NORTHWEST PIPELINE LLC - FORM 10-K

NORTHWEST PIPELINE LLC - FORM 10-K - February 27, 2013

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

¨	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 GP

(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 x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x 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. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

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 GP

FORM 10-K

TABLE OF CONTENTS


	Page
PART I
Item 1. BUSINESS		3

Item 1A. RISK FACTORS		6

Item 1B. UNRESOLVED STAFF COMMENTS		21

Item 2. PROPERTIES		21

Item 3. LEGAL PROCEEDINGS		21

Item 4. MINE SAFETY DISCLOSURES		21

PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		21

Item 6. SELECTED FINANCIAL DATA (Omitted)		21

Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		21

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		23

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		25

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		48

Item 9A. CONTROLS AND PROCEDURES		48

Item 9B. OTHER INFORMATION		48

PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE (Omitted)		49

Item 11. EXECUTIVE COMPENSATION (Omitted)		49

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS (Omitted)		49

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE (Omitted)		49

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES		49

PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES		50

DEFINITIONS

We use the following gas measurements in this report:

Dth-means dekatherm.

Mdth-means thousand dekatherms.

MMdth-means million dekatherms.

PART I

Item 1.

BUSINESS

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

Northwest is indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). As of December 31, 2012, Williams holds an approximate 70 percent interest in WPZ, comprised of an approximate 68 percent limited partner interest and all of WPZ’s 2 percent general partner interest.

GENERAL

Northwest owns and operates 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, 2012, we had long-term firm transportation contracts, including peaking service, with aggregate capacity reservations of approximately 3.9 MMdth of natural gas per day.

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

We transport and store natural gas for a broad mix of customers, including local natural gas distribution companies, municipal utilities, direct industrial users, electric power generators and natural gas marketers and producers. Our firm transportation and storage contracts are generally long-term contracts with various expiration dates and account for the major portion of our business. Additionally, we offer interruptible and short-term firm transportation services. During 2012, our two largest customers were Puget Sound Energy, Inc. and Northwest Natural Gas Company, which accounted for approximately 23.0 percent and 10.8 percent, respectively, of our total operating revenues for the year ended December 31, 2012. 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 FERC. We provide a significant portion of our transportation and storage services pursuant to long-term firm contracts that obligate our customers to pay us monthly capacity reservation fees, which are fees that are owed for reserving an agreed upon amount of pipeline or storage capacity regardless of the amount of pipeline or storage capacity actually utilized by a customer. When a customer utilizes the capacity it has reserved under a firm transportation contract, we also collect a volumetric fee based on the quantity of natural gas transported. These volumetric fees are typically a small percentage of the total fees received under a firm contract. We also derive a small portion of our revenues from short-term firm and interruptible contracts under which customers pay fees for transportation, storage and other related services. The high percentage of our revenue derived from capacity reservation fees helps mitigate the risk of revenue fluctuations caused by changing supply and demand conditions.

CAPITAL PROJECTS

North and South Seattle Lateral Delivery Expansions

We have executed agreements with Puget Sound Energy to expand the North and South Seattle laterals to provide additional lateral capacity of approximately 80 Mdth per day and 74 Mdth per day, respectively. We estimate the expansion of the two laterals to cost between $32 million and $36 million. We placed North Seattle into service on November 8, 2012. South Seattle is scheduled for a fall 2013 in-service date.

RATE MATTERS

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

On April 26, 2012, the FERC unconditionally approved our Stipulation and Settlement Agreement (Settlement) filed on March 15, 2012. The supporting or non-opposing customers named in the Settlement represented approximately 99.5 percent of our long-term firm transportation and storage capacity. The Settlement specified an annual cost of service of $466.5 million and established a new general system firm transportation rate of $0.44 per dekatherm, a 7.4 percent increase over our previous rate. New rates became effective January 1, 2013, and will remain in effect for a minimum of 3 years and a maximum of 5 years.

REGULATION

FERC Regulation

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

Environmental Matters

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

•

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

•

Damage to facilities resulting from accidents during normal operations;

•

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

•

Blowouts, cratering, and explosions.

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

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

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

Safety and Maintenance

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

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

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

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

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

EMPLOYEES

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

TRANSACTIONS WITH AFFILIATES

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

Item 1A.

RISK FACTORS

FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE

“SAFE HARBOR” PROVISIONS OF

THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions, and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

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

•

Amounts and nature of future capital expenditures;

•

Expansion and growth of our business and operations;

•

Financial condition and liquidity;

•

Business strategy;

•

Cash flow from operations or results of operations;

•

Rate case filings; and

•

Natural gas prices and demand.

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

•

Availability of supplies, market demand, volatility of prices, and the availability and cost of capital;

•

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;

•

Development of alternative energy sources;

•

The impact of operational and development hazards;

•

Costs of, changes in, or the results of laws, government regulations (including safety and climate change regulation and changes in natural gas production from exploration and production areas that we serve), environmental liabilities, litigation and rate proceedings;

•

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

•

Changes in maintenance and construction costs;

•

Changes in the current geopolitical situation;

•

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

•

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

•

Risks associated with future weather conditions;

•

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

•

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

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

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

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

RISK FACTORS

You should carefully consider the following risk factors in addition to the other information in this report. Each of these factors could adversely affect our business, operating results, and financial condition as well as adversely affect the value of an investment in our securities.

Risks Inherent to Our Industry and Business

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

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

•

fires, blowouts, cratering, and explosions;

•

uncontrolled releases of natural gas;

•

pollution and other environmental risks;

•

natural disasters;

•

aging infrastructure and mechanical problems;

•

damages to pipelines and pipeline blockages or other pipeline interruptions;

•

operator error;

•

damage caused by third party activity, such as operation of construction equipment; and

•

terrorist attacks or threatened attacks on our facilities or those of other energy companies.

These risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all of these risks and losses, and only at levels we believe to be appropriate. 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. In spite of our precautions taken, an event such as those described above could cause considerable harm to people or property and could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of our pipeline infrastructure. Potential customer impacts arising from service interruptions on segments of our pipeline infrastructure could include limitations on the pipeline’s ability to satisfy customer requirements, obligations to provide reservation charge credits to customers in times of constrained capacity, and solicitation of existing customers by others for potential new pipeline projects that would compete directly with existing services. Such circumstances could adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business, financial condition, results of operations and cash flows.

Increased competition from alternative natural gas transportation and storage options and alternative fuel sources could have a significant financial impact on us.

We compete primarily with other interstate pipelines and storage facilities in the transportation and storage of natural gas. Some of our competitors may have greater financial resources and access to greater supplies of natural gas than we do. Some of these competitors may expand or construct transportation and storage systems that would create additional competition for natural gas supplies or the services we provide to our customers. Moreover, WPZ and its other affiliates, including Williams, may not be limited in their ability to compete with us. Further, natural gas also competes with other forms of energy available to our customers, including electricity, coal, fuel oils, and other alternative energy sources.

