of $52.0 million to our parent.

During 2013, 2012, and 2011, we received contributions of $13.3 million, $8.6 million, and $5.1 million from our parent to fund a portion of our expenditures for additions to property, plant, and equipment.

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 2013 and 2012, our overall asset retirement obligation changed as follows (in thousands):

	2013			2012
Beginning balance	$	67,640		$	80,313
Accretion	5,708			5,543
New obligations	51			15
Changes in estimates of existing obligations (1)	(12,577		)	(18,231		)
Property Dispositions & Settlements	(69		)	—
Ending balance	$	60,753		$	67,640

(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 2012 is primarily attributed to a decrease in removal cost estimates. The decrease in 2013 is primarily attributed to increases in the discount rate and the remaining life of the applicable property.

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, 2013 and 2012:

35

NORTHWEST PIPELINE LLC

NOTES TO FINANCIAL STATEMENTS

	2013		2012
	(Thousands of Dollars)
Current regulatory assets:
Environmental costs	$	1,300	$	1,300
Fuel recovery	—		1,249
Total current regulatory assets	1,300		2,549
Noncurrent regulatory assets:
Environmental costs	2,843		739
Grossed-up deferred taxes on equity funds used during construction	15,325		16,083
Levelized depreciation	33,261		33,979
Asset retirement obligations, net	6,712		9,497
Total noncurrent regulatory assets	58,141		60,298
Total regulatory assets	$	59,441	$	62,847
Current regulatory liabilities:
Fuel recovery	$	638	$	—
Noncurrent regulatory liabilities:
Postretirement benefits	19,047		17,395
Other	205		—
Total noncurrent regulatory liabilities	19,252		17,395
Total regulatory liabilities	$	19,890	$	17,395

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.

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.

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. 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.

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.

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 being recovered through the net negative salvage component of depreciation included in our rates, and is being amortized to expense consistent with the amounts collected in rates.

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.

36

NORTHWEST PIPELINE LLC

QUARTERLY FINANCIAL DATA

(Unaudited)

The following is a summary of unaudited quarterly financial data for 2013 and 2012:

	Quarter of 2013
	First		Second		Third		Fourth
	(Thousands of Dollars)
Operating revenues	$	118,734	$	113,853	$	115,971	$	121,103
Operating income	57,192		51,142		52,767		56,833
Net income	45,638		40,025		41,832		45,492

	Quarter of 2012
	First		Second		Third		Fourth
	(Thousands of Dollars)
Operating revenues	$	111,372	$	106,311	$	107,643	$	112,509
Operating income	49,659		42,811		42,383		46,729
Net income	38,308		31,886		31,214		35,315

37

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 Northwest 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.

Fourth Quarter 2013 Changes in Internal Controls

There have been no changes during the fourth quarter of 2013 that have materially affected, or are reasonably likely to materially affect, our Internal Controls 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 controls over financial reporting are 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, 2013, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (1992). Based on our assessment, we concluded that, as of December 31, 2013, our internal control over financial reporting was effective.

38

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.

39

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:

	2013		2012
	(Thousands of Dollars)
Audit fees	$	752	$	752
Audit related fees	—		—
Tax fees	—		—
All other fees	—		—
	$	752	$	752

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 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 2013 annual report on Form 10-K, which is available on the SEC’s website at http://www.sec.gov and on WPZ’s website at http://williamslp.com under the heading “Investors – SEC Filings.”

40

PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

	Page Reference to 2013 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, 2013, 2012, and 2011	21
Balance Sheet at December 31, 2013 and 2012	22
Statement of Owners’ Equity for the Years Ended December 31, 2013, 2012, and 2011	24
Statement of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011	25
Notes to Financial Statements	26
Schedule II – Valuation and Qualifying Accounts for the Years Ended December 31, 2013 and 2012	42
Not covered by reports of independent auditors:
Quarterly Financial Data (Unaudited)	37

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.

41

(a) 2. Financial Statement Schedules

NORTHWEST PIPELINE LLC

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

(Thousands of Dollars)

	Beginning		Charged to Costs and					Ending
Description	Balance		Expenses		Deductions			Balance
Year ended December 31, 2013:
Reserve for doubtful receivables	$	—	$	—	$	—		$	—
Reserve for obsolescence of materials and supplies	81		15		(79		)	17
Year ended December 31, 2012:
Reserve for doubtful receivables	—		—		—			—
Reserve for obsolescence of materials and supplies	816		162		(897		)	81
Year ended December 31, 2011:
Reserve for doubtful receivables	—		—		—			—
Reserve for obsolescence of materials and supplies	613		640		(437		)	816

All other schedules have been omitted because they are not required to be filed.

