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, 2018

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 every Interactive Data File required to be submitted 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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer þ Smaller reporting company ¨ Emerging growth company ¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes  ¨    No  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	7
Item 1B. UNRESOLVED STAFF COMMENTS	17
Item 2. PROPERTIES	17
Item 3. LEGAL PROCEEDINGS	17
Item 4. MINE SAFETY DISCLOSURES	18
PART II
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	19
Item 6. SELECTED FINANCIAL DATA (Omitted)	19
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	19
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	22
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	23
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	45
Item 9A. CONTROLS AND PROCEDURES	45
Item 9B. OTHER INFORMATION	46
PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE (Omitted)	47
Item 11. EXECUTIVE COMPENSATION (Omitted)	47
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS (Omitted)	47
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE (Omitted)	47
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES	47
PART IV
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	48
Item 16. FORM 10-K SUMMARY	50

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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 indirectly owned by The Williams Companies, Inc. (Williams), a publicly traded Delaware corporation. Prior to August 10, 2018, we were indirectly owned by Williams Partners L.P. (WPZ), a Delaware limited partnership which was consolidated by Williams. On August 10, 2018, Williams acquired all of the outstanding common units of WPZ held by others, merged WPZ into Williams (WPZ Merger), and Williams continued as the surviving entity.

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, 2018, 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 public utilities, municipalities, direct industrial users, electric power generators, and natural gas marketers and producers. We offer firm and interruptible transportation and storage service. Our firm transportation and storage contracts are generally long-term contracts with various expiration dates and account for the major portion of our business. During 2018, our three largest customers were Puget Sound Energy, Inc., Northwest Natural Gas Company, and Cascade Natural Gas Corporation, which accounted for approximately 26.0 percent, 11.1 percent, and 10.4 percent, respectively, of our total operating revenues for the year ended December 31, 2018. 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.

Pipeline Projects

The North Seattle Lateral Upgrade (Project) involves expanded delivery capabilities of Northwest’s North Seattle Lateral. On July 19, 2018, we received the FERC order granting a certificate of public convenience and necessity. The Project consists of the removal and replacement of approximately 5.9 miles of 8-inch diameter pipeline with new 20-inch diameter pipeline. We

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plan to place the Project into service as early as the fourth quarter of 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase the delivery capacity by approximately 159 MDth/d.

RATE MATTERS

FERC regulation requires all terms and conditions of service, including the rates charged, to be filed with and accepted by the FERC before any changes can go into effect. We establish our rates primarily through the FERC’s ratemaking process, but we also may negotiate rates with our customers pursuant to the terms of our tariff and FERC policy. Key determinants in the ratemaking process are (1) costs of providing service, including depreciation expense, (2) allowed rate of return, including the equity component of the capital structure and related income taxes, and (3) contract volume and throughput assumptions. The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the reservation and commodity rates also impact profitability. As a result of these proceedings, certain revenues may be collected subject to refund. We record estimates of rate refund liabilities considering our and third-party regulatory proceedings, advice of counsel, and other risks.

Rate Case Settlement Filing

On January 23, 2017, we filed for FERC approval a Stipulation and Settlement Agreement (Settlement) and were assigned Docket No. RP17-346. The Settlement specified an annual cost of service of $440 million and established a new general system firm Rate Schedule TF-1 (Large Customer) demand rate of $0.39294/Dth with a $0.00832 commodity rate (Phase 1) and a demand rate of $0.39033/Dth with a $0.00832 commodity rate (Phase 2). Phase 1 rates became effective January 1, 2018 and Phase 2 rates became effective October 1, 2018. The annual cost of service did not change from Phase 1 to Phase 2, but the Phase 2 rates reflect the termination of fifteen-year levelized contracts which became Rate Schedule TF-1 (Large Customer) contracts. Provisions were included in the Settlement that we can file a general rate case to place new rates into effect after October 1, 2018, and that a general rate case must be filed for new rates to become effective no later than January 1, 2023.

Tax Reform Rates charged to our customers are subject to the rate-making policies of the FERC. These policies permit an interstate pipeline to include in its cost-of-service an income tax allowance that includes a deferred income tax component. The Tax Cuts and Jobs Act signed into law on December 22, 2017 (Tax Reform), among other things, reduced the corporate federal income tax rates. As part of our Settlement discussed above, we agreed with our customers to record a regulatory asset or liability for federal income tax rate increases or decreases due to subsequent legislation, such as Tax Reform. Therefore, we have established a regulatory liability of $23.6 million plus accrued interest of $0.5 million, as of December 31, 2018, included within Regulatory Liabilities in our Balance Sheet. This liability will be amortized over a five-year period, coincidental with the next rate case going into effect.

Further, as a result of the decreased federal income tax rates, deferrals for timing differences related to accelerated tax deductions recorded on our books were reflected at the previous statutory tax rates and needed to be reduced to the new statutory tax rates. We recorded a regulatory liability for this difference. The timing and actual amount of such return will be subject to future negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing services.

FERC Income Tax Policy Revision

On March 15, 2018, the FERC issued a revised policy statement (the March 15 Statement) in Docket No. PL17-1 regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. As a result, the FERC will no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. One of the benefits of the WPZ Merger is to allow us to continue to recover an income tax allowance in our cost of service rates.

On July 18, 2018, the FERC issued an order dismissing the requests for rehearing and clarification of the revised policy statement. In addition, the FERC provided guidance that an MLP pipeline (or other pass-through entity) no longer recovering an income tax allowance pursuant to the revised policy may eliminate previously accumulated deferred income taxes (ADIT) from its cost of service instead of flowing these ADIT balances to ratepayers. This guidance, if implemented, would significantly mitigate the impact of the March 15 Statement. However, the FERC stated that the revised policy statement and such guidance do not establish a binding rule, but are instead expressions of general policy intent designed to provide guidance by notifying entities of the course of action the FERC intends to follow in future adjudications. To the extent the FERC addresses these issues in future proceedings, it will consider any arguments regarding not only the application of the revised policy to the facts of the case, but also any arguments regarding the underlying validity of the policy itself. The FERC’s guidance on ADIT likely will be

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challenged by customers and state commissions, which would result in a long period of revenue uncertainty for pipelines eliminating ADIT from their cost of service. The WPZ Merger has the additional benefit of eliminating this uncertainty.

On March 15, 2018, the FERC also issued a Notice of Proposed Rulemaking in Docket No. RM18-11 proposing a filing process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the reduction in the corporate income tax rate from Tax Reform and the revised policy statement. On July 18, 2018, the FERC issued a Final Rule in the docket, retaining the filing requirement and reaffirming the options that pipelines have to either reflect the reduced tax rate or explain why no rate change is necessary. The FERC also clarified that a natural gas company organized as a pass-through entity all of whose income or losses are consolidated on the federal income tax return of its corporate parent is considered to be subject to the federal corporate income tax, and is thus eligible for a tax allowance. We believe this Final Rule and the previously discussed WPZ Merger allow for the continued recovery of income tax allowances in Northwest Pipeline’s rates. On October 19, 2018, we filed in Docket No. RP19-106, a petition requesting that the Commission waive our FERC Form No. 501-G filing requirement under this Final Rule because the reduction in the corporate income tax in Tax Reform is already addressed in our Settlement. On November 19, 2018 FERC granted our waiver request, obviating the need to make a FERC Form No. 501-G filing.

On March 15, 2018, the FERC also issued a Notice of Inquiry in Docket No. RM18-12 seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to ADIT amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action. We are evaluating the impact of these developments and currently expect any associated impacts would be prospective and determined through subsequent rate proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform. It is reasonably possible that our future tariff-based rates collected may be adversely impacted.

REGULATION

FERC Regulation

Our interstate transmission and storage activities are subject to regulation by the FERC under the Natural Gas Act of 1938, as amended (NGA), and under the Natural Gas Policy Act of 1978, 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 for which certificates are required 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 approximately $1.3 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 underground gas storage caverns, pipelines, transportation facilities, and storage tanks;

• Damage to facilities resulting from accidents during normal operations;

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

• Blowouts, cratering, and explosions.

In addition, we may be liable for environmental damage caused by former owners or 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 current 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.

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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 our expectations,” and “Item 8. Financial Statements and Supplementary Data – Notes to Financial Statements: Note 4. 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, the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011 (Pipeline Safety Act), and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (PIPES Act), which regulate safety requirements in the design, construction, operation, and maintenance of interstate natural gas transmission facilities. The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) administers federal pipeline safety laws.

Federal pipeline safety laws authorize PHMSA 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. PHMSA 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, PHMSA performs pipeline safety inspections and has the authority to initiate enforcement actions.

Pipeline Integrity Regulations We have an enterprise-wide Gas Integrity Management Plan that we believe meets the PHMSA final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for transmission pipelines that could affect high consequence areas in the event of pipeline failure. The Integrity Management Plan includes a baseline assessment plan along with periodic reassessments to be completed within required timeframes. In meeting the integrity regulations, we identified high consequence areas as defined by the rule. Ongoing periodic reassessments and initial assessments of any new high consequence areas will be completed within the timeframes required by the rule. We estimate that the cost to be incurred in 2019 associated with this program will be approximately $15 million. 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 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 8. Transactions with Major Customers and Affiliates.”

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Item 1A. RISK FACTORS

FORWARD-LOOKING STATEMENTS

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

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

• Our and our affiliates’ future credit ratings;

• Amounts and nature of future capital expenditures;

• Expansion and growth of our business and operations;

• Expected in-service dates for capital projects;

• 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 forward-looking statements include, among others, the following:

• Availability of supplies, including lower than anticipated volumes from third parties and market demand;

• Volatility of pricing including the effect of lower than anticipated energy commodity 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 timely execute our capital projects and other investment opportunities in accordance with our capital expenditure budget;

• Our ability to successfully expand our facilities and operations;

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• Development and rate of adoption of alternative energy sources;

• Availability of adequate insurance coverage and the impact of operational and development hazards and unforeseen interruptions;

• The impact of existing and future laws and regulations (including but not limited to the Tax Cuts and Jobs Act of 2017), the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain necessary permits and approvals and achieve favorable rate proceeding outcomes;

• Our 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 and physical damage to our facilities;

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

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

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

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

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

RISK FACTORS

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

Risks Inherent to Our Industry and Business

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

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

• Aging infrastructure and mechanical problems;

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

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• Uncontrolled releases of natural gas;

• Operator error;

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

• Pollution and other environmental risks; and

• Fires, blowouts, cratering and explosions.

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

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

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

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

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

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

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

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

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

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

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

The principal elements of competition among natural gas transportation and storage assets are rates, terms of service, access to natural gas supplies, flexibility, and reliability. Although most of our pipeline system’s current capacity is fully contracted, the FERC has taken certain actions to strengthen market forces in the interstate natural gas pipeline industry that have led to increased competition throughout the industry. Similarly, a highly liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. As a result, pipeline capacity is being used more efficiently, and peaking and storage services are increasingly effective substitutes for annual pipeline capacity. As a result, we could experience some “turnback” of firm capacity as the primary terms of existing

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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, Williams and its other affiliates 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, financial condition, results of operations, and cash flows.

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

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

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

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

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

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

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

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

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our services, such costs could have a material adverse impact on our business, financial condition, results of operations and cash flows.

The operation of our businesses might be adversely affected by regulatory proceedings, 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, including those pertaining to financial assurances to be provided by our businesses in respect of potential asset decommissioning and abandonment activities, might be revised, reinterpreted or otherwise enforced in a manner which differs from prior regulatory action. New laws and regulations might also be adopted or become applicable to us, our customers or our business activities. If new laws or regulations are imposed relating to oil and gas extraction, or if additional or revised 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, our compliance costs could increase 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 and local laws and regulations governing environmental protection, endangered and threatened species, the discharge of materials into the environment, and the security of chemical and industrial facilities. Substantial costs, liabilities, delays, and other significant issues related to environmental laws and regulations are inherent in the gathering, transportation, and storage of natural gas as well as waste disposal practices and construction activities. New or amended environmental laws and regulations can also result in significant increases in capital costs we incur to comply with such laws and regulations.

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

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

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

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In addition, climate change and the costs that may be associated with its impacts and with the regulation of emissions of greenhouse gases (GHG) have the potential to affect our business. Regulatory actions by the U.S. Environmental Protection Agency (EPA) or the passage of new climate change laws or regulations could result in increased costs to operate and maintain our facilities, install new emissions controls on our facilities, or 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, or at all. For the year ended December 31, 2018, our largest customer, Puget Sound Energy, Inc., accounted for approximately 26.0 percent of our operating revenues. 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, financial condition, results of operations, and cash flows.

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

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

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

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

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

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

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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. 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 face opposition to operation and expansion of our pipelines and facilities from various individuals and groups.

We have experienced, and we anticipate that we will continue to face, opposition to the operation and expansion of our pipelines and facilities from governmental officials, environmental groups, landowners, tribal groups, local groups and other advocates. In some instances, we encounter opposition which disfavors hydrocarbon based energy supplies regardless of practical implementation or financial considerations. Opposition to our operation and expansion can take many forms, including the delay or denial of required governmental permits, organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the operation or expansion of our assets and business. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of our operations. Any such event that delays or prevents the expansion of our business, that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could adversely affect our financial condition and results of operations.

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

As part of our growth strategy, we engage in significant capital projects. We have a project lifecycle process and an investment evaluation process. These are processes we use to identify, evaluate, and execute on acquisition opportunities and capital projects. We may not always have sufficient and accurate information to identify and value potential opportunities and risks or our investment evaluation process may be incomplete or flawed. Our growth may also be dependent upon the construction of new natural gas gathering, transportation, compression, processing, or treating pipelines and facilities, as well as the expansion of existing facilities. Additional risks associated with construction may include the inability to obtain rights-of-way, skilled labor, equipment, materials, permits and other required inputs in a timely manner such that projects are completed on time and the risk that construction cost overruns could cause total project costs to exceed budgeted costs. Additional risks associated with growing our business include, among others, that:

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

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

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

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

If realized, any of these risks could have an adverse impact on our financial condition, results of operations, including the possible impairment of our assets, or cash flows.

Risks Related to Strategy and Financing

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.

Downgrades of our credit ratings increase our cost of borrowing and could require us to provide collateral to our counterparties, negatively impacting our available liquidity. In addition, our ability to access capital markets could be limited by a downgrade of our credit ratings.

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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 credit ratings agencies.

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

Substantially all of Williams’ operations are conducted through its subsidiaries. Williams’ cash flows are substantially derived from loans, dividends and distributions paid to it by its subsidiaries. Due to our relationship with Williams, our ability to obtain credit will be affected by Williams’ credit ratings. If Williams were to experience a deterioration in its respective credit standing or financial condition, our access to capital and our ratings could be adversely affected. Any downgrading of a Williams credit rating could result in a downgrading of our credit rating. A downgrading of a Williams credit rating could limit our ability to obtain financing in the future upon favorable terms, if at all.

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 (including current portion), as of December 31, 2018, was $576.2 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’ debt agreements contain similar covenants with respect to such entities and their respective subsidiaries, including us.

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

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

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

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

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

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

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

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

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

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

Williams 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 Williams, Williams 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.