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. FERC’s policies promoting competition in natural gas markets are having the effect of increasing the natural gas transportation and storage options for our traditional customer base. Similarly, a highly-liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. As a result, pipeline capacity is being used more efficiently, and peaking and storage services are increasingly effective substitutes for annual pipeline capacity. As a result, we could experience some “turnback” of firm capacity as the primary terms of existing agreements expire. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we or our remaining customers may have to bear the costs associated with the turned back capacity. Increased competition could reduce the amount of transportation or storage

capacity contracted on our system or, in cases where we do not have long-term fixed rate contracts, could force us to lower our transportation or storage rates. Competition could intensify the negative impact of factors that significantly decrease demand for natural gas or increase the price of natural gas in the markets served by our pipeline system, such as competing or alternative forms of energy, a regional or national recession or other adverse economic conditions, weather, higher fuel costs and taxes, or other governmental or regulatory actions that directly or indirectly increase the price of natural gas or limit the use of natural gas. Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. All of these competitive pressures could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

We provide some services pursuant to long-term, discounted or negotiated rate 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 FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a discount or “negotiated rate” that may be above or below 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 maintain or replace expiring natural gas transportation and storage contracts at favorable rates or on a long-term basis.

Our primary exposure to market risk occurs at the time the terms of existing transportation and storage contracts expire and are subject to termination. Upon expiration of the terms, we may not be able to extend contracts with existing customers or obtain replacement contracts at favorable rates or on a long-term basis.

The extension or replacement of existing contracts depends on a number of factors beyond our control, including:

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the level of existing and new competition to deliver natural gas to our markets;

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the growth in demand for natural gas in our markets;

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

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whether our business strategy continues to be successful;

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the level of competition for natural gas supplies in the production basins serving us; and

•

the effects of state regulation on customer contracting practices.

Any 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.

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

Although most of our pipeline system’s current capacity is fully contracted, 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. 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. There can be no assurance that we will be able to compete successfully against current and future competitors and any failure to do so could have a material adverse effect on our business and results of operations.

Any significant decrease in supplies of natural gas in our areas of operation could adversely affect our business and operating results.

Our business is dependent on the continued availability of natural gas production and reserves. The development of the additional natural gas reserves requires significant capital expenditures by others for exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to our pipeline system. 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, adversely impacting our ability to fill the capacities of our transportation facilities.

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 wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Additionally, the competition for natural gas supplies to serve other markets could reduce the amount of natural gas supply for our customers. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas transported on our pipeline and cash flows associated with the transportation of natural gas, our customers must compete with others to obtain adequate supplies of natural gas. In addition, if natural gas prices in the supply basins connected to our pipeline systems are higher than prices in other natural gas producing regions, our ability to compete with other transporters may be negatively impacted on a short-term basis, as well as with respect to our long-term recontracting activities.

If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply basins, if natural gas supplies are diverted to serve other markets, if development in new supply basins where we do not have significant gathering or pipeline systems reduces demand for our services, or if environmental regulators restrict new natural gas drilling, the overall volume of natural gas transported and stored on our system would decline, which could have a material adverse effect on our business, financial condition, and results of operations.

Decreases in demand for natural gas could adversely affect our business.

Demand for our transportation services depends on the ability and willingness of shippers with access to our facilities to satisfy their demand 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, or technological advances in fuel economy and energy generation devices, all of which are matters beyond our control.

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

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

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

We could experience unexpected leaks or ruptures on our gas pipeline system, or be required by regulatory authorities to test or undertake modifications to our systems that could result in a material adverse impact on our business, financial condition, and results of operations if the cost of testing, maintaining, or repairing our facilities exceed current expectations and the FERC or competition in our markets do not allow us to recover such costs in the rates we charge for our service. For example, in response to a recent third party pipeline rupture, PHMSA issued an Advisory Bulletin which, among other things, advises pipeline operators that if they are relying on design, construction, inspection, testing or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable, and complete. More recently, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 became law and under this statute PHMSA may issue additional regulations addressing such records. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities to meet the demands of such pressures, could significantly increase our costs. Additionally, failure to locate such records or verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity on our pipeline.

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

Public and regulatory scrutiny of the energy industry has resulted in increased regulations being either proposed or implemented. Such scrutiny has also resulted in various inquiries, investigations and court proceedings. Both the shippers on our pipelines 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 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 against us including environmental matters, suits, regulatory appeals and similar matters might result in adverse decisions against us. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.

In addition, existing regulations might be revised or reinterpreted, new laws and regulations might be adopted or become applicable to us, our facilities or our customers, and future changes in laws and regulations could have a material adverse effect on our financial condition and results of operations. For example, various legislative and regulatory reforms associated with pipeline safety and integrity have been proposed recently, including the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 enacted on January 3, 2012. This law will result in the promulgation of new regulations to be administered by PHMSA affecting the operations of our gas pipeline system including, but not limited to, requirements relating to pipeline inspection, installation of additional valves and other equipment and records verification. These reforms and any future changes in related laws and regulations could significantly increase our costs.

We are subject to risks associated with climate change and the regulation of greenhouse gas emissions.

Climate change and the costs that may be associated with its impacts and with the regulation of emissions of greenhouse gases (GHGs) have the potential to affect our business in many ways, including negatively impacting the costs we incur in providing our products and services, the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks.

In addition, legislative and regulatory responses related to GHGs and climate change create the potential for financial risk.

The U.S. Environmental Protection Agency (EPA) has issued a final determination that six GHG emissions are a threat to public safety and welfare and implemented permitting for new and/or modified large sources of GHG emissions. Increased public awareness and concern over climate change may result in additional state, regional, and/or federal requirements to reduce or mitigate GHG emissions. The U.S. Congress and certain states have for some time been considering various forms of legislation related to GHG emissions and additional regulation of GHG emission in our industry may be implemented under existing Clean Air Act programs. There have also been international efforts seeking legally binding reductions in emissions of GHGs.

Regulatory actions by the EPA or the passage of new climate change laws or regulations could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products and services by making our products and services less desirable than competing sources of energy.

Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs, liabilities, and expenditures that could exceed current expectations.

Substantial costs, liabilities, delays, and other significant issues related to environmental laws and regulations are inherent in the transportation and storage of natural gas, and as a result, we may be required to make substantial expenditures that could exceed current expectations. Our operations are subject to extensive federal, state, tribal, and local laws and regulations governing environmental protection, endangered and threatened species, the discharge of materials into the environment, and the security of chemical and industrial facilities.

Various governmental authorities, including the EPA, the U.S. Department of the Interior, the Bureau of Indian Affairs, and analogous state agencies and tribal governments, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, and delays in granting permits.

There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to our handling of the products as they are transported and stored, air emissions related to our operations, historical industry operations, waste and waste disposal practices, and the prior use of flow meters containing mercury. 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 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. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.

Our business may be adversely affected by changed regulations and increased costs due to stricter pollution control requirements or liabilities resulting from noncompliance with required operating or other regulatory permits. We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretation of those laws and regulations. If the interpretation of the laws and regulations themselves change, our assumptions and expectations may also change and any new capital costs incurred to comply with such changes may not be recoverable under our regulatory rate structure or our customer contracts. We might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to our business, financial condition, results of operations, and cash flows.

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.