42

(a) 3 and b. Exhibits:

Exhibit	Description
2.1	Certificate of Conversion of Northwest Pipeline GP (Exhibit 2.1 to our report on Form 8-K, filed July 3, 2013 (File No. 001-07414)) and incorporated herein by reference.
2.2	Certificate of Formation of Northwest Pipeline LLC (Exhibit 2.2 to our report on Form 8-K, filed July 3, 2013 (File No. 001-07414)) and incorporated herein by reference.
3	Operating Agreement of Northwest Pipeline LLC (Exhibit 3.1 to our 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 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 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 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 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 report on Form 10-K, filed February 27, 2013 (File No. 001-07414)) and incorporated herein by reference.
10.3	First Amended & Restated Credit Agreement, dated as of July 31, 2013, by and among Williams Partners L.P., Northwest Pipeline LLC, and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (Exhibit 10 to Williams Partners L.P.’s Quarterly Report on Form 10-Q, filed July 31, 2013 (File No. 001-32599)) 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

43

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 GP
(Registrant)
By	/s/ Jeffrey P. Heinrichs
	Jeffrey P. Heinrichs
	Controller

Date: February 26, 2014

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/ Allison G. Bridges	Senior Vice President – West and Management Committee Member (Principal Executive Officer)
Allison G. Bridges
/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/ Donald R. Chappel	Management Committee Member
Donald R. Chappel

Date: February 26, 2014

EXHIBIT INDEX

Exhibit	Description
2.1	Certificate of Conversion of Northwest Pipeline GP (Exhibit 2.1 to our report on Form 8-K, filed July 3, 2013 (File No. 001-07414)) and incorporated herein by reference.
2.2	Certificate of Formation of Northwest Pipeline LLC (Exhibit 2.2 to our report on Form 8-K, filed July 3, 2013 (File No. 001-07414)) and incorporated herein by reference.
3	Operating Agreement of Northwest Pipeline LLC (Exhibit 3.1 to our 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 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 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 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 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 report on Form 10-K, filed February 27, 2013 (File No. 001-07414)) and incorporated herein by reference.
10.3	First Amended & Restated Credit Agreement, dated as of July 31, 2013, by and among Williams Partners L.P., Northwest Pipeline LLC, and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (Exhibit 10 to Williams Partners L.P.’s Quarterly Report on Form 10-Q, filed July 31, 2013 (File No. 001-32599)) 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.A

Exhibit 31.1

SECTION 302 CERTIFICATION

I, Allison G. Bridges, 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 26, 2014

By:	/s/ Allison G. Bridges
	Allison G. Bridges
	Sr. Vice President—West
	(Principal Executive Officer)

EX-31.B

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 26, 2014

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

EX-32.A

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, 2013 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/ Allison G. Bridges

Allison G. Bridges

Senior Vice President—West

February 26, 2014

/s/ Ted T. Timmermans

Ted T. Timmermans

Vice President and Chief Accounting Officer

February 26, 2014

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

Contingent Liabilities and Commitments (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Environmental Matters
Environmental assessment and remediation costs, undiscounted	$ 8,700,000
Accrued environmental liabilities	8,700,000	6,400,000
Estimated capital costs to comply with hazardous air pollutant regulations	100,000
Other Commitments
Commitments for construction and acquisition of property, plant, and equipment	$ 11,200,000

XML

Contingent Liabilities and Commitments (Notes)

12 Months Ended

Dec. 31, 2013

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 and mercury contamination at certain natural gas metering sites. 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. As of December 31, 2013, all of our meter stations have been remediated to Washington’s current environmental standards. In addition, assessment and remediation has been completed at seven of our thirteen compressor stations in Washington. On the basis of the findings to date, we estimate that environmental assessment and remediation costs will total approximately $8.7 million, measured on an undiscounted basis, and are expected to be incurred through 2018. At December 31, 2013 and 2012, we had accrued liabilities totaling approximately $8.7 million and $6.4 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. However, in September 2009, the EPA announced it would reconsider the 2008 NAAQS for ground-level ozone to ensure that the standards were clearly grounded in science, and were protective of both public health and the environment. As a result, the EPA delayed designation of new eight-hour ozone non-attainment areas under the 2008 standards until the reconsideration is complete. In January 2010, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels. In September 2011, the EPA announced that it was proceeding with required actions to implement the 2008 ozone standard and area designations. 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.

Additionally, in August 2010, the EPA promulgated National Emission Standards for hazardous air pollutants (NESHAP) regulations that will impact our operations. The emission control additions required to comply with the hazardous air pollutant regulations were completed in 2013, and there are estimated capital costs of $100,000 for potential modifications in 2014 to ensure compliance.

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. This standard is subject to challenges in federal court. 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.

Safety Matters

Pipeline Integrity Regulations We have developed an Integrity Management Plan that we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration 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 Program 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 and developed our baseline assessment plan. The required pipeline segments originally identified for assessment were completed within the required timeframes.

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.

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.

Other Commitments

We have commitments for construction and acquisition of property, plant, and equipment of approximately $11.2 million at December 31, 2013.