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

Risks Related to Regulations That Affect Our Industry

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

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

• Transportation of natural gas in interstate commerce;

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

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

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

• Accounts and records;

• Depreciation and amortization policies;

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

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

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

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We expect that certain aspects of Tax Reform, including regulatory liabilities relating to reduced corporate federal income tax rates, could adversely impact our financial condition and our future financial results.

Tax Reform made significant changes to the U.S. federal income tax rules applicable to both individuals and entities, including among other things, a reduction in corporate federal income tax rates. The rates we charge to our customers are subject to the rate-making policies of the FERC. These policies permit us to include in our cost-of-service an income tax allowance that includes a deferred income tax component. Although we expect the decreased federal income tax rates will require us to return amounts to certain customers through future rates and have recognized a regulatory liability, the details of any regulatory implementation guidance remain uncertain.

Risks Related to Employees and Outsourcing of Support Activities

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 the 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, financial condition, results of operations, and cash flows.

A failure to attract and retain an appropriately qualified workforce could negatively impact our results of operations.

Events such as an aging workforce without appropriate replacements, mismatch of skill sets to future needs, or unavailability of contract labor may lead to operating challenges such as lack of resources, loss of knowledge, and a lengthy time period associated with skill development, including with the workforce needs associated with projects and ongoing operations. Williams’ failure to hire and adequately obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect our ability to manage and operate the businesses. If Williams is unable to successfully attract and retain an appropriately qualified workforce, results of operations could be negatively impacted.

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

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

Risks Related to Weather, Other Natural Phenomena and Business Disruption

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

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

Our business could be negatively impacted by acts of terrorism and related disruptions.

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

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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 business, financial condition, results of operations, and cash flows.

A breach of our information technology infrastructure, including a breach caused by a cybersecurity attack on us or third parties with whom we are interconnected, may interfere with the safe operation of our assets, result in the disclosure of personal or proprietary information, and harm our reputation.

We rely on our information technology infrastructure to process, transmit, and store electronic information, including information we use to safely operate our assets. In addition to the oversight of our business provided by our Management Committee, the Williams’ Board of Directors has oversight responsibility with regard to enterprise-wide assessment of the major risks inherent in its businesses including cybersecurity risks. Accordingly, the Williams’ Board of Directors reviews management’s efforts to address and mitigate such risks, including the establishment and implementation of policies to address cybersecurity threats. We have invested, and expect to continue to invest, significant time, manpower and capital in our information technology infrastructure. However, 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. While we believe that we maintain appropriate information security policies, practices, and protocols, we regularly 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 face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists”, or private individuals. We face the threat of theft and misuse of sensitive data and information, including customer and employee information. We 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. We also are subject to cybersecurity risks arising from the fact that our business operations are interconnected with third parties, including third-party pipelines, other facilities and our contractors and vendors. In addition, the breach of certain business systems could affect our ability to correctly record, process and report financial 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 or destruction of our assets, unnecessary waste, safety incidents, damage to the environment, reputational damage, potential liability, the loss of contracts, the imposition of significant costs associated with remediation and litigation, heightened regulatory scrutiny, increased insurance costs, and have a material adverse effect on our operations, financial condition, results of operations, and cash flows.

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.

Item 3. LEGAL PROCEEDINGS

On August 27, 2018, Northwest Pipeline LLC received a Notice of Violation/Cease and Desist Order from the Colorado Department of Public Health & Environment regarding certain alleged violations of the Colorado Water Quality Control Act and its General Permit under the Colorado Discharge Permit System related to its stormwater management practices at two construction sites. While the Notice of Violation does not contain an initial penalty assessment, a fine could still be issued. We have responded to the alleged violations and continue to work with the agency to resolve this matter.

The additional information called for by this item is provided in “Item 8. Financial Statements and Supplementary Data – Notes to Financial Statements: Note 4. Contingent Liabilities and Commitments.”

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Item 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

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

At December 31, 2018, we were indirectly owned by Williams.

We paid $174.0 million and $186.0 million in cash distributions during 2018 and 2017, respectively. During January 2019, we declared and paid cash distributions of $21.0 million to our parent.

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 (ASC) 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 (Loss) for the period in which the discontinuance of regulatory accounting treatment occurs, unless otherwise required to be recorded under other provisions of U.S. generally accepted accounting principles. The aggregate amount of regulatory assets reflected in the Balance Sheet is $31.0 million at December 31, 2018. The aggregate amount of regulatory liabilities reflected in the Balance Sheet is $290.4 million at December 31, 2018.

In December 2017, Tax Reform was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent. Rates charged to our customers currently permit the recovery of an income tax allowance that includes a deferred income tax component. As a result of the reduced income tax rate from Tax Reform, the WPZ Merger, as well as the collection of historical rates that reflected historical federal and state income tax rates, we expect we will be required to return amounts to certain customers through future rates and have accordingly established federal and state regulatory liabilities of $206.5 million and $12.1 million, respectively, as of December 2018. The timing and actual amount of such return will be subject to future

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negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing service.

RESULTS OF OPERATIONS

Analysis of Financial Results

This analysis discusses financial results of our operations for the years 2018 and 2017. 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 decreased $29.8 million, or 6 percent, in 2018 as compared with 2017 primarily due to the reduction of our rates as a result of the Settlement of our rate case Docket No. RP17-346 that became effective January 1, 2018. Transportation service accounted for 97 percent and gas storage service accounted for 3 percent of our operating revenues for both 2018 and 2017.

Total operating expenses decreased $176.2 million, or 38 percent, in 2018 as compared with 2017, due mostly to the absence of a $206.5 million regulatory charge related to the corporate tax rate change recorded in 2017. This reduction in expenses was partially offset by a $23.6 million regulatory charge per our Settlement related to Tax Reform and a $12.1 million regulatory charge related to establishing a regulatory liability associated with a decrease in our estimated state tax rate following the WPZ Merger.

Interest expense decreased $5.0 million, or 15 percent, in 2018 primarily as a result of lower interest rates and the timing of retirement and issuances of debt. Miscellaneous other income increased $7.1 million, or 129 percent, in 2018 compared to 2017 primarily as a result of the $5.7 million charge recorded in 2017 for the effects of the deferred taxes on equity funds used during construction.

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

Effects of Inflation

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

CAPITAL RESOURCES AND LIQUIDITY

Method of Financing

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

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.

On August 24, 2018, we issued $250 million of 4.0 percent senior unsecured notes due 2027 to investors in a private debt placement. We used the net proceeds to repay the intercompany debt owed to Williams in connection with the repayment of our 6.05 percent senior notes at their maturity on June 15, 2018 and for general corporate purposes. The notes, which are an additional issuance of the 4.0 percent senior unsecured notes due 2027 we originally issued on April 3, 2017 and subsequently exchanged for substantially identical registered notes, were issued under the Indenture, dated as of April 3, 2017, between us and The Bank of New York Mellon Trust Company, N.A., as trustee.

We, along with Williams and Transcontinental Gas Pipe Line Company, LLC (Transco), are co-borrowers under a $4.5 billion unsecured credit facility. Total letter of credit capacity available to Williams under the credit facility is $1.0 billion. We may borrow up to $500 million under the credit facility to the extent not otherwise utilized by Williams and Transco.

20

We are a participant in Williams’s cash management program, and we make advances to and receive advances from Williams. At December 31, 2018, our advances to Williams totaled approximately $180.4 million. These advances are represented by demand notes.

Please see “Item 8. Financial Statements and Supplementary Data – Notes to Financial Statements: Note 5. Debt, Financing Arrangements, and Leases – Credit Facility and Note 8. Transactions with Major Customers and Affiliates – Related Party Transactions.”

Capital Expenditures

We categorize our capital expenditures as either maintenance capital expenditures or expansion capital expenditures. Maintenance capital expenditures are those expenditures required to maintain the existing operating capacity and service capability of our assets, including replacement of system components and equipment that are worn, obsolete, completing their useful life, or necessary to remain in compliance with environmental laws and regulations. Expansion capital expenditures improve the service capability of the existing assets, extend useful lives, increase transmission or storage capacities from existing levels, reduce costs, or enhance revenues. We anticipate 2019 capital expenditures will be approximately $121 million. Of this total, approximately $45 million is considered nondiscretionary due to legal, regulatory, and/or contractual requirements. In 2019, we expect to fund our capital expenditures with cash from operations.

21

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 as shown on the following table (in thousands of dollars):

	December 31, 2018
Fixed rates on long-term debt:
7.125% unsecured debentures due 2025	$	85,000
4.0% unsecured debentures due 2027	500,000
	585,000
Unamortized debt issuance costs	(4,507		)
Unamortized debt discount	(4,325		)
Total long-term debt, including current portion	$	576,168

Our total long-term debt at December 31, 2018 had a carrying value of $576.2 million and a fair market value of $577.1 million. As of December 31, 2018, the weighted-average interest rate on our long-term debt was 4.45 percent.

22

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	24
Statement of Comprehensive Income (Loss)	25
Balance Sheet	26
Statement of Member's Equity	28
Statement of Cash Flows	29
Notes to Financial Statements	30

23

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To The Management Committee and Member of Northwest Pipeline LLC

Opinion on the Financial Statements

We have audited the accompanying balance sheet of Northwest Pipeline LLC (the Company) as of December 31, 2018 and 2017, the related statements of comprehensive income (loss), member’s equity, and cash flows for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting 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.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 1986.

Houston, Texas

February 21, 2019

24

NORTHWEST PIPELINE LLC

STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Thousands of Dollars)

	Years Ended December 31,
	2018			2017			2016
OPERATING REVENUES:
Natural gas transportation	$	430,730		$	460,934		$	460,109
Natural gas storage	12,852			12,399			13,918
Other	36			73			2
Total operating revenues	443,618			473,406			474,029
OPERATING EXPENSES:
General and administrative	50,653			54,512			52,343
Operation and maintenance	75,237			78,085			79,514
Depreciation and amortization	106,073			102,084			101,672
Regulatory debits	2,334			4,857			3,510
Taxes, other than income taxes	17,507			17,889			17,835
Regulatory charges resulting from tax rate changes	35,680			206,547			—
Other expenses, net	444			195			—
Total operating expenses	287,928			464,169			254,874
OPERATING INCOME	155,690			9,237			219,155
OTHER (INCOME) AND OTHER EXPENSES:
Interest expense	27,987			33,015			39,164
Allowance for equity and borrowed funds used during construction	(2,183		)	(1,444		)	(1,371		)
Miscellaneous other (income) expenses, net	(1,575		)	5,500			907
Total other (income) and other expenses	24,229			37,071			38,700
NET INCOME (LOSS)	131,461			(27,834		)	180,455
CASH FLOW HEDGES:
Amortization of cash flow hedges into Interest expense	—			—			(28		)
COMPREHENSIVE INCOME (LOSS)	$	131,461		$	(27,834	)	$	180,427

See accompanying notes.

25

NORTHWEST PIPELINE LLC

BALANCE SHEET

(Thousands of Dollars)

	December 31, 2018		December 31, 2017
ASSETS
CURRENT ASSETS:
Cash	$	—	$	—
Receivables:
Trade	42,143		38,884
Affiliated companies	18		1,921
Advances to affiliate	180,400		137,666
Other	970		2,618
Materials and supplies	10,046		10,084
Exchange gas due from others	4,581		2,720
Prepayments and other	8,591		6,423
Total current assets	246,749		200,316
PROPERTY, PLANT AND EQUIPMENT, at cost	3,457,982		3,396,776
Less-Accumulated depreciation	1,596,369		1,508,245
Total property, plant and equipment, net	1,861,613		1,888,531
OTHER ASSETS:
Deferred charges	1,277		934
Regulatory assets	23,992		22,747
Total other assets	25,269		23,681
Total assets	$	2,133,631	$	2,112,528

See accompanying notes.

26

NORTHWEST PIPELINE LLC

BALANCE SHEET

(Thousands of Dollars)

	December 31, 2018		December 31, 2017
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES:
Payables:
Trade	$	12,839	$	11,053
Affiliated companies	26,532		11,298
Accrued liabilities:
Taxes, other than income taxes	11,496		11,617
Interest	5,505		3,677
Exchange gas due to others	11,660		4,500
Exchange gas offset	—		1,499
Customer advances	788		2,092
Other	7,386		6,655
Long-term debt due within one year	—		249,874
Total current liabilities	76,206		302,265
LONG-TERM DEBT	576,168		331,748
OTHER NONCURRENT LIABILITIES:
Asset retirement obligations	69,350		67,100
Regulatory liabilities	290,430		246,504
Other	835		1,730
Total other noncurrent liabilities	360,615		315,334
CONTINGENT LIABILITIES AND COMMITMENTS (Note 4)
MEMBER'S EQUITY:
Member’s capital	1,073,892		1,073,892
Retained earnings	46,750		89,289
Total member’s equity	1,120,642		1,163,181
Total liabilities and member’s equity	$	2,133,631	$	2,112,528

See accompanying notes.

27

NORTHWEST PIPELINE LLC

STATEMENT OF MEMBER’S EQUITY

(Thousands of Dollars)

	Years Ended December 31,
	2018			2017			2016
MEMBER'S CAPITAL:
Balance at beginning and end of period	$	1,073,892		$	1,073,892		$	1,073,892
RETAINED EARNINGS:
Balance at beginning of period	89,289			303,123			296,668
Net income (loss)	131,461			(27,834		)	180,455
Cash distributions to parent	(174,000		)	(186,000		)	(174,000		)
Balance at end of period	46,750			89,289			303,123
ACCUMULATED OTHER COMPREHENSIVE INCOME(LOSS):
Balance at beginning of period	—			—			28
Cash flow hedges:
Reclassification of unrecognized gain into earnings	—			—			(28		)
Balance at end of period	—			—			—
Total member’s equity	$	1,120,642		$	1,163,181		$	1,377,015

See accompanying notes.

28

NORTHWEST PIPELINE LLC

STATEMENT OF CASH FLOWS

(Thousands of Dollars)

	Years Ended December 31,
	2018			2017			2016
OPERATING ACTIVITIES:
Net income (Loss)	$	131,461		$	(27,834	)	$	180,455
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation	106,073			102,084			101,672
Regulatory debits	2,334			4,857			3,510
Regulatory charges resulting from tax rate changes	35,680			206,547			—
Amortization of deferred charges and credits	954			2,687			898
Allowance for equity funds used during construction	(1,703		)	(1,104		)	(953		)
Changes in current assets and liabilities:
Trade and other accounts receivable	(1,611		)	1,798			845
Affiliated receivables	1,903			(600		)	120
Materials and supplies	39			22			77
Other current assets	4,494			(687		)	424
Trade accounts payable	1,753			271			(1,560		)
Affiliated payables	15,234			4,005			(4,666		)
Other accrued liabilities	881			1,856			(2,089		)
Changes in noncurrent assets and liabilities:
Deferred charges	(8,392		)	4,340			(7,275		)
Regulatory liabilities	2,530			3,503			3,785
Noncurrent liabilities	3,498			(3,620		)	9,025
Net cash provided by operating activities	295,128			298,125			284,268
FINANCING ACTIVITIES:
Proceeds from long-term debt	246,395			249,102			—
Retirement of long-term debt	(250,000		)	(185,000		)	(175,000		)
Payments for debt issuance costs	(2,498		)	(2,207		)	—
Cash distributions to parent	(174,000		)	(186,000		)	(174,000		)
Net cash used in financing activities	(180,103		)	(124,105		)	(349,000		)
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures, net of equity AFUDC*	(73,487		)	(81,217		)	(80,383		)
Contributions and advances for construction costs	2,075			872			1,308
Disposal of property, plant and equipment, net	(879		)	(1,146		)	(1,280		)
Advances to affiliates, net	(42,734		)	(92,529		)	126,730
Proceeds from insurance	—			—			18,188
Net cash provided by (used in) investing activities	(115,025		)	(174,020		)	64,563
NET (DECREASE) INCREASE IN CASH	—			—			(169		)
CASH AT BEGINNING OF PERIOD	—			—			169
CASH AT END OF PERIOD	$	—		$	—		$	—
____________________________________
* Increases to property, plant and equipment	$	(73,105	)	$	(80,355	)	$	(72,432	)
Changes in related accounts receivable, accounts payable, and accrued liabilities	(382		)	(862		)	(7,951		)
Capital expenditures, net of equity AFUDC	$	(73,487	)	$	(81,217	)	$	(80,383	)

See accompanying notes.