Increased regulation of energy extraction activities, including hydraulic fracturing, could result in reductions or delays in drilling and completing new oil and natural gas wells, which could decrease the volumes of natural gas that we transport.

Hydraulic fracturing, a practice involving the injection of water, sand, and chemicals under pressure into tight geologic formations to stimulate oil and natural gas production, is currently exempt from federal regulation pursuant to the federal Safe Drinking Water Act (except when the fracturing fluids or propping agents contain diesel fuels). However, public concerns have been raised related to its potential environmental impact, and there have been recent initiatives at the federal, state, and local levels to regulate or otherwise restrict the use of hydraulic fracturing. Several states have adopted regulations that impose permitting, disclosure, and well completion requirements on hydraulic fracturing operations. The EPA has also announced regulatory and enforcement initiatives related to hydraulic fracturing and other natural gas production activities. We cannot predict whether any additional federal, state, or local laws or regulations will be enacted in this area, and if so, what their provisions would be. If new regulations are imposed related to oil and gas extraction, or if additional levels of reporting, regulation or permitting moratoria are required or imposed related to hydraulic fracturing, the volumes of natural gas that we transport, could decline and our results of operations could be adversely affected.

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

We rely on a limited number of customers for a significant portion of our revenues. Although some of these customers are subject to long-term contracts, we may be unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. For the year ended December 31, 2012, our two largest customers were Puget Sound Energy, Inc. and Northwest Natural Gas Company. These customers accounted for approximately 33.8 percent of our operating revenues for the year ended December 31, 2012. The loss of all, or even a portion of, the revenues from contracted volumes supplied by these customers, as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition, and cash flows, unless we are able to acquire comparable volumes from other sources.

We are exposed to the credit risk of our customers, and our credit risk management may not be adequate to protect against such risk.

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers in the ordinary course of our business. Generally, our customers are rated investment grade, are otherwise considered creditworthy, or are required to make pre-payments or provide security to satisfy credit concerns. However, our credit procedures and policies may not be adequate to fully eliminate customer credit risk. We cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including declines in our customers’ creditworthiness. If we fail to adequately assess the creditworthiness of existing or future customers, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off doubtful accounts. Such write-downs or write-offs could negatively affect our operating results for the period in which they occur, and, if significant, could have a material adverse effect on our business, results of operations, cash flows, and financial condition.

The failure of counterparties to perform their contractual obligations could adversely affect our operating results and financial condition.

Despite performing credit analysis prior to extending credit, we are exposed to the credit risk of our contractual counterparties in the ordinary course of business even though we monitor these situations and attempt to take appropriate measures to protect ourselves. In addition to credit risk, counterparties to our commercial agreements, such as transportation and storage agreements, may fail to perform their other contractual obligations. A failure of counterparties to perform their contractual obligations could cause us to write down or write off doubtful accounts, which could materially adversely affect our operating results and financial condition.

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

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

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

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

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

We are not fully insured against all risks inherent to our business, including environmental accidents. We do not maintain insurance in the type and amount to cover all possible risks of loss.

Williams currently maintains excess liability insurance with limits of $610 million per occurrence and in the annual aggregate with a $2 million per occurrence deductible. This insurance covers Williams, its subsidiaries, and certain of its affiliates, including us, for legal and contractual liabilities arising out of bodily injury or property damage, including resulting loss of use to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability for full limits, with the first $135 million of insurance also providing gradual pollution liability coverage for natural gas and natural gas liquids operations.

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

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

Furthermore, any insurance company that provides coverage to us may experience negative developments that could impair their ability to pay any of our claims. As a result, we could be exposed to greater losses than anticipated and may have to obtain replacement insurance, if available, at a greater cost.

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.

Execution of our capital projects subjects us to construction risks, increases in labor costs and materials, and other risks that may adversely affect financial results.

Our growth may be dependent upon the construction of new transportation and storage facilities as well as the expansion of existing facilities. Construction or expansion of these facilities is subject to various regulatory, development and operational risks, including:

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the ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on acceptable terms;

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the availability of skilled labor, equipment, and materials to complete expansion projects;

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potential changes in federal, state and local statutes and regulations, including environmental requirements, that prevent a project from proceeding or increase the anticipated cost of the project;

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impediments on our ability to acquire rights-of-way or land rights on a timely basis and on acceptable terms;

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the ability to construct projects within estimated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials, labor or other factors beyond our control, that may be material; and

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the ability to access capital markets to fund construction projects.

Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. As a result, new facilities may not achieve expected investment return, which could adversely affect our results of operations, financial position, or cash flows.

Potential changes in accounting standards might cause us to revise our financial results and disclosures in the future, which might change the way analysts measure our business or financial performance.

Regulators and legislators continue to take a renewed look at accounting practices, financial disclosures, and companies’ relationships with their independent public accounting firms. It remains unclear what new

laws or regulations will be adopted, and we cannot predict the ultimate impact that any such new laws or regulations could have. In addition, the Financial Accounting Standards Board (FASB), the SEC or FERC could issue new rules that might impact how we are required to record revenues, expenses, assets, and liabilities. Any significant change in accounting standards or disclosure requirements could have a material adverse effect on our business, results of operations, and financial condition.

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

We rely on Williams and other third parties for certain services necessary for us to be able to conduct our business. We have a limited ability to control these operations and the associated costs. Certain of Williams’ accounting and information technology functions that we rely on are currently provided by third party vendors, and sometimes from service centers outside of the United States. Services provided pursuant to these agreements could be disrupted. Similarly, the expiration of such agreements or the transition of services between providers could lead to loss of institutional knowledge or service disruptions. Our reliance on Williams and others as service providers and on Williams’ outsourcing relationships, and our limited ability to control certain costs, could have a material adverse effect on our business, results of operations, and financial condition.

Risks Related to Strategy and Financing

Restrictions in our debt agreements and our leverage may affect our future financial and operating flexibility.

Our total outstanding long-term debt, as of December 31, 2012, was $694.0 million.

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

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

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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;

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

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

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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 partnership purposes, or other purposes;

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

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Place us at a competitive disadvantage compared to our competitors that have proportionately less debt.

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, which will be affected by general economic, financial, competitive, legislative, regulatory, business and other factors, many of which are beyond our control and may differ materially from our current assumptions. 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.”

We are not prohibited under our indentures from incurring additional indebtedness. Our incurrence of significant additional indebtedness would exacerbate the negative consequences mentioned above, and could adversely affect our ability to repay our existing indebtedness.

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

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

Difficult conditions in the global capital markets, the credit 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 reduced energy demand and lower prices for our products and services, increased difficulty in collecting amounts owed to us by our customers and a reduction in our credit ratings (either due to tighter rating standards or the negative impacts described above), which could reduce our access to credit markets, raise the cost of such access or require us, WPZ or Williams to provide additional collateral to our counterparties. We have availability under the credit facility, but our ability to borrow under that facility could be impaired if one or more of our lenders fails to honor its contractual obligation to lend to us. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures. In addition, financial markets have recently been affected by concerns over U.S. fiscal policy, including uncertainty regarding federal spending and tax policy, as well as the U.S. federal government’s debt ceiling and the federal deficit. These concerns, as well as actions taken by the U.S. federal government in response to these concerns, could significantly and adversely impact the global and U.S. economies and financial markets, which could negatively impact us in the manners described above.