XML

Transactions with Major Customers and Affiliates (Details) (USD $)	1 Months Ended	12 Months Ended
	Jan. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]
Advances to affiliate		$ 119,168,000	$ 29,322,000
Related party transaction, rate		0.01%
Entity number of employees		0
Related party transaction, expenses from transactions with related party		112,100,000	113,000,000	98,000,000
Related party transaction, other revenues from transactions with related party				24,700,000
Equity distributions to parent		91,000,000	137,500,000	127,000,000
Contributions from parent		13,300,000	8,630,000	5,100,000
Puget Sound Energy, Inc. [Member]
Revenue, Major Customer [Line Items]
Operating revenues		110,111,000	100,799,000	99,116,000
Northwest Natural Gas Company [Member]
Revenue, Major Customer [Line Items]
Operating revenues		51,085,000	47,297,000	47,322,000
Williams Field Services [Member]
Related Party Transaction [Line Items]
Reimbursable costs		89,800,000
Related party transaction, due from (to) related party		38,600,000
Williams Partners L.P. [Member]
Related Party Transaction [Line Items]
Advances to affiliate		119,200,000	29,300,000
Williams Partners Operating LLC [Member]
Related Party Transaction [Line Items]
Equity distributions to parent	52,000,000	91,000,000	137,500,000	127,000,000
Contributions from parent		$ 13,300,000	$ 8,600,000	$ 5,100,000

XML

Financial Instruments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Carrying amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, including current maturities	$ 694.2	$ 694.0
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	$ 806.1	$ 840.2

XML

Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 67,640	$ 80,313
Accretion	5,708	5,543
New obligations	51	15
Changes in estimates of existing obligations (1)	(12,577)	(18,231)
Property Dispositions & Settlements	(69)	0
Ending balance	$ 60,753	$ 67,640

XML

Regulatory Assets and Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Regulatory Assets [Line Items]
Current regulatory assets	$ 1,300	$ 2,549
Noncurrent regulatory assets	58,141	60,298
Total regulatory assets	59,441	62,847
Regulatory Liabilities [Line Items]
Current regulatory liabilities	638	0
Noncurrent regulatory liabilities	19,252	17,395
Total regulatory liabilities	19,890	17,395
Postretirement benefits [Member]
Regulatory Liabilities [Line Items]
Noncurrent regulatory liabilities	19,047	17,395
Other [Member]
Regulatory Liabilities [Line Items]
Noncurrent regulatory liabilities	205	0
Environmental costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	1,300	1,300
Noncurrent regulatory assets	2,843	739
Fuel recovery [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0	1,249
Grossed-up deferred taxes on equity funds used during construction [Member]
Regulatory Assets [Line Items]
Noncurrent regulatory assets	15,325	16,083
Levelized depreciation [Member]
Regulatory Assets [Line Items]
Noncurrent regulatory assets	33,261	33,979
Asset retirement obligations, net [Member]
Regulatory Assets [Line Items]
Noncurrent regulatory assets	$ 6,712	$ 9,497

XML

Rate and Regulatory Matters (Notes)	12 Months Ended
	Dec. 31, 2013
Public Utilities, Rate Matters [Abstract]
Rate and Regulatory Matters	RATE AND REGULATORY MATTERSRate Case Settlement FilingOn April 26, 2012, the FERC unconditionally approved Northwest’s Stipulation and Settlement Agreement (Settlement) filed on March 15, 2012. The Settlement specified an annual cost of service of $466.5 million and established a new general system firm transportation rate of $0.44 per dekatherm, a 7.4 percent increase over the previous rate. New rates became effective January 1, 2013, and will remain in effect for a minimum of 3 years and a maximum of 5 years.

XML

Statement of Comprehensive Income (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Comprehensive Income [Abstract]
OPERATING REVENUES	$ 469,661	$ 437,835	$ 434,484
OPERATING EXPENSES:
General and administrative	62,473	68,997	56,226
Operation and maintenance	75,342	77,580	74,911
Depreciation	96,109	93,419	90,486
Regulatory debits (credits)	921	(494)	(1,023)
Taxes, other than income taxes	16,882	16,751	16,655
Total operating expenses	251,727	256,253	237,255
OPERATING INCOME	217,934	181,582	197,229
OTHER (INCOME) AND OTHER EXPENSES:
Interest expense	46,177	46,357	46,433
Allowance for equity and borrowed funds used during construction	(1,405)	(2,291)	(2,101)
Miscellaneous other expenses, net	175	793	84
Total other (income) and other expenses	44,947	44,859	44,416
NET INCOME	172,987	136,723	152,813
CASH FLOW HEDGES:
Amortization of cash flow hedges into Interest expense	(62)	(62)	(62)
COMPREHENSIVE INCOME	$ 172,925	$ 136,661	$ 152,751