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NORTHWEST PIPELINE LLC

NOTES TO FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure and Control

Northwest Pipeline LLC (Northwest) was indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which was consolidated by The Williams Companies, Inc. (Williams). On August 10, 2018, Williams completed a merger with WPZ, pursuant to which Williams acquired all of the publicly held outstanding common units of WPZ in exchange for shares of Williams’ common stock (WPZ Merger). Williams continued as the surviving entity. Northwest is now indirectly owned by Williams.

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

We are regulated by the Federal Energy Regulatory Commission (FERC). The Accounting Standards Codification (ASC) 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.

In December 2017, the Tax Cuts and Jobs Act (Tax Reform) was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent. Rates charged to our customers currently permit the recovery of an income tax allowance that includes a deferred income tax component. As a result of the reduced income tax rate from Tax Reform, the WPZ Merger, as well as the collection of historical rates that reflected historical federal and state income tax rates, we expect we will be required to return amounts to certain customers through future rates and have accordingly established federal and state regulatory liabilities of $206.5 million and $12.1 million, respectively, as of December 2018. The timing and actual amount of such return will be subject to future negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing service. Our regulatory asset associated with the effects of deferred taxes on equity funds used during construction was also impacted by Tax Reform and was reduced by $5.7 million in December 2017 through a charge to Miscellaneous other (income) expenses, net below Operating income.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles 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; 5) asset retirement obligations; and 6) regulatory deferred tax.

30

NORTHWEST PIPELINE LLC

NOTES TO FINANCIAL STATEMENTS

Revenue Recognition (subsequent to adoption of ASC 606)

Our customers are comprised of public utilities, municipalities, direct industrial users, electric power generators, and natural gas marketers and producers.

A performance obligation is a promise in a contract to transfer a distinct good or service (or integrated package of goods or services) to the customer. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue, when, or as, the performance obligation is satisfied. A performance obligation is distinct if the service is separately identifiable from other items in the integrated package of products or services and if a customer can benefit from it on its own or with other resources that are readily available to the customer. Service revenue contracts contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance.

Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. As a rate-regulated entity applying Topic 980, we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, in our judgment, the construction activities do not represent an ongoing major and central operation of our gas pipelines business and are not within the scope of Accounting Standards Update (ASU) 2014-09, Revenues from Contracts with Customers (ASC 606). Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed assets.

Service Revenues

We are subject to regulation by certain state and federal authorities, including the FERC, with revenue derived from both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a fixed reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas scheduled, each at rates specified in our FERC tariffs or as negotiated with our customers, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended beyond the specified contract term and until terminated generally by either us or the customer, but in certain cases unilaterally by the customer, with advance notice of termination ranging from one to five years. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one month periods or less. Our performance obligations include the following:

• Firm transportation or storage under firm transportation and storage contracts - an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities;

• Interruptible transportation and storage under interruptible transportation and storage contracts - an integrated package of services typically constituting a single performance obligation once scheduled, which includes receiving, transporting or storing (as applicable), and redelivering commodities.

In situations where, in our judgment, we consider the integrated package of services as a single performance obligation, which represents a majority of our contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized over time upon satisfaction of our daily stand ready performance obligation.

We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage 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 withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We use judgment to record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks. At December 31, 2018, we had no such rate refund liabilities.

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NORTHWEST PIPELINE LLC

NOTES TO FINANCIAL STATEMENTS

In the course of providing transportation services to customers, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers or consumed in fuel to operate our system. The resulting customer imbalances are typically settled through the receipt or delivery of gas in the future based on the timelines outlined in Northwest’s Tariff, whereas the over/under recovery of fuel is cleared up through Northwest’s semi-annual fuel tracker. Customer imbalances to be repaid or recovered in-kind are recorded as Exchange gas due from others or Exchange gas due to others in our Balance Sheet. The under recovery of fuel is recorded as a Regulatory Asset and the over recovery is recorded as a Regulatory Liability. 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."

Revenue Recognition (prior to the adoption of ASC 606)

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 customers, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers or consumed in fuel to operate our system. The resulting customer imbalances are typically settled through the receipt or delivery of gas in the future based on the timelines outlined in Northwest’s Tariff, whereas the over/under recovery of fuel is cleared up through Northwest’s semi-annual fuel tracker. Customer imbalances to be repaid or recovered in-kind are recorded as Exchange gas due from others or Exchange gas due to others in our Balance Sheet. The under recovery of fuel is recorded as a Regulatory Asset and the over recovery is recorded as a Regulatory Liability. 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."

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.

Environmental Matters

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

Property, Plant, and Equipment

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

We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2018, 2017, and 2016 are as follows:

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

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NORTHWEST PIPELINE LLC

NOTES TO FINANCIAL STATEMENTS

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. The levelized period for the 15-year contracts ended September 30, 2018.

We recorded regulatory debits totaling $2.3 million in 2018, $4.9 million in 2017, and $3.5 million in 2016 in the accompanying Statement of Comprehensive Income (Loss). These debits relate primarily to the levelized depreciation adjustment for the Evergreen Project discussed above.

We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. Measurement of AROs includes, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as market-risk premium. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and is offset by a regulatory asset. The gross regulatory asset balances associated with ARO as of December 31, 2018 and 2017 were $86.4 million and $82.2 million, respectively. The regulatory asset is expected to be fully recovered through the net negative salvage component of depreciation included in our rates; as such, the negative salvage component of accumulated depreciation was ($86.4) million and ($82.2) million at December 31, 2018 and 2017, respectively, and has been reclassified and netted against the amount of the ARO regulatory asset.

Impairment of Long-Lived Assets

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

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

Allowance for Funds Used During Construction

Allowance for funds used during construction (AFUDC) represents the estimated cost of borrowed 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 borrowed and equity AFUDC. The allowance for borrowed funds used during construction was $0.5 million for 2018, $0.3 million for 2017, and $0.4 million for 2016. The allowance for equity funds was $1.7 million, $1.1 million, and $1.0 million for 2018, 2017, and 2016, respectively. Both are reflected in Other (Income) and Other Expenses.

Income Taxes

We are a natural gas company organized as a pass-through entity and our taxable income or loss is consolidated on the federal income tax return of our parent, Williams. We generally are treated as a pass-through entity for state and local income tax purposes, and those taxes are generally borne on a consolidated basis by Williams. Net income for financial statement purposes may differ significantly from taxable income of Williams as a result of differences between the tax basis and financial reporting basis of assets and liabilities.

Accounts Receivable and Allowance for Doubtful Receivables

Accounts receivable are stated at the historical carrying amount net of reserves or write-offs. We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received

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by the contractual due date. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers’ financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables. Receivables determined to be uncollectible are reserved or written off in the period of determination.

Materials and Supplies Inventory

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

We perform an annual review of materials and supplies inventories, including an analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 2018 and 2017.

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.

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.

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 6 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.

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 $25.4 million in 2018, $31.9 million in 2017, and $38.5 million in 2016.

Accounting Standards Issued and Adopted

In May 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-09 establishing ASC 606. ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard became effective for interim and annual reporting periods beginning after December 15, 2017.

We adopted the provisions of ASC 606 effective January 1, 2018, utilizing the modified retrospective transition method for all contracts with customers, which included applying the provisions of ASC 606 beginning January 1, 2018, to all contracts not

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completed as of that date. There was no cumulative effect adjustment to retained earnings upon initially applying ASC 606 for periods prior to January 1, 2018.

For each revenue contract type, we conducted a formal contract review process to evaluate the impact of ASC 606. As a result of the adoption of ASC 606, there are no changes to the timing of our revenue recognition or differences in the presentation in our financial statements from those under the previous revenue standard (See Note 2).

Accounting Standards Issued But Not Yet Adopted

In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. The standard requires varying transition methods for the different categories of amendments. We do not expect ASU 2016-13 to have a significant impact on our financial statements.

In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach to lease classification similar to current lease accounting, and causes lessees to recognize operating leases on the balance sheet as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset, with an exception for leases with a term of one year or less. Additional disclosures will also be required regarding the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01 “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842” (ASU 2018-01). Per ASU 2018-01, land easements and rights-of-way are required to be assessed under ASU 2016-02 to determine whether the arrangements are or contain a lease. ASU 2018-01 permits an entity to elect a transition practical expedient to not apply ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not previously assessed under the previous lease guidance in ASC Topic 840 “Leases.”

In July 2018, the FASB issued ASU 2018-11 “Leases (Topic 842): Targeted Improvements” (ASU 2018-11). Prior to ASU 2018-11, a modified retrospective transition was required for financing or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. ASU 2018-11 allows entities an additional transition method to the existing requirements whereby an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. ASU 2018-11 also allows a practical expedient that permits lessors to not separate non-lease components from the associated lease component if certain conditions are present. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. We adopted ASU 2016-02 effective January 1, 2019.

We are substantially complete with our review of contracts to identify leases based on the modified definition of a lease and changes to our internal controls to support management in the accounting for and disclosure of leasing activities upon adoption of ASU 2016-02. We implemented a financial lease accounting system to assist management in the accounting for leases upon adoption. We are substantially complete with the implementation of ASU 2016-02 and believe the most significant changes to our financial statements relate to the recognition of a lease liability and offsetting right-of-use asset in our Balance Sheetfor operating leases, which we estimate to be less than 3 percent of total liabilities and total assets. We have also evaluated ASU 2016-02’s available practical expedients on adoption. We generally elected to adopt the practical expedients, which includes the practical expedient to not separate lease and non-lease components by both lessees and lessors by class of underlying assets and the land easements practical expedient.

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2. REVENUE RECOGNITION

Revenue by Category

Our revenue disaggregation by major service line includes Natural gas transportation, Natural gas storage, and Other, which are separately presented on the Statement of Comprehensive Income (Loss).

We do not have any contract assets or material contract liabilities.

Remaining Performance Obligations

The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of December 31, 2018. These primarily include reservation charges on contracted capacity on our firm transportation and storage contracts with customers. Amounts from certain contracts included in the table below, which are subject to the periodic review and approval by the FERC, reflect the rates for such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based on future rate cases or settlements approved by the FERC and the amount and timing of these changes is not currently known. As a practical expedient permitted by ASC 606, this table excludes the variable consideration component for commodity charges that will be recognized in future periods. As noted above, certain of our contracts contain evergreen provisions for periods beyond the initial term of the contract. The remaining performance obligations as of December 31, 2018, does not consider potential future performance obligations for which the renewal has not been exercised. The table below also does not include contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service.

	(Thousands)
2019	$	427,705
2020	404,899
2021	378,288
2022	372,446
2023	329,338
Thereafter	1,832,771
Total	$	3,745,447

The table above excludes remaining performance obligations associated with certain contract extensions executed in February 2019. The additional performance obligations associated with these contract extensions are approximately $11 million in 2023 and $549 million thereafter.

Receivables from contracts with customers are included within Receivables - Trade andReceivables - Affiliated companies and receivables that are not related to contracts with customers comprise the balance of Receivables - Advances to affiliate and Receivables - Other in our Balance Sheet.

3. RATE AND REGULATORY MATTERS

Rate Case Settlement Filing

On January 23, 2017, we filed for FERC approval a Stipulation and Settlement Agreement (Settlement) and were assigned Docket No. RP17-346. The Settlement specified an annual cost of service of $440 million and established a new general system firm Rate Schedule TF-1 (Large Customer) demand rate of $0.39294/Dth with a $0.00832 commodity rate (Phase 1) and a demand rate of $0.39033/Dth with a $0.00832 commodity rate (Phase 2). Phase 1 rates became effective January 1, 2018 and Phase 2 rates became effective October 1, 2018. The annual cost of service did not change from Phase 1 to Phase 2, but the Phase 2 rates reflect the termination of fifteen-year levelized contracts which became Rate Schedule TF-1 (Large Customer) contracts. Provisions were included in the Settlement that we can file a general rate case to place new rates into effect after October 1, 2018, and that a general rate case must be filed for new rates to become effective no later than January 1, 2023.

Tax Reform

Rates charged to our customers are subject to the rate-making policies of the FERC. These policies permit an interstate pipeline to include in its cost-of-service an income tax allowance that includes a deferred income tax component. Tax Reform, among other things, reduced the corporate federal income tax rates. As part of our Settlement discussed above, we agreed with

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NOTES TO FINANCIAL STATEMENTS

our customers to record a regulatory asset or liability for federal income tax rate increases or decreases due to subsequent legislation, such as Tax Reform. Therefore, we have established a regulatory liability of $23.6 million plus accrued interest of $0.5 million, as of December 31, 2018, included within Regulatory Liabilities in our Balance Sheet. This liability will be amortized over a five-year period, coincidental with the next rate case going into effect.

As a result of the WPZ Merger, we also recorded a $12.1 million state tax regulatory liability associated with a decrease in our estimated state income tax rate.

FERC Developments

On March 15, 2018, the FERC issued a revised policy statement (the March 15 Statement) in Docket No. PL17-1 regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. As a result, the FERC will no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. One of the benefits of the WPZ Merger is to allow us to continue to recover an income tax allowance in our cost of service rates.

On July 18, 2018, the FERC issued an order dismissing the requests for rehearing and clarification of the revised policy statement. In addition, the FERC provided guidance that an MLP pipeline (or other pass-through entity) no longer recovering an income tax allowance pursuant to the revised policy may eliminate previously accumulated deferred income taxes (ADIT) from its cost of service instead of flowing these previously accumulated ADIT balances to ratepayers. This guidance, if implemented, would significantly mitigate the impact of the March 15 Statement. However, the FERC stated that the revised policy statement and such guidance do not establish a binding rule, but are instead expressions of general policy intent designed to provide guidance by notifying entities of the course of action the FERC intends to follow in future adjudications. To the extent the FERC addresses these issues in future proceedings, it will consider any arguments regarding not only the application of the revised policy to the facts of the case, but also any arguments regarding the underlying validity of the policy itself. The FERC's guidance on ADIT likely will be challenged by customers and state commissions, which would result in a long period of revenue uncertainty for pipelines eliminating ADIT from their cost of service. The WPZ Merger has the additional benefit of eliminating this uncertainty.