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

A downgrade of our credit ratings might increase our cost of borrowing and could require us to post collateral with third parties, negatively impacting our available liquidity. Our ability to access capital markets could also be limited by a downgrade of our credit ratings and other disruptions. Such disruptions could include:

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economic downturns;

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deteriorating capital market conditions;

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declining market prices for natural gas;

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terrorist attacks or threatened attacks on our facilities or those of other energy companies; and

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the overall health of the energy industry, including the bankruptcy or insolvency of other companies.

Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, 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 not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the ratings agencies and no assurance can be given that we will maintain our current credit ratings.

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

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

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payment of distributions and repayment of advances;

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decisions on financings and our capital raising activities;

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mergers or other business combinations; and

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acquisition or disposition of assets.

WPZ could decide to increase distributions or advances to our partners 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 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.

Our interstate natural gas transportation and storage operations are subject to federal, state, and local regulatory authorities. Specifically, our interstate pipeline transportation and storage services and related assets are subject to regulation by the FERC. The federal regulation extends to such matters as:

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transportation of natural gas in interstate commerce;

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rates, operating terms, and conditions of service, including initiation and discontinuation of services;

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the types of services we may offer to our customers;

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certification and construction of new interstate pipeline and storage facilities;

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acquisition, extension, disposition, or abandonment of existing interstate pipeline and storage facilities;

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accounts and records;

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depreciation and amortization policies;

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

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

Under the NGA, the FERC has authority to regulate providers of natural gas pipeline transportation and storage services in interstate commerce, and such providers may only charge rates that have been determined to be just and reasonable by the FERC. In addition, the FERC prohibits providers from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

Regulatory actions in these areas can affect our business in many ways, including decreasing tariff rates and revenues, decreasing volumes in our pipelines, increasing our costs and otherwise altering the profitability of our business.

The rates, terms and conditions for our interstate pipeline and storage services are set forth in our FERC-approved tariff. Pursuant to the terms of our most recent rate settlement agreement, we must file a new rate case to become effective not later than January 1, 2018. Any successful complaint or protest against our rates could have an adverse impact on our revenues associated with providing transportation and storage services.

We could be subject to penalties and fines if we fail to comply with laws governing our business.

Our operations are regulated by numerous governmental agencies, including the FERC, the EPA and PHMSA. Should we fail to comply with applicable statutes, rules, regulations, and orders, we could be subject to substantial penalties and fines. For example, under the Energy Policy Act of 2005, the FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1,000,000 per day for each violation and under the recently enacted Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has civil penalty authority up to $200,000 per day with a maximum of $2 million for any related series of violations. Any material penalties or fines under these or other statutes, rules, regulations or orders could have a material adverse impact on our business, financial condition, results of operations, and cash flows.

The outcome of future rate cases to set the rates we can charge customers on our pipeline might result in rates that lower our return on the capital that we have invested in our pipeline.

There is a risk that rates set by FERC in our future rate cases will be inadequate to recover increases in operating costs or to sustain an adequate return on capital investments. There is also the risk that higher rates will cause our customers to look for alternative ways to transport their natural gas.

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

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

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

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

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

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

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

Risks Related to Weather, Other Natural Phenomena and Business Disruption

Our assets and operations can be affected by weather and other natural phenomena.

Our 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 these assets and operations. Insurance may be inadequate, and in some instances, we have been unable to obtain insurance on commercially reasonable terms or insurance has not been available at all. A significant disruption in operations or a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations, and financial condition.

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

Our assets and the assets of our customers and others may be targets of terrorist activities that could disrupt our business or cause significant harm to our operations, such as full or partial disruption to our ability to transport natural gas. Acts of terrorism as well as events occurring in response to or in connection with acts of terrorism could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our financial condition, results of operations, and cash flows.

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

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

Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-to-day operations. Breaches in our information technology infrastructure or physical facilities, or other disruptions, could result in damage to our assets, safety incidents, damage to the environment, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position and results of operations.

Item 1B.

UNRESOLVED STAFF COMMENTS

None.

Item 2.

PROPERTIES

Our gas pipeline facilities are generally owned in fee. However, a substantial portion of such facilities is constructed and maintained on and across properties owned by others pursuant to rights-of-way, easements, permits, licenses or consents. Our compressor stations, with associated facilities, are located in whole or in part upon lands owned by us and upon sites held under leases or permits issued or approved by public authorities. Land owned by others, but used by us under rights-of-way, easements, permits, leases, licenses, or consents, includes land owned by private parties, federal, state and local governments, quasi-governmental agencies, or Native American tribes. The Plymouth LNG facility is located on lands owned in fee simple by us. Various credit arrangements restrict the sale or disposal of a major portion of our pipeline system. We lease our company offices in Salt Lake City, Utah.

Item 3.

LEGAL PROCEEDINGS

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

Item 4.

MINE SAFETY DISCLOSURES

Not applicable.

PART II

Item 5.

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

We are indirectly owned 100 percent by WPZ, a publicly traded master limited partnership, and Williams holds an approximate 70 percent interest in WPZ, comprised of an approximate 68 percent limited partner interest and all of WPZ’s 2 percent general partner interest. Our partnership interest is not publicly traded.

We paid $137.5 million and $127.0 million in cash distributions to our partners during 2012 and 2011, respectively.

Item 6.

SELECTED FINANCIAL DATA

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

Item 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

GENERAL

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

CRITICAL ACCOUNTING ESTIMATES

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

Regulatory Accounting

We are regulated by the FERC. The Accounting Standards Codification Topic 980, Regulated Operations (Topic 980) provides that rate-regulated public utilities account for and report regulatory assets and liabilities consistent with the economic effect of the way in which regulators establish rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Accounting for businesses that are regulated and apply the provisions of Topic 980 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset retirement obligations and other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, our management has determined that it is appropriate to apply the accounting prescribed by Topic 980 and, accordingly, the accompanying financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Balance Sheet and included in the Statement of Comprehensive Income for the period in which the discontinuance of regulatory accounting treatment occurs, unless otherwise required to be recorded under other provisions of accounting principles generally accepted in the United States. The aggregate amounts of regulatory assets reflected in the Balance Sheet are $62.8 million and $61.9 million at December 31, 2012 and 2011, respectively. The aggregate amounts of regulatory liabilities reflected in the Balance Sheet are $17.4 million and $20.9 million at December 31, 2012 and 2011, respectively. A summary of regulatory assets and liabilities is included in Note 9 of Notes to Financial Statements.

RESULTS OF OPERATIONS

Analysis of Financial Results

This analysis discusses financial results of our operations for the years 2012 and 2011. Variances due to changes in natural gas prices and transportation volumes have little impact on revenues, because under our rate design methodology, the majority of overall cost of service is recovered through firm capacity reservation charges in our transportation rates.

Our operating revenues increased $3.4 million, or 1 percent. This increase is primarily attributed to higher reservation charges.

Our transportation service and gas storage service accounted for 97 percent and 3 percent, respectively, of our operating revenues for both periods.