XML

Statement of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
OPERATING ACTIVITIES:
Net income	$ 172,987	$ 136,723	$ 152,813
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation	96,109	93,419	90,486
Regulatory debits (credits)	921	(494)	(1,023)
Loss on sale of property, plant and equipment	0	0	6
Amortization of deferred charges and credits	1,720	1,578	1,491
Allowance for equity funds used during construction	(945)	(1,564)	(1,438)
Changes in current assets and liabilities:
Trade and other accounts receivable	2,133	(8,291)	270
Affiliated receivables	(38,744)	567	(132)
Exchange gas due from others	153	(1,262)	402
Materials and supplies	(132)	351	1,231
Other current assets	(202)	116	(54)
Trade accounts payable	(212)	6,305	(597)
Affiliated payables	224	2,100	(1,462)
Exchange gas due to others	(153)	1,262	(402)
Other accrued liabilities	3,885	169	827
Changes in noncurrent assets and liabilities:
Deferred charges	(7,448)	(4,015)	(2,829)
Noncurrent liabilities	9,819	5,442	4,769
Net cash provided by operating activities	240,115	232,406	244,358
FINANCING ACTIVITIES:
Capital contributions from parent	13,300	8,630	5,100
Cash distributions to parent	(91,000)	(137,500)	(127,000)
Other	(1,318)	329	657
Net cash used in financing activities	(79,018)	(128,541)	(121,243)
Property, plant and equipment:
Capital expenditures, net of equity AFUDC	(76,991)	(134,330)	(115,111)
Proceeds from sales	5,756	7,843	(993)
Repayments from (advances to) affiliates, net	(89,846)	22,702	(6,979)
Net cash used in investing activities	(161,081)	(103,785)	(123,083)
NET (DECREASE) INCREASE IN CASH	16	80	32
CASH AT BEGINNING OF PERIOD	117	37	5
CASH AT END OF PERIOD	133	117	37
Supplemental Cash Flow Elements [Abstract]
Increases to property, plant and equipment	(84,151)	(132,445)	(115,677)
Changes in related accounts payable and accrued liabilities	7,160	(1,885)	566
Capital expenditures, net of equity AFUDC	$ (76,991)	$ (134,330)	$ (115,111)

XML

Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2013

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, 2013 and 2012:

	2013		2012
	(Thousands of Dollars)
Current regulatory assets:
Environmental costs	$	1,300	$	1,300
Fuel recovery	—		1,249
Total current regulatory assets	1,300		2,549
Noncurrent regulatory assets:
Environmental costs	2,843		739
Grossed-up deferred taxes on equity funds used during construction	15,325		16,083
Levelized depreciation	33,261		33,979
Asset retirement obligations, net	6,712		9,497
Total noncurrent regulatory assets	58,141		60,298
Total regulatory assets	$	59,441	$	62,847
Current regulatory liabilities:
Fuel recovery	$	638	$	—
Noncurrent regulatory liabilities:
Postretirement benefits	19,047		17,395
Other	205		—
Total noncurrent regulatory liabilities	19,252		17,395
Total regulatory liabilities	$	19,890	$	17,395

XML

Rate and Regulatory Matters (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Public Utilities, General Disclosures [Line Items]
Annual cost of service	$ 466.5
General system firm transportation rate, per unit	0.44
General system firm transportation rate, percentage	7.40%
Minimum [Member]
Public Utilities, General Disclosures [Line Items]
Duration of effective period of rates	3 years
Maximum [Member]
Public Utilities, General Disclosures [Line Items]
Duration of effective period of rates	5 years

XML

Summary of Significant Accounting Policies (Notes)

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure and Control

On July 1, 2013, Northwest Pipeline GP converted from a Delaware general partnership to a Delaware limited liability company, Northwest Pipeline LLC (Northwest). Following the conversion, the sole member of Northwest, Williams Partners Operating LLC (WPO), a Delaware limited liability company, executed a limited liability company operating agreement. In connection with the conversion of Northwest to a limited liability company, the Amended and Restated Partnership Agreement of Northwest Pipeline GP was terminated.

Northwest is owned, through WPO, by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). At December 31, 2013, Williams holds an approximate 64 percent interest in WPZ, comprised of an approximate 62 percent limited partner interest and all of WPZ’s 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.”

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 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.)

Basis of Presentation

Certain prior period amounts reported within Total operating expenses in the Statement of Comprehensive Income have been reclassified to conform to the current presentation. For the years ended December 31, 2012 and 2011, the effect of the correction increased Operation and maintenance costs $2.2 million in each year, increased General and administrative expenses $0.5 million in each year, and decreased Taxes, other than income taxes $2.7 million in each year, with no net impact on Total operating expenses, Operating Income, or Net Income.

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, 2013, we had no 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. We account for repair and maintenance costs under the guidance of FERC regulations. 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, 2013, 2012 and 2011 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 $0.9 million in 2013 and regulatory credits totaling $0.5 million in 2012 and $1.0 million in 2011 in the accompanying Statement of Comprehensive Income. These debits and credits relate primarily to the levelized depreciation 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 regulatory asset is being recovered through the net negative salvage component of depreciation included in our rates, and is being amortized to expense consistent with the amounts collected in rates. The regulatory asset balances as of December 31, 2013 and 2012 were $57.9 million and $51.9 million, respectively. The full amount of the regulatory asset is expected to be recovered in future rates.

The negative salvage component of accumulated depreciation ($51.2 million and $42.4 million at December 31, 2013 and 2012, respectively) was reclassified to a noncurrent regulatory asset and has been netted against the amount of the ARO regulatory asset expected to be collected in rates.

Impairment of Long-Lived Assets

We evaluate long-lived assets for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. When such a determination has been made, 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 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 Borrowed and Equity 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 2013 and $0.7 million for 2012 and 2011. The equity funds portion of AFUDC was $0.9 million, $1.6, million and $1.4 million for 2013, 2012, and 2011, respectively. Both are reflected in Other (Income) and Other Expenses. The composite rate used to capitalize AFUDC was approximately 9 percent for 2013, 2012, and 2011.