On March 15, 2018, the FERC also issued a Notice of Proposed Rulemaking in Docket No. RM18-11 proposing a filing process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the reduction in the corporate income tax rate in Tax Reform and the revised policy statement. On July 18, 2018, the FERC issued a Final Rule in the docket, retaining the filing requirement and reaffirming the options that pipelines have to either reflect the reduced tax rate or explain why no rate change is necessary. The FERC also clarified that a natural gas company organized as a pass-through entity all of whose income or losses are consolidated on the federal income tax return of its corporate parent is considered to be subject to the federal corporate income tax, and is thus eligible for a tax allowance. We believe this Final Rule and the previously discussed WPZ Merger allow for the continued recovery of income tax allowances in Northwest Pipeline’s rates. On October 19, 2018, we filed in Docket No. RP19-106, a petition requesting that the Commission waive our FERC Form No. 501-G filing requirement under this Final Rule because the reduction in the corporate income tax in Tax Reform is already addressed in our Settlement. On November 19, 2018 FERC granted our waiver request, obviating the need to make a FERC Form No. 501-G filing.

On March 15, 2018, the FERC also issued a Notice of Inquiry in Docket No. RM18-12 seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to ADIT amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action. We are evaluating the impact of these developments and currently expect any associated impacts would be prospective and determined through subsequent rate proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform. It is reasonably possible that our future tariff-based rates collected may be adversely impacted.

4. 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.

Beginning in the mid-1980s, we evaluated many of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation might be necessary. We identified polychlorinated biphenyl (PCB) contamination in air compressor systems, soils, and related properties at certain compressor station sites. Similarly, we identified hydrocarbon impacts at these facilities due to the former use of earthen pits, lubricating oil leaks or spills, and excess pipe coating released to the environment. In addition, heavy metals have been identified at these sites due to the former use of mercury containing meters and paint and welding rods containing lead, cadmium, and arsenic. The PCBs were remediated pursuant to a Consent Decree with the U.S. Environmental Protection Agency (EPA) in the late 1980s, and we conducted a voluntary clean-up of the hydrocarbon and mercury impacts in the early 1990s. In 2005, the Washington Department of Ecology required us to re-evaluate our previous clean-ups in Washington. During 2006 to 2015, 129 meter stations were evaluated, of which 82 required remediation. As of December 31, 2018, all of the meter stations have been remediated. During 2006 to 2018, 14 compressor stations were evaluated, of which 11 required remediation. As of December 31, 2018, 10 compressor stations have been remediated. On the basis of the findings to date, we estimate that environmental assessment and remediation costs will total approximately $2.0 million, measured on an undiscounted basis, and are expected to be incurred through 2026. At December 31, 2018 we had accrued liabilities totaling approximately $2.0 million, $1.3 million in current liabilities and $0.7 million in other noncurrent liabilities and at December 31, 2017 approximately $3.0 million, $1.3 million in current liabilities and $1.7 million in other noncurrent liabilities 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.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, air quality standards for one-hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. The EPA previously issued its rule regarding National Ambient Air Quality Standards for ground-level ozone. We are monitoring the rule’s implementation as it will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Property, plant, and equipment - net in the Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.

Other Matters

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

Summary

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

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NOTES TO FINANCIAL STATEMENTS

5. DEBT, FINANCING ARRANGEMENTS, AND LEASES

Long-Term Debt

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

	December 31,
	2018			2017
	(Thousands of Dollars)
6.05% senior unsecured notes due 2018	$	—		$	250,000
7.125% unsecured debentures due 2025	85,000			85,000
4.0% unsecured debentures due 2027	500,000			250,000
Debt issuance costs	(4,507		)	(2,415		)
Unamortized debt discount	(4,325		)	(963		)
Total long-term debt, including current portion	576,168			581,622
Long-term debt due within one year	—			249,874
Total long-term debt less current portion	$	576,168		$	331,748

There are no maturities applicable to long-term debt outstanding through 2023.

No property is pledged as collateral under any of our long-term debt.

Restrictive Debt Covenants

At December 31, 2018, none of our debt instruments restrict the amount of distributions to our parent, provided, however, that under the credit facility described below, we are restricted from making distributions to our parent during an event of default if we have directly incurred indebtedness under the credit facility. Our debt agreements contain restrictions on our ability to incur secured debt beyond certain levels.

Issuance and Retirement of Long-Term Debt

On August 24, 2018, we issued $250 million of 4.0 percent senior unsecured notes due 2027 to investors in a private debt placement. We used the net proceeds to repay the intercompany debt owed to Williams in connection with the repayment of our 6.05 percent senior notes at their maturity on June 15, 2018 and for general corporate purposes. The notes, which are an additional issuance of the 4.0 percent senior unsecured notes due 2027 we originally issued on April 3, 2017 and subsequently exchanged for substantially identical registered notes, were issued under the Indenture, dated as of April 3, 2017, between us and The Bank of New York Mellon Trust Company, N.A., as trustee. As part of the issuance we entered into a registration rights agreement with the initial purchasers of the notes. Under the terms of the agreement, we were obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act within 365 days after closing and to use commercially reasonable efforts to complete the exchange offer. We filed a registration statement, which was subsequently declared effective by the SEC, and consummated the exchange offer in the fourth quarter of 2018.

On April 3, 2017, we issued $250 million of 4.0 percent senior unsecured notes due 2027 to investors in a private debt placement. We used the net proceeds to retire $185 million of 5.95 percent senior unsecured notes that matured on April 15, 2017, and for general corporate purposes. We filed a registration statement, which the SEC declared effective in January 2018, and consummated the exchange offer in the first quarter of 2018.

Credit Facility

On July 13, 2018, we, along with Williams and Transco (the “borrowers”), the lenders named therein, and an administrative agent entered into a Credit Agreement with aggregate commitments available of $4.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. We and Transco are each subject to a $500 million borrowing sublimit. The facility made available under the Credit Agreement is initially available for five years from the Credit Agreement Effective Date (the “Maturity Date”). The borrowers may request an extension of the Maturity Date for an additional one-

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NOTES TO FINANCIAL STATEMENTS

year period up to two times, to allow a Maturity Date as late as the seventh anniversary of the Credit Agreement Effective Date, subject to certain conditions. The Credit Agreement allows for same day swingline borrowings up to an aggregate amount of $200 million, subject to other utilization of the aggregate commitments under the Credit Agreement. Letter of credit commitments of $1.0 billion are, subject to the $500 million borrowing sublimit applicable to us and Transco, available to the borrowers. At December 31, 2018, no letters of credit have been issued and loans to Williams of $160 million were outstanding under the credit facility.

Measured as of December 31, 2018, we are in compliance with our financial covenant under the credit facility.

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

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

Other than swing line loans, each time funds are borrowed, the applicable 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 the London Interbank Offered Rate plus an applicable margin. We are required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on the applicable borrower's senior unsecured long-term debt ratings.

Williams participates in a commercial paper program, and Williams 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 anytime of $4 billion of unsecured commercial paper notes. At December 31, 2018, Williams had no outstanding commercial paper.

Lease Obligations

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 had an initial term of approximately 10 years, and in May 2018 was renewed for an additional 10 years, expiring December 31, 2029.

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)
2019	$	1,942
2020	1,968
2021	1,920
2022	1,909
2023	1,832
Thereafter	11,508
Total	$	21,079

Operating lease rental expense, net of sublease revenues, amounted to $2.8 million, $3.5 million, and $2.7 million for 2018, 2017, and 2016, respectively.

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NOTES TO FINANCIAL STATEMENTS

6. 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 8 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 costs charged to us by Williams was $3.9 million in 2018, $5.2 million in 2017, and $2.3 million in 2016. Included in our pension costs are settlement charges of $1.3 million and $3.0 million for 2018 and 2017, respectively. This amount reflects the portion of Williams’ settlement charge directly charged to us which was required as a result of lump-sum benefit payments made under Williams’ program to pay out certain deferred vested pension benefits, as well as lump-sum benefit payments made throughout 2018 and 2017. In addition, we were charged $0.7 million and $1.1 million for 2018 and 2017, respectively, of allocated corporate expenses associated with the settlement charge.

Williams provides subsidized retiree health care and life insurance benefits to certain eligible participants. Generally, participants that were employed by Williams on or before December 31, 1991 are eligible for subsidized retiree health care benefits. During 2018, 2017, and 2016, we received credits from Williams related to retiree health care and life insurance benefits of $2.1 million, $3.5 million and $3.8 million, respectively. These credits were recorded as regulatory liabilities.

We have been allowed by rate case settlements to collect or refund in future rates any differences between the actuarially determined costs and amounts currently being recovered in rates related to other postretirement benefits. Any difference 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. The amount of other postretirement benefits costs deferred as a regulatory liability at December 31, 2018 and 2017 are $36.2 million and $34.1 million, respectively.

Defined Contribution Plan

Williams maintains a defined contribution plan for substantially all of its employees. Williams charged us compensation expense of $1.9 million in 2018, $2.1 million in 2017, and $2.2 million in 2016 for Williams’ company matching contributions to this plan.

Employee Stock-Based Compensation Plan Information

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

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

Total stock-based compensation expense for the years ended December 31, 2018, 2017 and 2016 was $1.8 million, $1.9 million and $1.4 million, respectively, excluding amounts allocated from WPZ and Williams.

7. 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,

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including current maturities, were $576.2 million and $577.1 million, respectively, at December 31, 2018, and $581.6 million and $606.8 million, respectively, at December 31, 2017.

8. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES

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,
	2018		2017		2016
	(Thousands of Dollars)
Puget Sound Energy, Inc.	$	115,238	$	120,226	$	120,351
Northwest Natural Gas Company	49,126		51,743		49,895
Cascade Natural Gas Corporation	46,164		48,071		47,951

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 Williams’ cash management program. At December 31, 2018 and 2017, the advances due to us by Williams totaled approximately $180.4 million and $137.7 million, respectively. These advances are represented by demand notes and are classified as Receivables - Advances to Affiliate in the accompanying Balance Sheet. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on Williams’ excess cash at the end of each month, which was approximately 2.24 percent at December 31, 2018. The interest income from these advances was $2.0 million for the year ended December 31, 2018, and minimal for the years ended December 31, 2017, and 2016. Such interest income is included in Other (Income) and Other Expenses: Miscellaneous other (income) expenses, net on the accompanying Statement of Comprehensive Income.

We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams and its affiliates for all direct and indirect expenses incurred or payments made (including salary, bonus, incentive compensation, and benefits) in connection with these services. Employees of Williams also provide general administrative and management services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three factor formula, which considers revenues; property, plant, and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. We were billed $92.7 million, $96.5 million, and $92.8 million in the years ended December 31, 2018, 2017, and 2016, 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 (Loss). The amount billed to us during 2016 includes $2.4 million for severance and other related costs associated with a reduction in workforce primarily recognized in the first quarter.

During 2018, 2017, and 2016, we declared and paid cash distributions to our parent of $174.0 million, $186.0 million, and $174.0 million, respectively. During January 2019, we declared and paid cash distributions of $21.0 million to our parent.

9. 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 or plug and abandon 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 2018 and 2017, our overall asset retirement obligation changed as follows (in thousands):

41

NORTHWEST PIPELINE LLC

NOTES TO FINANCIAL STATEMENTS

	2018			2017
Beginning balance	$	67,100		$	60,762
Accretion	4,359			3,968
New obligations	—			149
Changes in estimates of existing obligations (1)	(2,095		)	2,510
Property dispositions/obligations settled	(14		)	(289		)
Ending balance	$	69,350		$	67,100

(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 costs, the estimated remaining life of assets, and discount rates.

10. REGULATORY ASSETS AND LIABILITIES

Our regulatory assets and liabilities result from our application of the provisions of ASC Topic 980 and are reflected on our Balance Sheet. Current regulatory assets are included in 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, 2018 and 2017:

	2018		2017
	(Thousands of Dollars)
Current regulatory assets:
Levelized depreciation	$	414	$	4,707
Fuel Recovery	6,619		—
Total current regulatory assets	7,033		4,707
Noncurrent regulatory assets:
Grossed-up deferred taxes on equity funds used during construction	5,883		6,598
Levelized depreciation	18,109		16,149
Total noncurrent regulatory assets	23,992		22,747
Total regulatory assets	$	31,025	$	27,454
Current regulatory liabilities:
Fuel recovery	$	—	$	1,539
Noncurrent regulatory liabilities:
Postretirement benefits	36,154		34,089
Deferred federal taxes-liability	206,527		206,547
Deferred state taxes - liability	12,120		—
Customer tax refund	24,094		—
Asset retirement obligations, net	11,535		5,868
Total noncurrent regulatory liabilities	290,430		246,504
Total regulatory liabilities	$	290,430	$	248,043

The significant regulatory assets and liabilities include:

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

42

NORTHWEST PIPELINE LLC

NOTES TO FINANCIAL STATEMENTS

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.

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. All amounts were generated during the period that we were a taxable entity. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long-lived asset to which they relate.

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. (See Note 6)

Deferred Federal Taxes-Liability This regulatory liability balance was established as a result of a decrease to rate base deferred taxes due to a decrease to the effective federal income tax rate. The timing of the refund of the regulatory liability to rate payers will be subject to future discussions and negotiations with our customers in our next rate case.

Asset Retirement Obligations, net This regulatory liability balance reflects the amount that we have recovered in our rates related to our future retirement costs offset by depreciation of the ARO asset and changes in the ARO liability due to the passage of time. AROs are expected to be fully recovered through the net negative salvage component of depreciation included in our rates. (See Note 9 for further discussion)

Customer Tax Refund In our 2017 Settlement, which became effective January 1, 2018, we agreed with our customers that if federal income tax rates decreased due to subsequent legislation, such as Tax Reform enacted in 2017, we would record a regulatory liability. As a result of Tax Reform, the regulatory liability will be $23.6 million annually plus accrued interest ($0.5 million at December 31, 2018) for the period beginning January 1, 2018 and continuing through the time that our current rates remain effective. (See Note 3)

Deferred State Taxes-Liability This regulatory liability balance, following the WPZ Merger, reflects a decrease to rate base deferred taxes due to a decrease to the estimated effective state income tax rates. The timing of the refund of the regulatory liability to rate payers will be subject to future discussions and negotiations with our customers in our next rate case.

43

NORTHWEST PIPELINE LLC

QUARTERLY FINANCIAL DATA

(Unaudited)

The following is a summary of unaudited quarterly financial data for 2018 and 2017:

	Quarter of 2018
	First		Second		Third (1)		Fourth
	(Thousands of Dollars)
Operating revenues	$	111,926	$	108,279	$	109,679	$	113,734
Operating income	45,967		39,507		30,246		39,970
Net income	38,795		32,822		25,454		34,390

	Quarter of 2017
	First		Second		Third		Fourth (2)
	(Thousands of Dollars)
Operating revenues	$	120,500	$	115,094	$	116,188	$	121,624
Operating income (loss)	59,478		51,816		51,584		(153,641		)
Net income (loss)	51,149		43,632		44,062		(166,677		)

(1) Includes a $12.1 million regulatory charge related to establishing a regulatory liability associated with a decrease in our estimated state tax rate following the WPZ Merger.

(2) Includes a $206.5 million regulatory charge resulting from Tax Reform. Includes $4.1 million increase to operating expenses for a Pension Plan Settlement adjustment. Includes $5.7 million unfavorable change to other (income) and deductions, net for a reduction in the tax gross-up on equity AFUDC due to the tax rate change.