Total operating expenses increased $19.0 million, or 8 percent. This increase is due primarily to i) higher allocated overhead from affiliates of $8.6 million, due in part to Williams’ spin-off of its former exploration and production business in 2011; ii) higher depreciation of $2.9 million, attributed to property additions; iii) higher group insurance expense of $2.0 million; iv) higher pension costs of $1.7 million; v) higher contractual services of $1.5 million, primarily attributed to increased expenditures on pipeline maintenance; vi) higher labor of $1.1 million; and vii) higher employee incentive compensation expense of $1.1 million.

Effects of Inflation

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

CAPITAL RESOURCES AND LIQUIDITY

Method of Financing

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

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

In September 2012, WPZ amended its existing $2 billion senior unsecured revolving credit facility agreement with Northwest and Transcontinental Gas Pipe Line, LLC (Transco) as co-borrowers to increase the aggregate commitments by $400 million. The facility was also amended to provide an additional $400 million increase to be available under certain conditions in the future. The full amount of the $2.4 billion credit facility is available to WPZ. We may borrow up to $400 million under the Credit Facility to the extent not otherwise utilized by WPZ and Transco.

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

Capital Expenditures

We categorize our capital expenditures as either maintenance capital expenditures or expansion capital expenditures. Maintenance capital expenditures are those expenditures required to maintain the existing operating capacity and service capability of our assets, including replacement of system components and equipment that are worn, obsolete, completing their useful life, or necessary to remain in compliance with environmental laws and regulations. Expansion capital expenditures improve the service capability of the existing assets, increase transmission or storage capacities from existing levels or enhance revenues. We anticipate 2013 capital expenditures will be between $95 million and $115 million. Of this total, $50 million to $60 million is considered nondiscretionary due to legal, regulatory, and/or contractual requirements. In 2013, we expect to fund our capital expenditures with cash from operations.

Property, plant, and equipment additions were $134.3 million, $115.1 million and $120.2 million for 2012, 2011, and 2010, respectively.

Item 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

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


	December 31, 2012
Fixed rates on long-term debt:
5.95% senior unsecured notes due 2017	$	185,000
6.05% senior unsecured notes due 2018		250,000
7.00% senior unsecured notes due 2016		175,000
7.125% senior unsecured notes due 2025		85,000

		695,000
Unamortized debt discount		(973	)

Total long-term debt	$	694,027

Our total long-term debt at December 31, 2012 had a carrying value of $694.0 million and a fair market value of $840.2 million. As of December 31, 2012, the weighted-average interest rate on our long-term debt was 6.4 percent.

Item 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS


	Page
Management’s Annual Report on Internal Control over Financial Reporting		26

Report of Independent Registered Public Accounting Firm		27

Statement of Comprehensive Income		28

Balance Sheet		29

Statement of Owners’ Equity		31

Statement of Cash Flows		32

Notes to Financial Statements		33

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER

FINANCIAL REPORTING

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

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

Under the supervision and with the participation of our management, including our Senior Vice President — West and our Vice President and Chief Accounting Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2012, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment, we concluded that, as of December 31, 2012, our internal control over financial reporting was effective.

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.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Management Committee of

Northwest Pipeline GP

We have audited the accompanying balance sheets of Northwest Pipeline GP as of December 31, 2012 and 2011, and the related statements of income, comprehensive income, owner’s equity, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Northwest Pipeline GP at December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Ernst & Young LLP

Houston, Texas

February 27, 2013

NORTHWEST PIPELINE GP

STATEMENT OF COMPREHENSIVE INCOME

(Thousands of Dollars)


	Years Ended December 31,
	2012			2011			2010
OPERATING REVENUES	$	437,835		$	434,484		$	421,817

OPERATING EXPENSES:
General and administrative		68,473			55,735			54,067
Operation and maintenance		75,371			72,701			68,611
Depreciation		93,419			90,486			87,915
Regulatory credits		(494	)		(1,023	)		(1,662	)
Taxes, other than income taxes		19,484			19,356			18,106

Total operating expenses		256,253			237,255			227,037

Operating income		181,582			197,229			194,780

OTHER (INCOME) AND OTHER DEDUCTIONS:
Interest on long-term debt		44,439			44,439			44,458
Other interest		1,918			1,994			2,664
Allowance for equity and borrowed funds used during construction		(2,291	)		(2,101	)		(2,824	)
Miscellaneous other (income) deductions, net		793			84			955

Total other (income) and other deductions		44,859			44,416			45,253

NET INCOME		136,723			152,813			149,527
CASH FLOW HEDGES:
Amortization of cash flow hedges		(62	)		(62	)		(62	)

COMPREHENSIVE INCOME	$	136,661		$	152,751		$	149,465

See accompanying notes.

NORTHWEST PIPELINE GP

BALANCE SHEET

(Thousands of Dollars)


	December 31,		December 31,
	2012		2011
ASSETS
CURRENT ASSETS:
Cash	$	117	$	37
Receivables:
Trade		39,836		37,352
Affiliated companies		1,683		2,250
Advances to affiliate		29,322		52,024
Other		6,700		893
Materials and supplies, less reserves of $81 at December 31, 2012 and $816 at December 31, 2011		10,137		10,488
Exchange gas due from others		3,426		3,441
Exchange gas offset		1,277		—
Prepayments and other		3,353		3,469

Total current assets		95,851		109,954

PROPERTY, PLANT AND EQUIPMENT, at cost		3,163,489		3,068,915
Less-Accumulated depreciation		1,159,944		1,076,943

Total property, plant and equipment, net		2,003,545		1,991,972

OTHER ASSETS:
Deferred charges		7,918		10,250
Regulatory assets		60,298		59,605

Total other assets		68,216		69,855

Total assets	$	2,167,612	$	2,171,781

See accompanying notes.

NORTHWEST PIPELINE GP

BALANCE SHEET

(Thousands of Dollars)


	December 31,		December 31,
	2012		2011
LIABILITIES AND OWNER’S EQUITY
CURRENT LIABILITIES:
Payables:
Trade	$	18,383	$	13,634
Affiliated companies		10,912		8,812
Accrued liabilities:
Taxes, other than income taxes		10,961		10,252
Interest		4,045		4,045
Exchange gas due to others		6,572		10,472
Exchange gas offset		—		2,241
Other		4,467		5,006

Total current liabilities		55,340		54,462

LONG-TERM DEBT		694,027		693,831
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES		90,007		103,041
CONTINGENT LIABILITIES AND COMMITMENTS (Note 3)
OWNER’S EQUITY:
Owner’s capital		1,060,592		1,051,962
Retained earnings		267,432		268,209
Accumulated other comprehensive income		214		276

Total owner’s equity		1,328,238		1,320,447

Total liabilities and owner’s equity	$	2,167,612	$	2,171,781

See accompanying notes.