Regulatory Allowance for Equity Funds Used During Construction

Prior to our conversion to a general partnership on October 1, 2007, we recorded a regulatory asset in connection with deferred income taxes associated with equity AFUDC. Following that conversion and continuing after our 2013 conversion to a limited liability company, we are no longer subject to income taxes. As a result, we do not record additions to the regulatory asset associated with equity AFUDC. The pre-conversion unamortized balance of this regulatory asset will continue to be amortized consistent with the amount being recovered in rates.

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 allowance for doubtful accounts. 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. As a result, 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.

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 $44.6 million in 2013, 2012, and 2011.

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Balance Sheet (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
CURRENT ASSETS:
Cash	$ 133	$ 117
Receivables:
Trade	42,776	39,836
Affiliated companies	40,427	1,683
Advances to affiliate	119,168	29,322
Other	1,627	6,700
Materials and supplies, less reserves of $17 at December 31, 2013 and $81 at December 31, 2012	10,269	10,137
Exchange gas due from others	2,751	3,426
Exchange gas offset	0	1,277
Prepayments and other	3,555	3,353
Total current assets	220,706	95,851
PROPERTY, PLANT AND EQUIPMENT, at cost	3,205,576	3,163,489
Less-Accumulated depreciation	1,220,737	1,159,944
Total property, plant and equipment, net	1,984,839	2,003,545
OTHER ASSETS:
Deferred charges	6,408	7,918
Regulatory assets	58,141	60,298
Total other assets	64,549	68,216
Total assets	2,270,094	2,167,612
Payables:
Trade	24,013	18,383
Affiliated companies	11,136	10,912
Accrued liabilities:
Taxes, other than income taxes	10,974	10,961
Interest	4,045	4,045
Exchange gas due to others	5,847	6,572
Exchange gas offset	572	0
Customer advances	6,371	2,232
Other	1,965	2,235
Total current liabilities	64,923	55,340
LONG-TERM DEBT	694,224	694,027
OTHER NONCURRENT LIABILITIES:
Asset retirement obligations	60,753	67,557
Regulatory liabilities	19,252	17,395
Other	7,479	5,055
Total other noncurrent liabilities	87,484	90,007
CONTINGENT LIABILITIES AND COMMITMENTS (Note 3)
OWNER'S EQUITY:
Owner's capital	1,073,892	1,060,592
Retained earnings	349,419	267,432
Accumulated other comprehensive income	152	214
Total owner's equity	1,423,463	1,328,238
Total liabilities and owner's equity	$ 2,270,094	$ 2,167,612

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Financial Instruments (Policies)

12 Months Ended

Dec. 31, 2013

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 $694.2 million and $806.1 million, respectively, at December 31, 2013, and $694.0 million and $840.2 million, respectively, at December 31, 2012.

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 26, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	Northwest Pipeline LLC
Entity Central Index Key	0000110019
Document Type	10-K
Document Period End Date	Dec. 31, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
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

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

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, 2013, 2012 and 2011 are as follows:

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

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Balance Sheet (Parenthetical) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
ASSETS
Reserves, materials and supplies	$ 17	$ 81

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Financial Instruments (Notes)

12 Months Ended

Dec. 31, 2013

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 $694.2 million and $806.1 million, respectively, at December 31, 2013, and $694.0 million and $840.2 million, respectively, at December 31, 2012.

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Benefit Plans (Notes)

12 Months Ended

Dec. 31, 2013

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 $7.8 million in 2013, $7.3 million in 2012, and $5.7 million in 2011.

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 2013 and 2011, we received credits from Williams related to retiree health care and life insurance benefits of $1.7 million and $1.1 million, respectively. The credit in 2012 was minimal. These credits were recorded to our regulatory liability.

Defined Contribution Plan

Included in compensation expense is $2.0 million in 2013, $2.5 million in 2012, and $2.4 million in 2011 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, included in administrative and general expenses, for the years ended December 31, 2013, 2012 and 2011 was $1.2 million, $1.6 million and $1.3 million, respectively, excluding amounts allocated from WPZ and Williams.

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Summary of Significant Accounting Policies (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 employee	Dec. 31, 2012	Dec. 31, 2011
Corporate Structure and Control
Parent, total ownership percentage	64.00%
Parent, limited partner ownership percentage	62.00%
Parent, general partner ownership percentage	2.00%
Entity number of employees	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 (credits)	921,000	(494,000)	(1,023,000)
Regulatory assets	58,141,000	60,298,000
Capitalized Interest Costs, Including Allowance for Funds Used During Construction [Abstract]
Allowance for funds used during construction, debt	500,000	700,000	700,000
Allowance for funds used during construction, equity	945,000	1,564,000	1,438,000
Allowance for funds used during construction, composite rate	9.00%	9.00%	9.00%
Interest Payments [Abstract]
Cash payments for interest, net of interest capitalized	44,600,000	44,600,000	44,600,000
Levelized depreciation [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory debits (credits)	900,000	(500,000)	(1,000,000)
Regulatory assets	33,261,000	33,979,000
Asset retirement obligation [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets	57,900,000	51,900,000
Negative salvage [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets	(51,200,000)	(42,400,000)
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%
Operation and maintenance [Member]
Prior Period Reclassification Adjustment [Line Items]
Prior period reclassification adjustment		(2,200,000)	(2,200,000)
General and administrative [Member]
Prior Period Reclassification Adjustment [Line Items]
Prior period reclassification adjustment		(500,000)	(500,000)
Taxes other than income [Member]
Prior Period Reclassification Adjustment [Line Items]
Prior period reclassification adjustment		2,700,000	2,700,000
Total operating expenses [Member]
Prior Period Reclassification Adjustment [Line Items]
Prior period reclassification adjustment		0	0
Operating Income [Member]
Prior Period Reclassification Adjustment [Line Items]
Prior period reclassification adjustment		0	0
Net Income [Member]
Prior Period Reclassification Adjustment [Line Items]
Prior period reclassification adjustment		$ 0	$ 0