44

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

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

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

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

There have been no changes during the fourth quarter of 2018 that have materially affected, or are reasonably likely to materially affect, our Internal Control over Financial Reporting.

Management’s Annual Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a – 15(f) and 15d – 15(f) under the Securities Exchange Act of 1934). Our internal control over financial reporting is designed to provide reasonable assurance to our management regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

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

Under the supervision and with the participation of our management, including our Senior Vice President — West and our Vice President and Chief Accounting Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2018, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we concluded that, as of December 31, 2018, our internal control over financial reporting was effective.

45

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.

46

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:

	2018		2017
	(Thousands of Dollars)
Audit fees	$	800	$	700
Audit related fees	—		—
Tax fees	—		—
All other fees	—		—
	$	800	$	700

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

As a wholly owned subsidiary of Williams, we do not have a separate audit committee.  The Williams Audit Committee is responsible for the appointment, compensation, retention, and oversight of Ernst & Young LLP (“EY”) as such appointment relates to us and Williams’ other affiliates. The Williams Audit Committee is responsible for overseeing the determination of fees associated with EY’s audit of our financial statements. The Williams Audit Committee has established a policy regarding pre-approval of all audit and non-audit services provided by EY to Williams and its affiliates. On an ongoing basis, management presents specific projects and categories of service, including projects and categories of service relating to us, to the Williams Audit Committee to request advance approval. The Williams Audit Committee reviews those requests and advises management if the Williams Audit Committee approves the engagement of EY. On a periodic basis, management reports to the Williams Audit Committee regarding the actual spending for such projects and services compared to the approved amounts. The Williams Audit Committee may also delegate the authority to pre-approve audit and permitted non-audit services, excluding services related to internal control over financial reporting, to a subcommittee of one or more committee members, provided that any such pre-approvals are reported on at a subsequent Williams Audit Committee meeting.

47

PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

	Page Reference to 2018 Form 10-K
(a) 1. and 2. Northwest Pipeline LLC financials
Index
Covered by reports of independent auditors:
Statement of Comprehensive Income (Loss) for the Years Ended December 31, 2018, 2017, and 2016	25
Balance Sheet at December 31, 2018 and 2017	26
Statement of Member’s Equity for the Years Ended December 31, 2018, 2017, and 2016	28
Statement of Cash Flows for the Years Ended December 31, 2018, 2017, and 2016	29
Notes to Financial Statements	30
Not covered by reports of independent auditors:
Quarterly Financial Data (Unaudited)	44

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.

48

(a) 3 and b. Exhibits:

Exhibit	Description
2	Certificate of Conversion of Northwest Pipeline GP (filed on July 3, 2013 as Exhibit 2.1 to our current report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
3.1	Certificate of Formation of Northwest Pipeline LLC (filed on July 3, 2013 as Exhibit 2.2 to our current report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
3.2	Operating Agreement of Northwest Pipeline LLC (filed on July 3, 2013 as Exhibit 3.1 to our current report on Form 8-K (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 (filed on September 14, 1995 as Exhibit 4.1 to our registration statement on Form S-3 (File No. 033-62639) and incorporated herein by reference).
4.2	Indenture, dated as of April 3, 2017, between Northwest Pipeline LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on April 3, 2017 as Exhibit 4.1 to our current report on Form 8-K (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 (filed on January 30, 2008 as Exhibit 10.1 to our current report on Form 8-K (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 (filed on February 3, 2015 as Exhibit 10(b) to our annual report on Form 10-K (File No. 001-07414) and incorporated herein by reference).
10.3	Credit Agreement dated as of July 13, 2018, between The Williams Companies, Inc., Northwest Pipeline LLC, and Transcontinental Gas Pipeline Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on July 17, 2018 as Exhibit 10.1 to The Williams Companies, Inc.’s Current Report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
10.4	Registration Rights Agreement, dated August 24, 2018 between Northwest Pipeline LLC and the initial purchasers listed therein (filed on August 24, 2018 as Exhibit 10.1 to our current report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
23.1*	Consent of Ernst & Young LLP.
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

49

Item 16. FORM 10-K SUMMARY

Not applicable.

50

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

NORTHWEST PIPELINE LLC
(Registrant)
By	/s/ Kathleen R. Hambleton
	Kathleen R. Hambleton
	Controller

Date: February 21, 2019

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.

Signature	Title
/s/ Walter J. Bennett	Senior Vice President and Management Committee Member (Principal Executive Officer)
Walter J. Bennett
/s/ Ted T. Timmermans	Vice President and Chief Accounting Officer (Principal Financial Officer)
Ted T. Timmermans
/s/ Kathleen R. Hambleton	Controller
Kathleen R. Hambleton	(Principal Accounting Officer)

Date: February 21, 2019

EX-23

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statement (Form S-4 No. 333-222633) of Northwest Pipeline LLC and in the related Prospectus of our report dated February 22, 2018, with respect to the financial statements of Northwest Pipeline LLC included in this Annual Report (Form 10-K) for the year ended December 31, 2017.

/s/ Ernst & Young LLP

Houston, Texas

February 22, 2018

EX-31.1

Exhibit 31.1

SECTION 302 CERTIFICATION

I, Walter J. Bennett, certify that:

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

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 21, 2019

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

EX-31.2

Exhibit 31.2

SECTION 302 CERTIFICATION

I, Ted T. Timmermans, certify that:

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

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 21, 2019

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

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Northwest Pipeline LLC (the “Company”) on Form 10-K for the period ending December 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies, in his capacity as an officer of the Company, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

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

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

/s/ Walter J. Bennett

Walter J. Bennett

Senior Vice President—West

February 21, 2019

/s/ Ted T. Timmermans

Ted T. Timmermans

Vice President and Chief Accounting Officer

February 21, 2019

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

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

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 21, 2019
Entity Information [Line Items]
Entity Registrant Name	Northwest Pipeline LLC
Entity Central Index Key	0000110019
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Amendment Flag	false
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Shell Company	false
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		0
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float		$ 0

XML

Statement of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Revenue
Natural gas transportation	$ 430,730	$ 460,934	$ 460,109
Natural gas storage	12,852	12,399	13,918
Other	36	73	2
Total operating revenues	443,618	473,406	474,029
OPERATING EXPENSES:
General and administrative	50,653	54,512	52,343
Operation and maintenance	75,237	78,085	79,514
Depreciation and amortization	106,073	102,084	101,672
Regulatory debits	2,334	4,857	3,510
Taxes, other than income taxes	17,507	17,889	17,835
Regulatory charge resulting from tax rate change	35,680	206,547	0
Other expenses, net	444	195	0
Total operating expenses	287,928	464,169	254,874
OPERATING INCOME	155,690	9,237	219,155
OTHER (INCOME) AND OTHER EXPENSES:
Interest expense	27,987	33,015	39,164
Allowance for equity and borrowed funds used during construction	(2,183)	(1,444)	(1,371)
Miscellaneous other (income) expenses, net	(1,575)	5,500	907
Total other (income) and other expenses	24,229	37,071	38,700
NET INCOME (LOSS)	131,461	(27,834)	180,455
CASH FLOW HEDGES:
Amortization of cash flow hedges into Interest expense	0	0	(28)
COMPREHENSIVE INCOME (LOSS)	$ 131,461	$ (27,834)	$ 180,427

XML

Balance Sheet - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
CURRENT ASSETS:
Cash	$ 0	$ 0
Receivables:
Trade	42,143	38,884
Affiliated companies	18	1,921
Advances to affiliate	180,400	137,666
Other	970	2,618
Materials and supplies	10,046	10,084
Exchange gas due from others	4,581	2,720
Prepayments and other	8,591	6,423
Total current assets	246,749	200,316
PROPERTY, PLANT AND EQUIPMENT, at cost	3,457,982	3,396,776
Less-Accumulated depreciation	1,596,369	1,508,245
Total property, plant and equipment, net	1,861,613	1,888,531
OTHER ASSETS:
Deferred charges	1,277	934
Regulatory assets	23,992	22,747
Total other assets	25,269	23,681
Total assets	2,133,631	2,112,528
Payables:
Trade	12,839	11,053
Affiliated companies	26,532	11,298
Accrued liabilities:
Taxes, other than income taxes	11,496	11,617
Interest	5,505	3,677
Exchange gas due to others	11,660	4,500
Exchange gas offset	0	1,499
Customer advances	788	2,092
Other	7,386	6,655
Long-term debt due within one year	0	249,874
Total current liabilities	76,206	302,265
LONG-TERM DEBT	576,168	331,748
OTHER NONCURRENT LIABILITIES:
Asset retirement obligations	69,350	67,100
Regulatory liabilities	290,430	246,504
Other	835	1,730
Total other noncurrent liabilities	360,615	315,334
CONTINGENT LIABILITIES AND COMMITMENTS (Note 4)
MEMBER'S EQUITY:
Member's capital	1,073,892	1,073,892
Retained earnings	46,750	89,289
Total member's equity	1,120,642	1,163,181
Total liabilities and member's equity	$ 2,133,631	$ 2,112,528

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Statement of Member's Equity Statement of Member's Equity - USD ($) $ in Thousands	Total	MEMBER'S CAPITAL	RETAINED EARINGS	ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Balance at beginning of period at Dec. 31, 2015		$ 1,073,892	$ 296,668	$ 28
Net income (loss)	$ 180,455		180,455
Cash distributions to parent	(174,000)		(174,000)
Reclassification of unrecognized gain into earnings	(28)			(28)
Balance at end of period at Dec. 31, 2016	1,377,015	1,073,892	303,123	0
Net income (loss)	(27,834)		(27,834)
Cash distributions to parent	(186,000)		(186,000)
Reclassification of unrecognized gain into earnings	0			0
Balance at end of period at Dec. 31, 2017	1,163,181	$ 1,073,892	89,289	0
Net income (loss)	131,461		131,461
Cash distributions to parent	(174,000)		(174,000)
Reclassification of unrecognized gain into earnings	0			0
Balance at end of period at Dec. 31, 2018	$ 1,120,642		$ 46,750	$ 0

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Statement of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
OPERATING ACTIVITIES:
Net income (loss)	$ 131,461	$ (27,834)	$ 180,455
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation	106,073	102,084	101,672
Regulatory debits	2,334	4,857	3,510
Regulatory charge resulting from tax rate change	35,680	206,547	0
Amortization of deferred charges and credits	954	2,687	898
Allowance for equity funds used during construction	1,703	1,104	953
Changes in current assets and liabilities:
Trade and other accounts receivable	(1,611)	1,798	845
Affiliated receivables	1,903	(600)	120
Materials and supplies	39	22	77
Other current assets	4,494	(687)	424
Trade accounts payable	1,753	271	(1,560)
Affiliated payables	15,234	4,005	(4,666)
Other accrued liabilities	881	1,856	(2,089)
Changes in noncurrent assets and liabilities:
Deferred charges	(8,392)	4,340	(7,275)
Regulatory liabilities	2,530	3,503	3,785
Noncurrent liabilities	3,498	(3,620)	9,025
Net cash provided by operating activities	295,128	298,125	284,268
FINANCING ACTIVITIES:
Proceeds from long-term debt	246,395	249,102	0
Retirement of long-term debt	(250,000)	(185,000)	(175,000)
Payments for debt issuance costs	(2,498)	(2,207)	0
Cash distributions to parent	(174,000)	(186,000)	(174,000)
Net cash used in financing activities	(180,103)	(124,105)	(349,000)
Property, plant and equipment:
Capital expenditures, net of equity AFUDC	(73,487)	(81,217)	(80,383)
Contributions and advances for construction costs	2,075	872	1,308
Disposal of property, plant and equipment, net	(879)	(1,146)	(1,280)
Advances to affiliates, net	(42,734)	(92,529)	126,730
Proceeds from insurance	0	0	18,188
Net cash provided by (used in) investing activities	(115,025)	(174,020)	64,563
NET (DECREASE) INCREASE IN CASH	0	0	(169)
CASH AT BEGINNING OF PERIOD	0	0	169
CASH AT END OF PERIOD	0	0	0
Supplemental Cash Flow Elements [Abstract]
Increases to property, plant and equipment	(73,105)	(80,355)	(72,432)
Changes in related accounts receivable, accounts payable, and accrued liabilities	(382)	(862)	(7,951)
Capital expenditures, net of equity AFUDC	$ (73,487)	$ (81,217)	$ (80,383)

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Summary of Significant Accounting Policies (Notes)

12 Months Ended

Dec. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure and Control

Northwest Pipeline LLC (Northwest) was indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which was consolidated by The Williams Companies, Inc. (Williams). On August 10, 2018, Williams completed a merger with WPZ, pursuant to which Williams acquired all of the publicly held outstanding common units of WPZ in exchange for shares of Williams’ common stock (WPZ Merger). Williams continued as the surviving entity. Northwest is now indirectly owned by Williams.

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

We are regulated by the Federal Energy Regulatory Commission (FERC). The Accounting Standards Codification (ASC) 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.

In December 2017, the Tax Cuts and Jobs Act (Tax Reform) was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent. Rates charged to our customers currently permit the recovery of an income tax allowance that includes a deferred income tax component. As a result of the reduced income tax rate from Tax Reform, the WPZ Merger, as well as the collection of historical rates that reflected historical federal and state income tax rates, we expect we will be required to return amounts to certain customers through future rates and have accordingly established federal and state regulatory liabilities of $206.5 million and $12.1 million, respectively, as of December 2018. The timing and actual amount of such return will be subject to future negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing service. Our regulatory asset associated with the effects of deferred taxes on equity funds used during construction was also impacted by Tax Reform and was reduced by $5.7 million in December 2017 through a charge to Miscellaneous other (income) expenses, net below Operating income.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles 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; 5) asset retirement obligations; and 6) regulatory deferred tax.

Revenue Recognition (subsequent to adoption of ASC 606)

Our customers are comprised of public utilities, municipalities, direct industrial users, electric power generators, and natural gas marketers and producers.

A performance obligation is a promise in a contract to transfer a distinct good or service (or integrated package of goods or services) to the customer. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue, when, or as, the performance obligation is satisfied. A performance obligation is distinct if the service is separately identifiable from other items in the integrated package of products or services and if a customer can benefit from it on its own or with other resources that are readily available to the customer. Service revenue contracts contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance.

Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. As a rate-regulated entity applying Topic 980, we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, in our judgment, the construction activities do not represent an ongoing major and central operation of our gas pipelines business and are not within the scope of Accounting Standards Update (ASU) 2014-09, Revenues from Contracts with Customers (ASC 606). Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed assets.

Service Revenues

We are subject to regulation by certain state and federal authorities, including the FERC, with revenue derived from both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a fixed reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas scheduled, each at rates specified in our FERC tariffs or as negotiated with our customers, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended beyond the specified contract term and until terminated generally by either us or the customer, but in certain cases unilaterally by the customer, with advance notice of termination ranging from one to five years. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one month periods or less. Our performance obligations include the following:

• Firm transportation or storage under firm transportation and storage contracts - an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities;

• Interruptible transportation and storage under interruptible transportation and storage contracts - an integrated package of services typically constituting a single performance obligation once scheduled, which includes receiving, transporting or storing (as applicable), and redelivering commodities.