NORTHWEST PIPELINE GP

STATEMENT OF OWNER’S EQUITY

(Thousands of Dollars)


	Years Ended December 31,
	2012			2011			2010
Owner’s capital -
Balance at beginning of period	$	1,051,962		$	1,046,862		$	1,027,862
Capital contributions from parent		8,630			5,100			19,000

Balance at end of period		1,060,592			1,051,962			1,046,862

Loans (to) from affiliate -
Balance at beginning of period		—			—			(105,431	)
Loans (to) from affiliate		—			—			105,431

Balance at end of period		—			—			—

Retained earnings -
Balance at beginning of period		268,209			242,396			284,319
Net income		136,723			152,813			149,527
Cash distributions		(137,500	)		(127,000	)		(191,450	)

Balance at end of period		267,432			268,209			242,396

Accumulated other comprehensive income (loss) -
Balance at beginning of period		276			338			400
Cash flow hedges:
Reclassification of gain into earnings		(62	)		(62	)		(62	)

Balance at end of period		214			276			338

Total owner’s equity	$	1,328,238		$	1,320,447		$	1,289,596

See accompanying notes.

NORTHWEST PIPELINE GP

STATEMENT OF CASH FLOWS

(Thousands of Dollars)


	Years Ended December 31,
	2012			2011			2010
OPERATING ACTIVITIES:
Net income	$	136,723		$	152,813		$	149,527
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation		93,419			90,486			87,915
Regulatory credits		(494	)		(1,023	)		(1,662	)
Loss on sale of property, plant and equipment		—			6			—
Amortization of deferred charges and credits		1,578			1,491			2,293
Allowance for equity funds used during construction		(1,564	)		(1,438	)		(1,947	)
Changes in current assets and liabilities:
Trade and other accounts receivable		(8,291	)		270			1,927
Affiliated receivables		567			(132	)		2,396
Exchange gas due from others		(1,262	)		402			1,262
Materials and supplies		351			1,231			(1,759	)
Other current assets		116			(54	)		826
Trade accounts payable		6,305			(597	)		(559	)
Affiliated payables		2,100			(1,462	)		(13,026	)
Exchange gas due to others		1,262			(402	)		(1,262	)
Other accrued liabilities		169			827			985
Changes in noncurrent assets and liabilities:
Deferred charges		(4,015	)		(2,829	)		(5,865	)
Other deferred credits		5,442			4,769			8,148

Net cash provided by operating activities		232,406			244,358			229,199

FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		—			—			8,000
Retirement of long-term debt		—			—			(8,000	)
Capital contributions from parent		8,630			5,100			19,000
Distributions paid		(137,500	)		(127,000	)		(191,450	)
Other		329			657			(1,209	)

Net cash used in financing activities		(128,541	)		(121,243	)		(173,659	)

INVESTING ACTIVITIES:
Property, plant and equipment-
Capital expenditures*		(134,330	)		(115,111	)		(120,236	)
Proceeds from sales		7,843			(993	)		3,913
Repayments from (advances to) affiliates		22,702			(6,979	)		60,386

Net cash used in investing activities		(103,785	)		(123,083	)		(55,937	)

NET INCREASE (DECREASE) IN CASH		80			32			(397	)
CASH AT BEGINNING OF PERIOD		37			5			402

CASH AT END OF PERIOD	$	117		$	37		$	5


* Increases to property, plant and equipment	$	(132,445	)	$	(115,677	)	$	(117,629	)
Changes in related accounts payable and accrued liabilities		(1,885	)		566			(2,607	)

Capital expenditures	$	(134,330	)	$	(115,111	)	$	(120,236	)

See accompanying notes.

NORTHWEST PIPELINE GP

NOTES TO FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure and Control

Northwest Pipeline GP (Northwest) is indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams), and Williams holds an approximate 70 percent interest in WPZ, comprised of an approximate 68 percent limited partner interest and all of WPZ’s 2 percent general partner interest.

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

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

Nature of Operations

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

Regulatory Accounting

Our natural gas pipeline operations are regulated by the Federal Energy Regulatory Commission (FERC). FERC regulatory policies govern the rates that each pipeline is permitted to charge customers for interstate transportation and storage of natural gas. From time to time, certain revenues collected may be subject to possible refunds upon final FERC orders. Accordingly, estimates of rate refund reserves are recorded considering third-party regulatory proceedings, advice of counsel, our estimated risk-adjusted total exposure, market circumstances and other risks. Our current rates were approved pursuant to a rate settlement. As a result, our current revenues are not subject to refund.

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

Basis of Presentation

Certain prior period amounts reported within Total operating expenses in the Statement of Comprehensive Income have been reclassified to conform to the current presentation. The effect of the correction increased Operation and maintenance costs and decreased General and administrative expenses, with no net impact on Total operating expenses, Operating income, or Net Income. The adjustments were $3.5 million and $3.1 million in 2011 and 2010, respectively.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

NORTHWEST PIPELINE GP

NOTES TO FINANCIAL STATEMENTS

Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) litigation-related contingencies; 2) environmental remediation obligations; 3) impairment assessments of long-lived assets; 4) depreciation; and 5) asset retirement obligations.

Revenue Recognition

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

In the course of providing transportation services to our customers, we may receive or deliver different quantities of gas from shippers than the quantities delivered or received on behalf of those shippers. These transactions result in imbalances, which are typically settled through the receipt or delivery of gas in the future. Customer imbalances to be repaid or recovered in-kind are recorded as exchange gas due from others or due to others in the accompanying balance sheets. The exchange gas offset represents the gas balance in our system representing the difference between the exchange gas due to us from customers and the exchange gas that we owe to customers. 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 Platts “Gas Daily Price Guide.” Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions.

As a result of the ratemaking process, certain revenues collected by us may be subject to possible refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and third-party regulatory proceedings, advice of counsel and other risks. At December 31, 2012, we had no rate refund liabilities.

Environmental Matters

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

Property, Plant, and Equipment

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

NORTHWEST PIPELINE GP

NOTES TO FINANCIAL STATEMENTS

We provide for depreciation using the straight-line method at FERC prescribed rates, including negative salvage (cost of removal) for transmission and storage facilities. Depreciation of general plant is provided on a group basis at straight-line rates. Included in our depreciation rates is a negative salvage component that we currently collect in rates. Depreciation rates used for major regulated gas plant facilities at December 31, 2012, 2011 and 2010 are as follows:


Category of Property
Storage Facilities	1.60	%	—	2.76	%
Transmission Facilities	2.80	%	—	6.82	%

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. FERC has approved the accounting for the differences between book depreciation and the Evergreen Expansion Project’s levelized depreciation as a regulatory asset with the offsetting credit recorded to a regulatory credit on the accompanying Statement of Comprehensive Income.

We recorded regulatory credits totaling $0.5 million in 2012, $1.0 million in 2011, and $1.7 million in 2010 in the accompanying Statement of Comprehensive Income. These credits relate primarily to the levelized depreciation for the Evergreen Project discussed above. The accompanying Balance Sheet reflects the related regulatory assets of $34.0 million at December 31, 2012, and $33.5 million at December 31, 2011. Such amounts will be amortized over the primary terms of the shipper agreements as such costs are collected through rates.

We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the expected timing of the future abandonment of the underlying physical assets. Measurement of AROs includes, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as market-risk premium. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and is offset by a regulatory asset. The regulatory asset is being recovered through the net negative salvage component of depreciation included in our rates, and is being amortized to expense consistent with the amounts collected in rates. The regulatory asset balances as of December 31, 2012 and 2011 were $51.9 million and $45.9 million, respectively. The full amount of the regulatory asset is expected to be recovered in future rates.