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Debt, Financing Arrangements, and Leases (Tables)

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Long-term debt instruments

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

	December 31,
	2013		2012
	(Thousands of Dollars)
5.95% senior unsecured notes due 2017	$	184,790	$	184,726
6.05% senior unsecured notes due 2018	249,705		249,639
7% senior unsecured notes due 2016	174,864		174,809
7.125% unsecured debentures due 2025	84,865		84,853
Total long-term debt	$	694,224	$	694,027

Maturities of long-term debt

As of December 31, 2013, 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

Leases [Abstract]

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)
2014	$	2,344
2015	2,370
2016	2,396
2017	2,423
2018	2,449
Thereafter	2,463
Total	$	14,445

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Regulatory Assets and Liabilities (Notes)

12 Months Ended

Dec. 31, 2013

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, 2013 and 2012:

	2013		2012
	(Thousands of Dollars)
Current regulatory assets:
Environmental costs	$	1,300	$	1,300
Fuel recovery	—		1,249
Total current regulatory assets	1,300		2,549
Noncurrent regulatory assets:
Environmental costs	2,843		739
Grossed-up deferred taxes on equity funds used during construction	15,325		16,083
Levelized depreciation	33,261		33,979
Asset retirement obligations, net	6,712		9,497
Total noncurrent regulatory assets	58,141		60,298
Total regulatory assets	$	59,441	$	62,847
Current regulatory liabilities:
Fuel recovery	$	638	$	—
Noncurrent regulatory liabilities:
Postretirement benefits	19,047		17,395
Other	205		—
Total noncurrent regulatory liabilities	19,252		17,395
Total regulatory liabilities	$	19,890	$	17,395

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.

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.

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. 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.

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.

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 being recovered through the net negative salvage component of depreciation included in our rates, and is being amortized to expense consistent with the amounts collected in rates.

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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Transactions with Major Customers and Affiliates (Notes)

12 Months Ended

Dec. 31, 2013

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,
	2013		2012		2011
	(Thousands of Dollars)
Puget Sound Energy, Inc.	$	110,111	$	100,799	$	99,116
Northwest Natural Gas Company	51,085		47,297		47,322

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, 2013 and 2012, the advances due to us by WPZ totaled approximately $119.2 million and $29.3 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 0.01 percent at December 31, 2013. The interest income from these advances was minimal during the years ended December 31, 2013, 2012, and 2011. Such interest income is included in Other (Income) and Other Expenses: Miscellaneous other 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 $112.1 million, $113.0 million, and $98.0 million in the years ended December 31, 2013, 2012, and 2011, 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.

During the periods presented, our revenues include transportation transactions and rental of communication facilities with subsidiaries of Williams. Combined revenues for these activities, for the years ended December 31, 2013 and 2012, were minimal. Combined revenues for these activities for the year ended December 31, 2011 were $24.7 million. The reduction in revenues from 2011 is a result of Williams’ spin-off of its former exploration and production business, which was completed on December 31, 2011. These revenues, associated with transportation transactions, are now reflected with the revenues from outside parties. In 2013, we incurred reimbursable costs of $89.8 million due from Williams Field Services related to the construction of a natural gas liquids pipeline, of which $38.6 million was outstanding at December 31, 2013.

During 2013, 2012, and 2011, we declared and paid equity distributions to our parent of $91.0 million, $137.5 million, and $127.0 million, respectively. During January 2014, we declared and paid equity distributions of $52.0 million to our parent.

During 2013, 2012, and 2011, we received contributions of $13.3 million, $8.6 million, and $5.1 million from our parent to fund a portion of our expenditures for additions to property, plant, and equipment.

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, 2013

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 2013 and 2012, our overall asset retirement obligation changed as follows (in thousands):

	2013			2012
Beginning balance	$	67,640		$	80,313
Accretion	5,708			5,543
New obligations	51			15
Changes in estimates of existing obligations (1)	(12,577		)	(18,231		)
Property Dispositions & Settlements	(69		)	—
Ending balance	$	60,753		$	67,640

(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 2012 is primarily attributed to a decrease in removal cost estimates. The decrease in 2013 is primarily attributed to increases in the discount rate and the remaining life of the applicable property.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

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 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.)