In situations where, in our judgment, we consider the integrated package of services as a single performance obligation, which represents a majority of our contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized over time upon satisfaction of our daily stand ready performance obligation.

We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage 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 withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We use judgment to record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks. At December 31, 2018, we had no such rate refund liabilities.

In the course of providing transportation services to customers, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers or consumed in fuel to operate our system. The resulting customer imbalances are typically settled through the receipt or delivery of gas in the future based on the timelines outlined in Northwest’s Tariff, whereas the over/under recovery of fuel is cleared up through Northwest’s semi-annual fuel tracker. Customer imbalances to be repaid or recovered in-kind are recorded as Exchange gas due from others or Exchange gas due to others in our Balance Sheet. The under recovery of fuel is recorded as a Regulatory Asset and the over recovery is recorded as a Regulatory Liability. 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."

Revenue Recognition (prior to the adoption of ASC 606)

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 customers, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers or consumed in fuel to operate our system. The resulting customer imbalances are typically settled through the receipt or delivery of gas in the future based on the timelines outlined in Northwest’s Tariff, whereas the over/under recovery of fuel is cleared up through Northwest’s semi-annual fuel tracker. Customer imbalances to be repaid or recovered in-kind are recorded as Exchange gas due from others or Exchange gas due to others in our Balance Sheet. The under recovery of fuel is recorded as a Regulatory Asset and the over recovery is recorded as a Regulatory Liability. 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."

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.

Environmental Matters

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

Property, Plant, and Equipment

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

We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2018, 2017, and 2016 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. The levelized period for the 15-year contracts ended September 30, 2018.

We recorded regulatory debits totaling $2.3 million in 2018, $4.9 million in 2017, and $3.5 million in 2016 in the accompanying Statement of Comprehensive Income (Loss). These debits relate primarily to the levelized depreciation adjustment for the Evergreen Project discussed above.

We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. Measurement of AROs includes, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as market-risk premium. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and is offset by a regulatory asset. The gross regulatory asset balances associated with ARO as of December 31, 2018 and 2017 were $86.4 million and $82.2 million, respectively. The regulatory asset is expected to be fully recovered through the net negative salvage component of depreciation included in our rates; as such, the negative salvage component of accumulated depreciation was ($86.4) million and ($82.2) million at December 31, 2018 and 2017, respectively, and has been reclassified and netted against the amount of the ARO regulatory asset.

Impairment of Long-Lived Assets

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

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

Allowance for Funds Used During Construction

Allowance for funds used during construction (AFUDC) represents the estimated cost of borrowed 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 borrowed and equity AFUDC. The allowance for borrowed funds used during construction was $0.5 million for 2018, $0.3 million for 2017, and $0.4 million for 2016. The allowance for equity funds was $1.7 million, $1.1 million, and $1.0 million for 2018, 2017, and 2016, respectively. Both are reflected in Other (Income) and Other Expenses.

Income Taxes

We are a natural gas company organized as a pass-through entity and our taxable income or loss is consolidated on the federal income tax return of our parent, Williams. We generally are treated as a pass-through entity for state and local income tax purposes, and those taxes are generally borne on a consolidated basis by Williams. Net income for financial statement purposes may differ significantly from taxable income of Williams as a result of differences between the tax basis and financial reporting basis of assets and liabilities.

Accounts Receivable and Allowance for Doubtful Receivables

Accounts receivable are stated at the historical carrying amount net of reserves or write-offs. We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers’ financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables. Receivables determined to be uncollectible are reserved or written off in the period of determination.

Materials and Supplies Inventory

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

We perform an annual review of materials and supplies inventories, including an analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 2018 and 2017.

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.

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.

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 6 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.

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 $25.4 million in 2018, $31.9 million in 2017, and $38.5 million in 2016.

Accounting Standards Issued and Adopted

In May 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-09 establishing ASC 606. ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard became effective for interim and annual reporting periods beginning after December 15, 2017.

We adopted the provisions of ASC 606 effective January 1, 2018, utilizing the modified retrospective transition method for all contracts with customers, which included applying the provisions of ASC 606 beginning January 1, 2018, to all contracts not completed as of that date. There was no cumulative effect adjustment to retained earnings upon initially applying ASC 606 for periods prior to January 1, 2018.

For each revenue contract type, we conducted a formal contract review process to evaluate the impact of ASC 606. As a result of the adoption of ASC 606, there are no changes to the timing of our revenue recognition or differences in the presentation in our financial statements from those under the previous revenue standard (See Note 2).

Accounting Standards Issued But Not Yet Adopted

In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. The standard requires varying transition methods for the different categories of amendments. We do not expect ASU 2016-13 to have a significant impact on our financial statements.

In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach to lease classification similar to current lease accounting, and causes lessees to recognize operating leases on the balance sheet as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset, with an exception for leases with a term of one year or less. Additional disclosures will also be required regarding the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01 “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842” (ASU 2018-01). Per ASU 2018-01, land easements and rights-of-way are required to be assessed under ASU 2016-02 to determine whether the arrangements are or contain a lease. ASU 2018-01 permits an entity to elect a transition practical expedient to not apply ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not previously assessed under the previous lease guidance in ASC Topic 840 “Leases.”

In July 2018, the FASB issued ASU 2018-11 “Leases (Topic 842): Targeted Improvements” (ASU 2018-11). Prior to ASU 2018-11, a modified retrospective transition was required for financing or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. ASU 2018-11 allows entities an additional transition method to the existing requirements whereby an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. ASU 2018-11 also allows a practical expedient that permits lessors to not separate non-lease components from the associated lease component if certain conditions are present. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. We adopted ASU 2016-02 effective January 1, 2019.

We are substantially complete with our review of contracts to identify leases based on the modified definition of a lease and changes to our internal controls to support management in the accounting for and disclosure of leasing activities upon adoption of ASU 2016-02. We implemented a financial lease accounting system to assist management in the accounting for leases upon adoption. We are substantially complete with the implementation of ASU 2016-02 and believe the most significant changes to our financial statements relate to the recognition of a lease liability and offsetting right-of-use asset in our Balance Sheetfor operating leases, which we estimate to be less than 3 percent of total liabilities and total assets. We have also evaluated ASU 2016-02’s available practical expedients on adoption. We generally elected to adopt the practical expedients, which includes the practical expedient to not separate lease and non-lease components by both lessees and lessors by class of underlying assets and the land easements practical expedient.

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Rate and Regulatory Matters (Notes)

12 Months Ended

Dec. 31, 2018

Public Utilities, Rate Matters [Abstract]

Public Utilities, Disclosure of Rate Matters [Text Block]

RATE AND REGULATORY MATTERS

Rate Case Settlement Filing

On January 23, 2017, we filed for FERC approval a Stipulation and Settlement Agreement (Settlement) and were assigned Docket No. RP17-346. The Settlement specified an annual cost of service of $440 million and established a new general system firm Rate Schedule TF-1 (Large Customer) demand rate of $0.39294/Dth with a $0.00832 commodity rate (Phase 1) and a demand rate of $0.39033/Dth with a $0.00832 commodity rate (Phase 2). Phase 1 rates became effective January 1, 2018 and Phase 2 rates became effective October 1, 2018. The annual cost of service did not change from Phase 1 to Phase 2, but the Phase 2 rates reflect the termination of fifteen-year levelized contracts which became Rate Schedule TF-1 (Large Customer) contracts. Provisions were included in the Settlement that we can file a general rate case to place new rates into effect after October 1, 2018, and that a general rate case must be filed for new rates to become effective no later than January 1, 2023.

Tax Reform

Rates charged to our customers are subject to the rate-making policies of the FERC. These policies permit an interstate pipeline to include in its cost-of-service an income tax allowance that includes a deferred income tax component. Tax Reform, among other things, reduced the corporate federal income tax rates. As part of our Settlement discussed above, we agreed with our customers to record a regulatory asset or liability for federal income tax rate increases or decreases due to subsequent legislation, such as Tax Reform. Therefore, we have established a regulatory liability of $23.6 million plus accrued interest of $0.5 million, as of December 31, 2018, included within Regulatory Liabilities in our Balance Sheet. This liability will be amortized over a five-year period, coincidental with the next rate case going into effect.

As a result of the WPZ Merger, we also recorded a $12.1 million state tax regulatory liability associated with a decrease in our estimated state income tax rate.

FERC Developments

On March 15, 2018, the FERC issued a revised policy statement (the March 15 Statement) in Docket No. PL17-1 regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. As a result, the FERC will no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. One of the benefits of the WPZ Merger is to allow us to continue to recover an income tax allowance in our cost of service rates.

On July 18, 2018, the FERC issued an order dismissing the requests for rehearing and clarification of the revised policy statement. In addition, the FERC provided guidance that an MLP pipeline (or other pass-through entity) no longer recovering an income tax allowance pursuant to the revised policy may eliminate previously accumulated deferred income taxes (ADIT) from its cost of service instead of flowing these previously accumulated ADIT balances to ratepayers. This guidance, if implemented, would significantly mitigate the impact of the March 15 Statement. However, the FERC stated that the revised policy statement and such guidance do not establish a binding rule, but are instead expressions of general policy intent designed to provide guidance by notifying entities of the course of action the FERC intends to follow in future adjudications. To the extent the FERC addresses these issues in future proceedings, it will consider any arguments regarding not only the application of the revised policy to the facts of the case, but also any arguments regarding the underlying validity of the policy itself. The FERC's guidance on ADIT likely will be challenged by customers and state commissions, which would result in a long period of revenue uncertainty for pipelines eliminating ADIT from their cost of service. The WPZ Merger has the additional benefit of eliminating this uncertainty.

On March 15, 2018, the FERC also issued a Notice of Proposed Rulemaking in Docket No. RM18-11 proposing a filing process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the reduction in the corporate income tax rate in Tax Reform and the revised policy statement. On July 18, 2018, the FERC issued a Final Rule in the docket, retaining the filing requirement and reaffirming the options that pipelines have to either reflect the reduced tax rate or explain why no rate change is necessary. The FERC also clarified that a natural gas company organized as a pass-through entity all of whose income or losses are consolidated on the federal income tax return of its corporate parent is considered to be subject to the federal corporate income tax, and is thus eligible for a tax allowance. We believe this Final Rule and the previously discussed WPZ Merger allow for the continued recovery of income tax allowances in Northwest Pipeline’s rates. On October 19, 2018, we filed in Docket No. RP19-106, a petition requesting that the Commission waive our FERC Form No. 501-G filing requirement under this Final Rule because the reduction in the corporate income tax in Tax Reform is already addressed in our Settlement. On November 19, 2018 FERC granted our waiver request, obviating the need to make a FERC Form No. 501-G filing.

On March 15, 2018, the FERC also issued a Notice of Inquiry in Docket No. RM18-12 seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to ADIT amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action. We are evaluating the impact of these developments and currently expect any associated impacts would be prospective and determined through subsequent rate proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform. It is reasonably possible that our future tariff-based rates collected may be adversely impacted.

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Contingent Liabilities and Commitments (Notes)

12 Months Ended

Dec. 31, 2018

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.

Beginning in the mid-1980s, we evaluated many of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation might be necessary. We identified polychlorinated biphenyl (PCB) contamination in air compressor systems, soils, and related properties at certain compressor station sites. Similarly, we identified hydrocarbon impacts at these facilities due to the former use of earthen pits, lubricating oil leaks or spills, and excess pipe coating released to the environment. In addition, heavy metals have been identified at these sites due to the former use of mercury containing meters and paint and welding rods containing lead, cadmium, and arsenic. The PCBs were remediated pursuant to a Consent Decree with the U.S. Environmental Protection Agency (EPA) in the late 1980s, and we conducted a voluntary clean-up of the hydrocarbon and mercury impacts in the early 1990s. In 2005, the Washington Department of Ecology required us to re-evaluate our previous clean-ups in Washington. During 2006 to 2015, 129 meter stations were evaluated, of which 82 required remediation. As of December 31, 2018, all of the meter stations have been remediated. During 2006 to 2018, 14 compressor stations were evaluated, of which 11 required remediation. As of December 31, 2018, 10 compressor stations have been remediated. On the basis of the findings to date, we estimate that environmental assessment and remediation costs will total approximately $2.0 million, measured on an undiscounted basis, and are expected to be incurred through 2026. At December 31, 2018 we had accrued liabilities totaling approximately $2.0 million, $1.3 million in current liabilities and $0.7 million in other noncurrent liabilities and at December 31, 2017 approximately $3.0 million, $1.3 million in current liabilities and $1.7 million in other noncurrent liabilities 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.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, air quality standards for one-hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. The EPA previously issued its rule regarding National Ambient Air Quality Standards for ground-level ozone. We are monitoring the rule’s implementation as it will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Property, plant, and equipment - net in the Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.

Other Matters

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

Summary

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

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Debt, Financing Arrangements, and Leases (Notes)

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Debt, Financing Arrangements, and Leases

DEBT, FINANCING ARRANGEMENTS, AND LEASES

Long-Term Debt

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

	December 31,
	2018			2017
	(Thousands of Dollars)
6.05% senior unsecured notes due 2018	$	—		$	250,000
7.125% unsecured debentures due 2025	85,000			85,000
4.0% unsecured debentures due 2027	500,000			250,000
Debt issuance costs	(4,507		)	(2,415		)
Unamortized debt discount	(4,325		)	(963		)
Total long-term debt, including current portion	576,168			581,622
Long-term debt due within one year	—			249,874
Total long-term debt less current portion	$	576,168		$	331,748

There are no maturities applicable to long-term debt outstanding through 2023.

No property is pledged as collateral under any of our long-term debt.

Restrictive Debt Covenants

At December 31, 2018, none of our debt instruments restrict the amount of distributions to our parent, provided, however, that under the credit facility described below, we are restricted from making distributions to our parent during an event of default if we have directly incurred indebtedness under the credit facility. Our debt agreements contain restrictions on our ability to incur secured debt beyond certain levels.

Issuance and Retirement of Long-Term Debt

On August 24, 2018, we issued $250 million of 4.0 percent senior unsecured notes due 2027 to investors in a private debt placement. We used the net proceeds to repay the intercompany debt owed to Williams in connection with the repayment of our 6.05 percent senior notes at their maturity on June 15, 2018 and for general corporate purposes. The notes, which are an additional issuance of the 4.0 percent senior unsecured notes due 2027 we originally issued on April 3, 2017 and subsequently exchanged for substantially identical registered notes, were issued under the Indenture, dated as of April 3, 2017, between us and The Bank of New York Mellon Trust Company, N.A., as trustee. As part of the issuance we entered into a registration rights agreement with the initial purchasers of the notes. Under the terms of the agreement, we were obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act within 365 days after closing and to use commercially reasonable efforts to complete the exchange offer. We filed a registration statement, which was subsequently declared effective by the SEC, and consummated the exchange offer in the fourth quarter of 2018.

On April 3, 2017, we issued $250 million of 4.0 percent senior unsecured notes due 2027 to investors in a private debt placement. We used the net proceeds to retire $185 million of 5.95 percent senior unsecured notes that matured on April 15, 2017, and for general corporate purposes. We filed a registration statement, which the SEC declared effective in January 2018, and consummated the exchange offer in the first quarter of 2018.