The negative salvage component of accumulated depreciation ($42.4 million and $37.9 million at December 31, 2012 and 2011, respectively) was reclassified to a noncurrent regulatory asset and has been netted against the amount of the ARO regulatory asset expected to be collected in rates.

NORTHWEST PIPELINE GP

NOTES TO FINANCIAL STATEMENTS

Impairment of Long-Lived Assets

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

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

Allowance for Borrowed and Equity Funds Used During Construction

Allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in process of construction and is included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. FERC has prescribed a formula to be used in computing separate allowances for debt and equity AFUDC. The cost of debt portion of AFUDC was $0.7 million for 2012 and 2011 and $0.9 million for 2010. The equity funds portion of AFUDC was $1.6 million, $1.4 million and $1.9 million for 2012, 2011 and 2010, respectively. Both are reflected in Other (Income) and Other Deductions. The composite rate used to capitalize AFUDC was approximately 9 percent for 2012 and 2011 and 10 percent for 2010.

Regulatory Allowance for Equity Funds Used During Construction

Prior to our conversion to a general partnership on October 1, 2007, we recorded a regulatory asset in connection with deferred income taxes associated with equity AFUDC. Since we are no longer subject to income tax following the conversion, we do not record additions to the regulatory asset associated with equity AFUDC. The pre-conversion unamortized balance of this regulatory asset will continue to be amortized consistent with the amount being recovered in rates.

Income Taxes

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

Accounts Receivable and Allowance for Doubtful Receivables

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

NORTHWEST PIPELINE GP

NOTES TO FINANCIAL STATEMENTS

Materials and Supplies Inventory

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

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

Deferred Charges

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

Pension and Other Postretirement Benefits

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

Contingent Liabilities

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

Cash Flows from Operating Activities and Cash Equivalents

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

Interest Payments

Cash payments for interest were $44.6 million in 2012, 2011, and 2010.

2. RATE AND REGULATORY MATTERS

Rate Case Settlement Filing

On April 26, 2012, the FERC unconditionally approved Northwest’s Stipulation and Settlement Agreement (Settlement) filed on March 15, 2012. The supporting or non-opposing customers named in the Settlement represented approximately 99.5 percent of our long-term firm transportation and storage capacity. The Settlement specified an annual cost of service of $466.5 million and established a new general system firm transportation rate of $0.44 per dekatherm, a 7.4 percent increase over the previous rate. New rates became effective January 1, 2013, and will remain in effect for a minimum of 3 years and a maximum of 5 years.

NORTHWEST PIPELINE GP

NOTES TO FINANCIAL STATEMENTS

3. CONTINGENT LIABILITIES AND COMMITMENTS

Environmental Matters

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

Beginning in the mid-1980s, we evaluated many of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation might be necessary. We identified polychlorinated biphenyl (PCB) contamination in air compressor systems, soils and related properties at certain compressor station sites. Similarly, we identified hydrocarbon impacts at these facilities due to the former use of earthen pits and mercury contamination at certain natural gas metering sites. The PCBs were remediated pursuant to a Consent Decree with the U.S. Environmental Protection Agency (EPA) in the late 1980s, and we conducted a voluntary clean-up of the hydrocarbon and mercury impacts in the early 1990s. In 2005, the Washington Department of Ecology required us to re-evaluate our previous mercury clean-ups in Washington. Currently, we are conducting assessment and remediation activities for mercury and other constituents to bring the sites up to Washington’s current environmental standards. At December 31, 2012, we had accrued liabilities totaling approximately $6.4 million for these costs which are expected to be incurred through 2017. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs.

In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. However, in September 2009, the EPA announced it would reconsider the 2008 NAAQS for ground-level ozone to ensure that the standards were clearly grounded in science, and were protective of both public health and the environment. As a result, the EPA delayed designation of new eight-hour ozone non-attainment areas under the 2008 standards until the reconsideration is complete. In January 2010, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels. In September 2011, the EPA announced that it was proceeding with required actions to implement the 2008 ozone standard and area designations. In May 2012, the EPA completed designation of new eight-hour ozone non-attainment areas. Based on the published designations, no Northwest facilities are located within the non-attainment areas. At this time, it is unknown whether future state regulatory actions associated with implementation of the 2008 ozone standard will impact our operations and increase the cost of additions to property, plant and equipment. Until any additional state regulatory actions are proposed, we are unable to estimate the cost of additions that may be required to meet any such new regulation.

Additionally, in August 2010, the EPA promulgated National Emission Standards for hazardous air pollutants (NESHAP) regulations that will impact our operations. The emission control additions required to comply with the hazardous air pollutant regulations are estimated to include capital costs in the range of $500 thousand to $1 million through 2013, the compliance date.

NORTHWEST PIPELINE GP

NOTES TO FINANCIAL STATEMENTS

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

Safety Matters

Pipeline Integrity Regulations We have developed an Integrity Management Plan that we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for transmission pipelines that could affect high consequence areas in the event of pipeline failure. The Integrity Management Program includes a baseline assessment plan along with periodic reassessments to be completed within required timeframes. In meeting the integrity regulations, we identified high consequence areas and developed our baseline assessment plan. The required pipeline segments originally identified for assessment were completed within the required timeframes.

Other Matters

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

Summary

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

Other Commitments

We have commitments for construction and acquisition of property, plant and equipment of approximately $17.0 million at December 31, 2012.

NORTHWEST PIPELINE GP

NOTES TO FINANCIAL STATEMENTS

4. DEBT, FINANCING ARRANGEMENTS, AND LEASES

Long-Term Debt

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


	December 31,
	2012		2011
	(Thousands of Dollars)
5.95% senior unsecured notes due 2017	$	184,726	$	184,662
6.05% senior unsecured notes due 2018		249,639		249,573
7% senior unsecured notes due 2016		174,809		174,754
7.125% unsecured debentures due 2025		84,853		84,842

Total long-term debt	$	694,027	$	693,831

As of December 31, 2012, cumulative maturities of outstanding long-term debt (at face value) for the next five years are as follows:


	(Thousands
	of Dollars)
2016: 7% senior unsecured notes	$	175,000
2017: 5.95% senior unsecured notes		185,000

Total	$	360,000

In the second quarter of 2006, we entered into certain forward starting interest rate swaps prior to our issuance of fixed rate, long-term debt. The swaps, which were settled near the date of the June 2006 debt issuance, hedged the variability of forecasted interest payments arising from changes in interest rates prior to the issuance of our fixed rate debt. The settlement resulted in a gain, recorded in accumulated other comprehensive income, that is being amortized to reduce interest expense over the life of the related debt.

Restrictive Debt Covenants

At December 31, 2012, none of our debt instruments restrict the amount of distributions to our parent. Our debt agreements contain restrictions on our ability to incur secured debt beyond certain levels.