Basis of Presentation

Basis of Presentation

Certain prior period amounts reported within Total operating expenses in the Statement of Comprehensive Income have been reclassified to conform to the current presentation. For the years ended December 31, 2012 and 2011, the effect of the correction increased Operation and maintenance costs $2.2 million in each year, increased General and administrative expenses $0.5 million in each year, and decreased Taxes, other than income taxes $2.7 million in each year, with no net impact on Total operating expenses, Operating Income, or Net Income.

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, 2013, we had no 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. We account for repair and maintenance costs under the guidance of FERC regulations. 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, 2013, 2012 and 2011 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 $0.9 million in 2013 and regulatory credits totaling $0.5 million in 2012 and $1.0 million in 2011 in the accompanying Statement of Comprehensive Income. These debits and credits relate primarily to the levelized depreciation 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 regulatory asset is being recovered through the net negative salvage component of depreciation included in our rates, and is being amortized to expense consistent with the amounts collected in rates. The regulatory asset balances as of December 31, 2013 and 2012 were $57.9 million and $51.9 million, respectively. The full amount of the regulatory asset is expected to be recovered in future rates.

The negative salvage component of accumulated depreciation ($51.2 million and $42.4 million at December 31, 2013 and 2012, respectively) was reclassified to a noncurrent regulatory asset and has been netted against the amount of the ARO regulatory asset expected to be collected in rates.

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 management’s judgment, that the carrying value of such assets may not be recoverable. When such a determination has been made, 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 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 Borrowed and Equity Funds Used During Construction

Allowance for Borrowed and Equity 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 2013 and $0.7 million for 2012 and 2011. The equity funds portion of AFUDC was $0.9 million, $1.6, million and $1.4 million for 2013, 2012, and 2011, respectively. Both are reflected in Other (Income) and Other Expenses. The composite rate used to capitalize AFUDC was approximately 9 percent for 2013, 2012, and 2011.

Regulatory Allowance for Equity Funds Used During Construction

Prior to our conversion to a general partnership on October 1, 2007, we recorded a regulatory asset in connection with deferred income taxes associated with equity AFUDC. Following that conversion and continuing after our 2013 conversion to a limited liability company, we are no longer subject to income taxes. As a result, we do not record additions to the regulatory asset associated with equity AFUDC. The pre-conversion unamortized balance of this regulatory asset will continue to be amortized consistent with the amount being recovered in rates.

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 allowance for doubtful accounts. 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. As a result, 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.

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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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Schedule of change in asset retirement obligation

During 2013 and 2012, our overall asset retirement obligation changed as follows (in thousands):

	2013			2012
Beginning balance	$	67,640		$	80,313
Accretion	5,708			5,543
New obligations	51			15
Changes in estimates of existing obligations (1)	(12,577		)	(18,231		)
Property Dispositions & Settlements	(69		)	—
Ending balance	$	60,753		$	67,640

(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 2012 is primarily attributed to a decrease in removal cost estimates. The decrease in 2013 is primarily attributed to increases in the discount rate and the remaining life of the applicable property.

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Debt, Financing Arrangements, and Leases (Details) (USD $)	0 Months Ended	12 Months Ended			0 Months Ended				12 Months Ended		12 Months Ended
	Oct. 02, 2009	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Oct. 02, 2009 Minimum [Member]	Oct. 02, 2009 Maximum [Member]	Dec. 31, 2013 Williams Partners L.P. [Member]	Jul. 31, 2013 $2.4 billion credit facility [Member] Williams Partners L.P. [Member]	Dec. 31, 2013 $2.5 billion credit facility [Member]	Jul. 31, 2013 $2.5 billion credit facility [Member]	Dec. 31, 2013 $2.5 billion credit facility [Member] Williams Partners L.P. [Member]	Jul. 31, 2013 $2.5 billion credit facility [Member] Williams Partners L.P. [Member]	Jul. 31, 2013 $2.5 billion credit facility [Member] Williams Partners L.P. [Member] Letter of credit [Member]	Dec. 31, 2013 Commercial paper [Member] Williams Partners L.P. [Member]	Dec. 31, 2013 5.95% senior unsecured notes due 2017 [Member]	Dec. 31, 2012 5.95% senior unsecured notes due 2017 [Member]	Dec. 31, 2013 6.05% senior unsecured notes due 2018 [Member]	Dec. 31, 2012 6.05% senior unsecured notes due 2018 [Member]	Dec. 31, 2013 7% senior unsecured notes due 2016 [Member]	Dec. 31, 2012 7% senior unsecured notes due 2016 [Member]	Dec. 31, 2013 7.125% unsecured debentures due 2025 [Member]	Dec. 31, 2012 7.125% unsecured debentures due 2025 [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 694,224,000	$ 694,027,000												$ 184,790,000	$ 184,726,000	$ 249,705,000	$ 249,639,000	$ 174,864,000	$ 174,809,000	$ 84,865,000	$ 84,853,000
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]
Line of credit facility, maximum borrowing capacity								2,400,000,000		500,000,000		2,500,000,000	1,300,000,000	2,000,000,000
Additional amount by which credit facility can be increased												500,000,000
Letters of credit outstanding, amount											0
Line of credit facility, amount outstanding											0
Line of credit facility, remaining borrowing capacity									500,000,000
Debt to EBITDA, ratio											5.0
Debt to EBITDA, after acquisitions, ratio											5.5
Purchase price of acquistions increasing debt to EBITDA ratio, aggregate											50,000,000
Ratio of indebtedness to net capital		0.65
Line of credit facility, unused capacity, commitment fee percentage									0.20%
Commercial paper							225,000,000
Lease, initial term	10 years
Lease, renewal term					5 years	10 years
Leases [Abstract]
2014		2,344,000
2015		2,370,000
2016		2,396,000
2017		2,423,000
2018		2,449,000
Thereafter		2,463,000
Total		14,445,000
Operating Leases, Rent Expense, Net [Abstract]
Operating lease rent expense, net of sublease revenues		$ 2,300,000	$ 2,200,000	$ 2,400,000