Credit Facility

On July 13, 2018, we, along with Williams and Transco (the “borrowers”), the lenders named therein, and an administrative agent entered into a Credit Agreement with aggregate commitments available of $4.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. We and Transco are each subject to a $500 million borrowing sublimit. The facility made available under the Credit Agreement is initially available for five years from the Credit Agreement Effective Date (the “Maturity Date”). The borrowers may request an extension of the Maturity Date for an additional one-year period up to two times, to allow a Maturity Date as late as the seventh anniversary of the Credit Agreement Effective Date, subject to certain conditions. The Credit Agreement allows for same day swingline borrowings up to an aggregate amount of $200 million, subject to other utilization of the aggregate commitments under the Credit Agreement. Letter of credit commitments of $1.0 billion are, subject to the $500 million borrowing sublimit applicable to us and Transco, available to the borrowers. At December 31, 2018, no letters of credit have been issued and loans to Williams of $160 million were outstanding under the credit facility.

Measured as of December 31, 2018, we are in compliance with our financial covenant under the credit facility.

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

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

Other than swing line loans, each time funds are borrowed, the applicable 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 the London Interbank Offered Rate plus an applicable margin. We are required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on the applicable borrower's senior unsecured long-term debt ratings.

Williams participates in a commercial paper program, and Williams 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 anytime of $4 billion of unsecured commercial paper notes. At December 31, 2018, Williams had no outstanding commercial paper.

Lease Obligations

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 had an initial term of approximately 10 years, and in May 2018 was renewed for an additional 10 years, expiring December 31, 2029.

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)
2019	$	1,942
2020	1,968
2021	1,920
2022	1,909
2023	1,832
Thereafter	11,508
Total	$	21,079

Operating lease rental expense, net of sublease revenues, amounted to $2.8 million, $3.5 million, and $2.7 million for 2018, 2017, and 2016, respectively.

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Employee Benefit Plans (Notes)

12 Months Ended

Dec. 31, 2018

Retirement Benefits [Abstract]

Employee Benefit Plans [Text Block]

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 8 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 costs charged to us by Williams was $3.9 million in 2018, $5.2 million in 2017, and $2.3 million in 2016. Included in our pension costs are settlement charges of $1.3 million and $3.0 million for 2018 and 2017, respectively. This amount reflects the portion of Williams’ settlement charge directly charged to us which was required as a result of lump-sum benefit payments made under Williams’ program to pay out certain deferred vested pension benefits, as well as lump-sum benefit payments made throughout 2018 and 2017. In addition, we were charged $0.7 million and $1.1 million for 2018 and 2017, respectively, of allocated corporate expenses associated with the settlement charge.

Williams provides subsidized retiree health care and life insurance benefits to certain eligible participants. Generally, participants that were employed by Williams on or before December 31, 1991 are eligible for subsidized retiree health care benefits. During 2018, 2017, and 2016, we received credits from Williams related to retiree health care and life insurance benefits of $2.1 million, $3.5 million and $3.8 million, respectively. These credits were recorded as regulatory liabilities.

We have been allowed by rate case settlements to collect or refund in future rates any differences between the actuarially determined costs and amounts currently being recovered in rates related to other postretirement benefits. Any difference 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. The amount of other postretirement benefits costs deferred as a regulatory liability at December 31, 2018 and 2017 are $36.2 million and $34.1 million, respectively.

Defined Contribution Plan

Williams maintains a defined contribution plan for substantially all of its employees. Williams charged us compensation expense of $1.9 million in 2018, $2.1 million in 2017, and $2.2 million in 2016 for Williams’ company matching contributions to this plan.

Employee Stock-Based Compensation Plan Information

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

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

Total stock-based compensation expense for the years ended December 31, 2018, 2017 and 2016 was $1.8 million, $1.9 million and $1.4 million, respectively, excluding amounts allocated from WPZ and Williams.

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Financial Instruments (Notes)

12 Months Ended

Dec. 31, 2018

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 $576.2 million and $577.1 million, respectively, at December 31, 2018, and $581.6 million and $606.8 million, respectively, at December 31, 2017.

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Transactions with Major Customers and Affiliates (Notes)

12 Months Ended

Dec. 31, 2018

Transactions with Major Customers and Affiliates [Abstract]

Transactions with Major Customers and Affiliates

TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES

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,
	2018		2017		2016
	(Thousands of Dollars)
Puget Sound Energy, Inc.	$	115,238	$	120,226	$	120,351
Northwest Natural Gas Company	49,126		51,743		49,895
Cascade Natural Gas Corporation	46,164		48,071		47,951

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 Williams’ cash management program. At December 31, 2018 and 2017, the advances due to us by Williams totaled approximately $180.4 million and $137.7 million, respectively. These advances are represented by demand notes and are classified as Receivables - Advances to Affiliate in the accompanying Balance Sheet. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on Williams’ excess cash at the end of each month, which was approximately 2.24 percent at December 31, 2018. The interest income from these advances was $2.0 million for the year ended December 31, 2018, and minimal for the years ended December 31, 2017, and 2016. Such interest income is included in Other (Income) and Other Expenses: Miscellaneous other (income) expenses, net on the accompanying Statement of Comprehensive Income.

We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams and its affiliates for all direct and indirect expenses incurred or payments made (including salary, bonus, incentive compensation, and benefits) in connection with these services. Employees of Williams also provide general administrative and management services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three factor formula, which considers revenues; property, plant, and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. We were billed $92.7 million, $96.5 million, and $92.8 million in the years ended December 31, 2018, 2017, and 2016, 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 (Loss). The amount billed to us during 2016 includes $2.4 million for severance and other related costs associated with a reduction in workforce primarily recognized in the first quarter.

During 2018, 2017, and 2016, we declared and paid cash distributions to our parent of $174.0 million, $186.0 million, and $174.0 million, respectively. During January 2019, we declared and paid cash distributions of $21.0 million to our parent.

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Asset Retirement Obligations (Notes)

12 Months Ended

Dec. 31, 2018

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 or plug and abandon 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 2018 and 2017, our overall asset retirement obligation changed as follows (in thousands):

	2018			2017
Beginning balance	$	67,100		$	60,762
Accretion	4,359			3,968
New obligations	—			149
Changes in estimates of existing obligations (1)	(2,095		)	2,510
Property dispositions/obligations settled	(14		)	(289		)
Ending balance	$	69,350		$	67,100

(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 costs, the estimated remaining life of assets, and discount rates.

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Regulatory Assets and Liabilities (Notes)

12 Months Ended

Dec. 31, 2018

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 ASC Topic 980 and are reflected on our Balance Sheet. Current regulatory assets are included in 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, 2018 and 2017:

	2018		2017
	(Thousands of Dollars)
Current regulatory assets:
Levelized depreciation	$	414	$	4,707
Fuel Recovery	6,619		—
Total current regulatory assets	7,033		4,707
Noncurrent regulatory assets:
Grossed-up deferred taxes on equity funds used during construction	5,883		6,598
Levelized depreciation	18,109		16,149
Total noncurrent regulatory assets	23,992		22,747
Total regulatory assets	$	31,025	$	27,454
Current regulatory liabilities:
Fuel recovery	$	—	$	1,539
Noncurrent regulatory liabilities:
Postretirement benefits	36,154		34,089
Deferred federal taxes-liability	206,527		206,547
Deferred state taxes - liability	12,120		—
Customer tax refund	24,094		—
Asset retirement obligations, net	11,535		5,868
Total noncurrent regulatory liabilities	290,430		246,504
Total regulatory liabilities	$	290,430	$	248,043

The significant regulatory assets and liabilities include:

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.

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. All amounts were generated during the period that we were a taxable entity. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long-lived asset to which they relate.

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. (See Note 6)

Deferred Federal Taxes-Liability This regulatory liability balance was established as a result of a decrease to rate base deferred taxes due to a decrease to the effective federal income tax rate. The timing of the refund of the regulatory liability to rate payers will be subject to future discussions and negotiations with our customers in our next rate case.

Asset Retirement Obligations, net This regulatory liability balance reflects the amount that we have recovered in our rates related to our future retirement costs offset by depreciation of the ARO asset and changes in the ARO liability due to the passage of time. AROs are expected to be fully recovered through the net negative salvage component of depreciation included in our rates. (See Note 9 for further discussion)

Customer Tax Refund In our 2017 Settlement, which became effective January 1, 2018, we agreed with our customers that if federal income tax rates decreased due to subsequent legislation, such as Tax Reform enacted in 2017, we would record a regulatory liability. As a result of Tax Reform, the regulatory liability will be $23.6 million annually plus accrued interest ($0.5 million at December 31, 2018) for the period beginning January 1, 2018 and continuing through the time that our current rates remain effective. (See Note 3)

Deferred State Taxes-Liability This regulatory liability balance, following the WPZ Merger, reflects a decrease to rate base deferred taxes due to a decrease to the estimated effective state income tax rates. The timing of the refund of the regulatory liability to rate payers will be subject to future discussions and negotiations with our customers in our next rate case.

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Revenue Recognition Revenue Recognition (Notes)

12 Months Ended

Dec. 31, 2018

Revenue Recognition [Abstract]

Revenue from Contract with Customer [Text Block]

REVENUE RECOGNITION

Revenue by Category

Our revenue disaggregation by major service line includes Natural gas transportation, Natural gas storage, and Other, which are separately presented on the Statement of Comprehensive Income (Loss).

We do not have any contract assets or material contract liabilities.

Remaining Performance Obligations

The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of December 31, 2018. These primarily include reservation charges on contracted capacity on our firm transportation and storage contracts with customers. Amounts from certain contracts included in the table below, which are subject to the periodic review and approval by the FERC, reflect the rates for such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based on future rate cases or settlements approved by the FERC and the amount and timing of these changes is not currently known. As a practical expedient permitted by ASC 606, this table excludes the variable consideration component for commodity charges that will be recognized in future periods. As noted above, certain of our contracts contain evergreen provisions for periods beyond the initial term of the contract. The remaining performance obligations as of December 31, 2018, does not consider potential future performance obligations for which the renewal has not been exercised. The table below also does not include contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service.

	(Thousands)
2019	$	427,705
2020	404,899
2021	378,288
2022	372,446
2023	329,338
Thereafter	1,832,771
Total	$	3,745,447

The table above excludes remaining performance obligations associated with certain contract extensions executed in February 2019. The additional performance obligations associated with these contract extensions are approximately $11 million in 2023 and $549 million thereafter.

Receivables from contracts with customers are included within Receivables - Trade andReceivables - Affiliated companies and receivables that are not related to contracts with customers comprise the balance of Receivables - Advances to affiliate and Receivables - Other in our Balance Sheet.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Regulatory Accounting

Regulatory Accounting

We are regulated by the Federal Energy Regulatory Commission (FERC). The Accounting Standards Codification (ASC) 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.

In December 2017, the Tax Cuts and Jobs Act (Tax Reform) was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent. Rates charged to our customers currently permit the recovery of an income tax allowance that includes a deferred income tax component. As a result of the reduced income tax rate from Tax Reform, the WPZ Merger, as well as the collection of historical rates that reflected historical federal and state income tax rates, we expect we will be required to return amounts to certain customers through future rates and have accordingly established federal and state regulatory liabilities of $206.5 million and $12.1 million, respectively, as of December 2018. The timing and actual amount of such return will be subject to future negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing service. Our regulatory asset associated with the effects of deferred taxes on equity funds used during construction was also impacted by Tax Reform and was reduced by $5.7 million in December 2017 through a charge to Miscellaneous other (income) expenses, net below Operating income.

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles 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; 5) asset retirement obligations; and 6) regulatory deferred tax.

Revenue Recognition

Revenue Recognition (subsequent to adoption of ASC 606)

Our customers are comprised of public utilities, municipalities, direct industrial users, electric power generators, and natural gas marketers and producers.

A performance obligation is a promise in a contract to transfer a distinct good or service (or integrated package of goods or services) to the customer. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue, when, or as, the performance obligation is satisfied. A performance obligation is distinct if the service is separately identifiable from other items in the integrated package of products or services and if a customer can benefit from it on its own or with other resources that are readily available to the customer. Service revenue contracts contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance.

Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. As a rate-regulated entity applying Topic 980, we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, in our judgment, the construction activities do not represent an ongoing major and central operation of our gas pipelines business and are not within the scope of Accounting Standards Update (ASU) 2014-09, Revenues from Contracts with Customers (ASC 606). Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed assets.

Service Revenues

We are subject to regulation by certain state and federal authorities, including the FERC, with revenue derived from both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a fixed reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas scheduled, each at rates specified in our FERC tariffs or as negotiated with our customers, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended beyond the specified contract term and until terminated generally by either us or the customer, but in certain cases unilaterally by the customer, with advance notice of termination ranging from one to five years. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one month periods or less. Our performance obligations include the following:

• Firm transportation or storage under firm transportation and storage contracts - an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities;

• Interruptible transportation and storage under interruptible transportation and storage contracts - an integrated package of services typically constituting a single performance obligation once scheduled, which includes receiving, transporting or storing (as applicable), and redelivering commodities.

In situations where, in our judgment, we consider the integrated package of services as a single performance obligation, which represents a majority of our contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized over time upon satisfaction of our daily stand ready performance obligation.

We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage 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 withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We use judgment to record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks. At December 31, 2018, we had no such rate refund liabilities.

In the course of providing transportation services to customers, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers or consumed in fuel to operate our system. The resulting customer imbalances are typically settled through the receipt or delivery of gas in the future based on the timelines outlined in Northwest’s Tariff, whereas the over/under recovery of fuel is cleared up through Northwest’s semi-annual fuel tracker. Customer imbalances to be repaid or recovered in-kind are recorded as Exchange gas due from others or Exchange gas due to others in our Balance Sheet. The under recovery of fuel is recorded as a Regulatory Asset and the over recovery is recorded as a Regulatory Liability. 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."

Revenue Recognition (prior to the adoption of ASC 606)

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 customers, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers or consumed in fuel to operate our system. The resulting customer imbalances are typically settled through the receipt or delivery of gas in the future based on the timelines outlined in Northwest’s Tariff, whereas the over/under recovery of fuel is cleared up through Northwest’s semi-annual fuel tracker. Customer imbalances to be repaid or recovered in-kind are recorded as Exchange gas due from others or Exchange gas due to others in our Balance Sheet. The under recovery of fuel is recorded as a Regulatory Asset and the over recovery is recorded as a Regulatory Liability. 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."

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.

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 economic benefit and potential for rate recovery. We believe that expenditures required to meet applicable environmental laws and regulations are prudently incurred in the ordinary course of business and such expenditures would be permitted to be recovered through rates.

Property, Plant, and Equipment

Property, Plant, and Equipment

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

We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2018, 2017, and 2016 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. The levelized period for the 15-year contracts ended September 30, 2018.

We recorded regulatory debits totaling $2.3 million in 2018, $4.9 million in 2017, and $3.5 million in 2016 in the accompanying Statement of Comprehensive Income (Loss). These debits relate primarily to the levelized depreciation adjustment for the Evergreen Project discussed above.

We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. Measurement of AROs includes, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as market-risk premium. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and is offset by a regulatory asset. The gross regulatory asset balances associated with ARO as of December 31, 2018 and 2017 were $86.4 million and $82.2 million, respectively. The regulatory asset is expected to be fully recovered through the net negative salvage component of depreciation included in our rates; as such, the negative salvage component of accumulated depreciation was ($86.4) million and ($82.2) million at December 31, 2018 and 2017, respectively, and has been reclassified and netted against the amount of the ARO regulatory asset.

Impairment of Long-Lived Assets

Impairment of Long-Lived Assets

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

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

Allowance for Funds Used During Construction

Allowance for Funds Used During Construction

Allowance for funds used during construction (AFUDC) represents the estimated cost of borrowed 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 borrowed and equity AFUDC. The allowance for borrowed funds used during construction was $0.5 million for 2018, $0.3 million for 2017, and $0.4 million for 2016. The allowance for equity funds was $1.7 million, $1.1 million, and $1.0 million for 2018, 2017, and 2016, respectively. Both are reflected in Other (Income) and Other Expenses.

Income Taxes

Income Taxes

We are a natural gas company organized as a pass-through entity and our taxable income or loss is consolidated on the federal income tax return of our parent, Williams. We generally are treated as a pass-through entity for state and local income tax purposes, and those taxes are generally borne on a consolidated basis by Williams. Net income for financial statement purposes may differ significantly from taxable income of Williams as a result of differences between the tax basis and financial reporting basis of assets and liabilities.

Accounts Receivable and Allowance for Doubtful Receivables

Accounts Receivable and Allowance for Doubtful Receivables

Accounts receivable are stated at the historical carrying amount net of reserves or write-offs. We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers’ financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables. Receivables determined to be uncollectible are reserved or written off in the period of determination.

Materials and Supplies Inventory

Materials and Supplies Inventory

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

We perform an annual review of materials and supplies inventories, including an analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 2018 and 2017.

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.

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.

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 6 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.

Cash Equivalents

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.

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Financial Instruments (Policies)

12 Months Ended

Dec. 31, 2018

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 $576.2 million and $577.1 million, respectively, at December 31, 2018, and $581.6 million and $606.8 million, respectively, at December 31, 2017.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018, 2017, and 2016 are as follows:

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

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Debt, Financing Arrangements, and Leases (Tables)

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Long-term debt

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

	December 31,
	2018			2017
	(Thousands of Dollars)
6.05% senior unsecured notes due 2018	$	—		$	250,000
7.125% unsecured debentures due 2025	85,000			85,000
4.0% unsecured debentures due 2027	500,000			250,000
Debt issuance costs	(4,507		)	(2,415		)
Unamortized debt discount	(4,325		)	(963		)
Total long-term debt, including current portion	576,168			581,622
Long-term debt due within one year	—			249,874
Total long-term debt less current portion	$	576,168		$	331,748

Future Minimum lease 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)
2019	$	1,942
2020	1,968
2021	1,920
2022	1,909
2023	1,832
Thereafter	11,508
Total	$	21,079

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Transactions with Major Customers and Affiliates (Tables)

12 Months Ended

Dec. 31, 2018

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,
	2018		2017		2016
	(Thousands of Dollars)
Puget Sound Energy, Inc.	$	115,238	$	120,226	$	120,351
Northwest Natural Gas Company	49,126		51,743		49,895
Cascade Natural Gas Corporation	46,164		48,071		47,951

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2018

Asset Retirement Obligation Disclosure [Abstract]

Schedule of change in asset retirement obligation

During 2018 and 2017, our overall asset retirement obligation changed as follows (in thousands):

	2018			2017
Beginning balance	$	67,100		$	60,762
Accretion	4,359			3,968
New obligations	—			149
Changes in estimates of existing obligations (1)	(2,095		)	2,510
Property dispositions/obligations settled	(14		)	(289		)
Ending balance	$	69,350		$	67,100

(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 costs, the estimated remaining life of assets, and discount rates.

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2018

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 ASC Topic 980 and are reflected on our Balance Sheet. Current regulatory assets are included in 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, 2018 and 2017:

	2018		2017
	(Thousands of Dollars)
Current regulatory assets:
Levelized depreciation	$	414	$	4,707
Fuel Recovery	6,619		—
Total current regulatory assets	7,033		4,707
Noncurrent regulatory assets:
Grossed-up deferred taxes on equity funds used during construction	5,883		6,598
Levelized depreciation	18,109		16,149
Total noncurrent regulatory assets	23,992		22,747
Total regulatory assets	$	31,025	$	27,454
Current regulatory liabilities:
Fuel recovery	$	—	$	1,539
Noncurrent regulatory liabilities:
Postretirement benefits	36,154		34,089
Deferred federal taxes-liability	206,527		206,547
Deferred state taxes - liability	12,120		—
Customer tax refund	24,094		—
Asset retirement obligations, net	11,535		5,868
Total noncurrent regulatory liabilities	290,430		246,504
Total regulatory liabilities	$	290,430	$	248,043

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Revenue Recognition (Tables)

12 Months Ended

Dec. 31, 2018

Revenue Recognition [Abstract]

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]

The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of December 31, 2018. These primarily include reservation charges on contracted capacity on our firm transportation and storage contracts with customers. Amounts from certain contracts included in the table below, which are subject to the periodic review and approval by the FERC, reflect the rates for such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based on future rate cases or settlements approved by the FERC and the amount and timing of these changes is not currently known. As a practical expedient permitted by ASC 606, this table excludes the variable consideration component for commodity charges that will be recognized in future periods. As noted above, certain of our contracts contain evergreen provisions for periods beyond the initial term of the contract. The remaining performance obligations as of December 31, 2018, does not consider potential future performance obligations for which the renewal has not been exercised. The table below also does not include contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service.

	(Thousands)
2019	$	427,705
2020	404,899
2021	378,288
2022	372,446
2023	329,338
Thereafter	1,832,771
Total	$	3,745,447

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Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2018 USD ($) employee	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Entity number of employees | employee	0
Regulatory charge resulting from tax rate change	$ 35,680,000	$ 206,547,000	$ 0
Revenue Recognition [Abstract]
Reserve for rate refund, Current	0
Reserve for rate refund, Noncurrent	0
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory debits	2,334,000	4,857,000	3,510,000
Regulatory assets	23,992,000	22,747,000
Capitalized Interest Costs, Including Allowance for Funds Used During Construction [Abstract]
Allowance for funds used during construction, debt	500,000	300,000	400,000
Allowance for funds used during construction, equity	1,703,000	1,104,000	953,000
Interest Payments [Abstract]
Cash payments for interest, net of interest capitalized	25,400,000	31,900,000	38,500,000
State Tax [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Regulatory charge resulting from tax rate change	12,100,000
Levelized depreciation [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory debits	2,300,000	4,900,000	$ 3,500,000
Regulatory assets	18,109,000	16,149,000
Asset retirement obligation [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets	86,400,000	82,200,000
Negative salvage [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets	$ 86,400,000	$ 82,200,000
Minimum [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Effective Income Tax Rate Reconciliation, Deduction, Percent		21.00%
Maximum [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Effective Income Tax Rate Reconciliation, Deduction, Percent		35.00%
Maximum [Member] | Accounting Standards Update 2016-02 [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Operating Lease Liability Percentage Of Total Liabilities	3.00%
Operating Lease Right Of Use Asset Percentage Of Total Assets	3.00%
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%
Other Nonoperating Income (Expense) [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Regulatory charge resulting from tax rate change		$ 5,700,000
Operating Expense [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Regulatory charge resulting from tax rate change	$ 206,547,000

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Rate and Regulatory Matters (Details) $ in Thousands				12 Months Ended
	Oct. 01, 2018 $ / dekatherm	Jan. 01, 2018 $ / dekatherm	Jan. 23, 2017 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Public Utilities, General Disclosures [Line Items]
Annual Cost of Service			$ 440,000
Regulatory Liabilities				$ 290,430	$ 248,043
Phase 1 Demand Rate per Dth Pending
Public Utilities, General Disclosures [Line Items]
Demand Rate | $ / dekatherm		0.39294
Phase 1 Commodity Rate Pending
Public Utilities, General Disclosures [Line Items]
Commodity Rate | $ / dekatherm		0.00832
Phase 2 Demand Rate per Dth Pending
Public Utilities, General Disclosures [Line Items]
Demand Rate | $ / dekatherm	0.39033
Phase 2 Commodity Rate Pending
Public Utilities, General Disclosures [Line Items]
Commodity Rate | $ / dekatherm	0.00832
Deferred Income Tax Charge [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities				$ 23,600	0
Regulatory Liability, Amortization Period				5 years
Accrued Interest on Deferred Regulatory Tax Liability [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities				$ 500
State Tax [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities				$ 12,100	$ 0

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Contingent Liabilities and Commitments (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Environmental Matters
Environmental assessment and remediation costs, undiscounted	$ 2.0
Accrued environmental liabilities	2.0	$ 3.0
Accrued Environmental Loss Contingencies, Current	1.3	1.3
Accrued Environmental Loss Contingencies, Noncurrent	$ 0.7	$ 1.7

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Debt, Financing Arrangements, and Leases (Details) - USD ($)		12 Months Ended
	Apr. 15, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Aug. 24, 2018	Jul. 13, 2018	May 02, 2018	Apr. 03, 2017	Oct. 01, 2009
Debt Instrument [Line Items]
Debt issuance costs		$ 4,507,000	$ 2,415,000
Debt Instrument, Unamortized Discount, Noncurrent		4,325,000	963,000
Long-term debt due within one year		0	249,874,000
Total long-term debt less current portion		576,168,000	331,748,000
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2019		1,942,000
2020		1,968,000
2021		1,920,000
2022		1,909,000
2023		1,832,000
Thereafter		11,508,000
Operating Leases, Future Minimum Payments Due		21,079,000
Lessee, Operating Lease, Term of Contract									10 years
Lessee, Operating Lease, Renewal Term							10 years
Operating Leases, Rent Expense		$ 2,800,000	3,500,000	$ 2,700,000
4% Senior Unsecured Notes Due 2027 [Member]
Debt Instrument [Line Items]
Issuance of debt					$ 250,000,000
Debt Instrument, Interest Rate, Stated Percentage		4.00%
6.05% Senior Unsecured Notes due 2018 [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 0	250,000,000
7.125 percent unsecured debentures due 2025 [Member]
Debt Instrument [Line Items]
Long-term Debt		85,000,000	85,000,000
4.0% unsecured debentures due 2027 [Member]
Debt Instrument [Line Items]
Long-term Debt		500,000,000	$ 250,000,000
Issuance of debt								$ 250,000,000
5.95 percent senior unsecured notes due 2017 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.95%
Extinguishment of Debt, Amount	$ 185,000,000,000
Line of Credit [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity						$ 500,000,000
Line of Credit [Member] | Williams Companies Inc [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity						4,500,000,000
Additional Amount By Which Credit Facility Can Be Increased						500,000,000
Long-term Line of Credit		160,000,000
Swing Line Loan | Williams Companies Inc [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity						200,000,000
Commercial Paper [Member] | Williams Companies Inc [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity						4,000,000,000
Commercial Paper		0
Letter of Credit [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity						500,000,000
Letters of Credit Outstanding, Amount		$ 0
Letter of Credit [Member] | Williams Companies Inc [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity						$ 1,000,000,000

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Employee Benefit Plans (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Regulatory liabilities	$ 290,430	$ 246,504
Salary and Wage, Excluding Cost of Good and Service Sold [Abstract]
Stock-based compensation expense	1,800	1,900	$ 1,400
Other Postretirement Benefit Costs
Defined Benefit Plan Disclosure [Line Items]
Regulatory liabilities	36,200	34,100
Williams Companies Inc [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension cost	3,900	5,200	2,300
Defined contribution plan matching contributions expense	1,900	2,100	2,200
Williams Companies Inc [Member] | Retiree health care and life insurance benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory liabilities	2,100	3,500	$ 3,800
Williams Companies Inc [Member] | Pension Plan [Member] | Directly charged [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Payment for Settlement	1,300	3,000
Williams Companies Inc [Member] | Pension Plan [Member] | Allocated corporate expenses [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Payment for Settlement	$ 700	$ 1,100

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Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Reported Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Gross	$ 576,168	$ 581,622
Estimate of fair value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Fair Value	$ 577,100	$ 606,800

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Transactions with Major Customers and Affiliates (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Jan. 31, 2019 USD ($)	Dec. 31, 2018 USD ($) employee	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Related Party Transaction [Line Items]
Advances to affiliate		$ 180,400	$ 137,666
Related party transaction, rate		2.24%
Entity number of employees | employee		0
Related party transaction, expenses from transactions with related party		$ 92,700	96,500	$ 92,800
Severance Costs				2,400
Cash distributions to parent		174,000	186,000	174,000
Williams Companies Inc [Member]
Related Party Transaction [Line Items]
Advances to affiliate		180,400	137,666
Subsequent Event [Member]
Related Party Transaction [Line Items]
Cash distributions to parent	$ 21,000
Puget Sound Energy, Inc. [Member]
Revenue, Major Customer [Line Items]
Operating revenues		115,238	120,226	120,351
Northwest Natural Gas Company [Member]
Revenue, Major Customer [Line Items]
Operating revenues		49,126	51,743	49,895
Cascade Natural Gas Corporation [Member]
Revenue, Major Customer [Line Items]
Operating revenues		$ 46,164	$ 48,071	$ 47,951

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 67,100	$ 60,762
Accretion	4,359	3,968
New obligations	0	149
Changes in estimates of existing obligations (1)	(2,095)	2,510
Property dispositions/obligations settled	(14)	(289)
Ending balance	$ 69,350	$ 67,100

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Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Regulatory Assets [Line Items]
Current regulatory assets	$ 7,033	$ 4,707
Noncurrent regulatory assets	23,992	22,747
Total regulatory assets	31,025	27,454
Regulatory Liabilities [Line Items]
Regulatory liabilities	290,430	246,504
Total regulatory liabilities	290,430	248,043
Fuel recovery [Member]
Regulatory Liabilities [Line Items]
Current regulatory liabilities	0	1,539
Postretirement benefits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	36,154	34,089
Deferred federal taxes-liability
Regulatory Liabilities [Line Items]
Regulatory liabilities	206,527	206,547
Total regulatory liabilities	23,600	0
Deferred state taxes - liability
Regulatory Liabilities [Line Items]
Total regulatory liabilities	12,100	0
Customer tax refund [Domain]
Regulatory Liabilities [Line Items]
Regulatory liabilities	24,094
Asset retirement obligations, net [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	11,535	5,868
Fuel recovery [Member]
Regulatory Assets [Line Items]
Current regulatory assets	6,619	0
Levelized depreciation [Member]
Regulatory Assets [Line Items]
Current regulatory assets	414	4,707
Noncurrent regulatory assets	18,109	16,149
Deferred taxes on equity funds used during construction [Member]
Regulatory Assets [Line Items]
Noncurrent regulatory assets	$ 5,883	$ 6,598

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Revenue Recognition (Details)	Dec. 31, 2018 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | Remaining Performance Obligations [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 427,705,000
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Remaining Performance Obligations [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 404,899,000
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Remaining Performance Obligations [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 378,288,000
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Remaining Performance Obligations [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 372,446,000
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 11,000,000
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Remaining Performance Obligations [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 329,338,000
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 549,000,000
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Remaining Performance Obligations [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 3,745,447,000