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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, 2010		$ 1,046,862	$ 242,396	$ 338
Capital contributions from parent	5,100	5,100
Net income	152,813		152,813
Cash distributions to parent	(127,000)		(127,000)
Reclassification of unrecognized gain into earnings	(62)			(62)
Balance at end of period at Dec. 31, 2011	1,320,447	1,051,962	268,209	276
Capital contributions from parent	8,630	8,630
Net income	136,723		136,723
Cash distributions to parent	(137,500)		(137,500)
Reclassification of unrecognized gain into earnings	(62)			(62)
Balance at end of period at Dec. 31, 2012	1,328,238	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

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Debt, Financing Arrangements, and Leases (Notes)

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Debt, Financing Arrangements, and Leases

DEBT, FINANCING ARRANGEMENTS, AND LEASES

Long-Term Debt

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

	December 31,
	2013		2012
	(Thousands of Dollars)
5.95% senior unsecured notes due 2017	$	184,790	$	184,726
6.05% senior unsecured notes due 2018	249,705		249,639
7% senior unsecured notes due 2016	174,864		174,809
7.125% unsecured debentures due 2025	84,865		84,853
Total long-term debt	$	694,224	$	694,027

As of December 31, 2013, 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

In the second quarter of 2006, we entered into certain forward starting interest rate swaps prior to our issuance of fixed rate, long-term debt. The swaps, which were settled near the date of the June 2006 issuance of the 7% senior unsecured notes due 2016, hedged the variability of forecasted interest payments arising from changes in interest rates prior to the issuance of our fixed rate 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, 2013, 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

In July 2013, WPZ amended its $2.4 billion credit facility to increase the aggregate commitments to $2.5 billion and extend the maturity date to July 31, 2018. The amended credit facility may also, under certain conditions, be increased up to an additional $500 million. Total letter of credit capacity available to WPZ under the $2.5 billion credit facility is $1.3 billion. At December 31, 2013, no letters of credit have been issued and no loans are outstanding under the credit facility. We may borrow up to $500 million under the amended credit facility to the extent not otherwise utilized by WPZ and Transcontinental Gas Pipe Line Company, LLC. At December 31, 2013, the full $500 million under the credit facility was available to us.

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 5.0 to 1.00. For the fiscal quarter and the two following fiscal quarters in which one or more acquisitions for a total aggregate purchase price equal to or greater than $50 million has been executed, WPZ is required to maintain a ratio of debt to EBITDA of no greater than 5.5 to 1.00. At December 31, 2013, WPZ is in compliance with these financial covenants. For us, the ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent. At December 31, 2013, we are in compliance with this financial covenant.

Each time funds are borrowed, the borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.’s alternate base rate plus an applicable margin, or a periodic fixed rate equal to London Interbank Offered Rate (LIBOR) plus an applicable margin. The borrower is required to pay a commitment fee (currently 0.20 percent) 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. The credit facility contains various covenants that limit, among other things, a borrower’s and its respective 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, make investments 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 all borrowers and accelerate the maturity of any loans of the defaulting borrower under the credit facility and exercise other rights and remedies.

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. The program allows a maximum outstanding amount at any time of $2 billion of unsecured commercial paper notes. At December 31, 2013, WPZ had $225 million in outstanding commercial paper.

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)
2014	$	2,344
2015	2,370
2016	2,396
2017	2,423
2018	2,449
Thereafter	2,463
Total	$	14,445

Operating lease rental expense, net of sublease revenues, amounted to $2.3 million, $2.2 million, and $2.4 million for 2013, 2012, and 2011, respectively.

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Benefit Plans (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Pension cost	$ 7,800,000	$ 7,300,000	$ 5,700,000
Regulatory liabilities	19,252,000	17,395,000
Defined contribution plan matching contributions expense	2,000,000	2,500,000	2,400,000
Salaries, Wages and Officers' Compensation [Abstract]
Stock-based compensation expense	1,200,000	1,600,000	1,300,000
Retiree health care and life insurance benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory liabilities	$ 1,700,000		$ 1,100,000

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Transactions with Major Customers and Affiliates (Tables)

12 Months Ended

Dec. 31, 2013

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,
	2013		2012		2011
	(Thousands of Dollars)
Puget Sound Energy, Inc.	$	110,111	$	100,799	$	99,116
Northwest Natural Gas Company	51,085		47,297		47,322