Credit Facility

In September 2012, WPZ amended its existing $2 billion senior unsecured revolving credit facility agreement to increase the aggregate commitments by $400 million. This facility was also amended to provide an additional $400 million increase to be available under certain conditions in the future. We may borrow up to $400 million under the credit facility to the extent not otherwise utilized by WPZ and Transcontinental Gas Pipe Line Company, LLC.

Under the credit facility, WPZ is required to maintain a ratio of debt to EBITDA (each as defined in the credit facility) that must be no greater than 5.0 to 1.00. For the fiscal quarter and the two following fiscal quarters in which one or more acquisitions for a total aggregate purchase price equal to or greater than $50 million has been executed, WPZ is required to maintain a ratio of debt to EBITDA of no greater than 5.5 to 1.00. For us, the ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent. At December 31, 2012, we are in compliance with these financial covenants.

NORTHWEST PIPELINE GP

NOTES TO FINANCIAL STATEMENTS

Each time funds are borrowed, the borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.’s alternate base rate plus an applicable margin, or a periodic fixed rate equal to London Interbank Offered Rate (LIBOR) plus an applicable margin. The borrower is required to pay a commitment fee (currently 0.20 percent) based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings. The credit facility contains various covenants that limit, among other things, a borrower’s and its respective material subsidiaries’ ability to grant certain liens supporting indebtedness, a borrower’s ability to merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, make investments and allow any material change in the nature of its business.

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

Total letter of credit capacity available to WPZ under the $2.4 billion credit facility is $1.3 billion. At December 31, 2012, no letters of credit have been issued and $375 million of loans are outstanding under the credit facility. At December 31, 2012, the full $400 million under the credit facility was available to us.

Leases

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

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

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


	(Thousands
	of Dollars)
2013	$	2,415
2014		2,415
2015		2,441
2016		2,467
2017		2,494

Total	$	12,232

Operating lease rental expense, net of sublease revenues, amounted to $2.2 million, $2.4 million, and $2.2 million for 2012, 2011, and 2010, respectively.

NORTHWEST PIPELINE GP

NOTES TO FINANCIAL STATEMENTS

5. BENEFIT PLANS

Certain of the benefit costs charged to us by Williams associated with employees who directly support us are described below. Additionally, allocated corporate expenses from Williams to us also include amounts related to these same employee benefits, which are not included in the amounts presented below. See Note 7. Transactions with Major Customers and Affiliates – Related Party Transactions.

Pension and Other Postretirement Benefit Plans

Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan, and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible employees. Pension cost charged to us by Williams was $7.3 million in 2012, $5.7 million in 2011 and $6.1 million in 2010.

Williams provides certain retiree health care and life insurance benefits for eligible participants that generally were employed by Williams on or before December 31, 1991. No other postretirement benefit expense was recognized in 2012, 2011, or 2010.

Defined Contribution Plan

Included in compensation expense is $2.5 million in 2012, $2.4 million in 2011, and $2.2 million in 2010 that Williams charged us for matching contributions to this plan.

Employee Stock-Based Compensation Plan Information

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

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

Total stock-based compensation expense, included in administrative and general expenses, for the years ended December 31, 2012, 2011 and 2010 was $1.5 million, $1.2 million and $1.4 million, respectively, excluding amounts allocated from WPZ, and Williams.

6. FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

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

Cash and advances to affiliate—The carrying amounts of these items approximates their fair value.

Long-term debt – The disclosed fair value of our long-term debt, which we consider as a level 2 measurement, is determined by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The carrying amount and estimated fair value of our long-term debt, including current maturities, were $694.0 million and $840.2 million, respectively, at December 31, 2012, and $693.8 million and $826.3 million, respectively, at December 31, 2011.

NORTHWEST PIPELINE GP

NOTES TO FINANCIAL STATEMENTS

7. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES

Concentration of Off-Balance-Sheet and Other Credit Risk

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


	Years Ended December 31,
	2012		2011		2010
	(Thousands of Dollars)
Puget Sound Energy, Inc.	$	100,799	$	99,116	$	95,564
Northwest Natural Gas Co.		47,297		47,322		48,022

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

Related Party Transactions

We are a participant in WPZ’s cash management program. At December 31, 2012 and 2011, the advances due to us by WPZ totaled approximately $29.3 million and $52.0 million, respectively. These advances are represented by demand notes. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on WPZ’s excess cash at the end of each month, which was approximately 0.01 percent at December 31, 2012. The interest income from these advances was minimal during the years ended December 31, 2012, 2011, and 2010. Such interest income is included in “Other (Income) and Other Deductions: Miscellaneous other (income) deductions, net” on the accompanying Statement of Comprehensive Income.

Williams charges its subsidiary companies for management services provided by it and other affiliated companies. Such corporate expenses charged by Williams, WPZ, and other affiliated companies, for the years ended December 31, 2012, 2011, and 2010, were $44.0 million, $35.4 million, and $34.1 million, respectively. These expenses are included in “General and administrative” expense on the accompanying Statement of Comprehensive Income. Management considers the cost of these services to be reasonable.

We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. In return, we reimburse Williams for all direct and indirect expenses it incurs or payments it makes (including salary, bonus, incentive compensation, pension and other benefits) in connection with these services. For the years ended December 31, 2012, 2011 and 2010, we were billed $69.0 million, $62.6 million, and $60.6 million, respectively. Such expenses are primarily included in “General and administrative” and “Operation and maintenance” expenses on the accompanying Statement of Comprehensive Income.

During the periods presented, our revenues include transportation transactions and rental of communication facilities with subsidiaries of Williams. Combined revenues for these activities, for the year ended December 31, 2012, were minimal. Combined revenues for these activities, for the years ended December 31, 2011 and 2010, were $24.7 million and $6.8 million, respectively. The reduction in revenues from 2011 is a result of Williams’ spin-off of its former exploration and production business, which was completed on December 31, 2011. These revenues, associated with transportation transactions, are now reflected with the revenues from outside parties.

NORTHWEST PIPELINE GP

NOTES TO FINANCIAL STATEMENTS

During 2012, 2011, and 2010, we declared and paid equity distributions to our parent of $137.5 million, $127.0 million, and $191.5 million, respectively.

During 2012, 2011, and 2010, we received contributions of $8.6 million, $5.1 million, and $19.0 million from our parent to fund a portion of our expenditures for additions to property, plant, and equipment.

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

8. ASSET RETIREMENT OBLIGATIONS

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

During 2012 and 2011, our overall asset retirement obligation changed as follows (in thousands):


	2012			2011
Beginning balance	$	80,313		$	65,155
Accretion		5,543			5,162
New obligations		15			2,257
Changes in estimates of existing obligations (1)		(18,231	)		8,116
Property Dispositions & Settlements		—			(377	)

Ending balance	$	67,640		$	80,313

(1)

Changes in estimates of existing obligations are primarily due to the annual review process, which considers various factors including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining life of assets. The increase in 2011 is primarily attributed to a decrease in the discount rate. The decrease in 2012 is primarily attributed to a decrease in removal cost estimates.

9. REGULATORY ASSETS AND LIABILITIES

Our regulatory assets and liabilities result from our application of the provisions of Topic 980 and are reflected on our balance sheet. Current regulatory assets are included in prepayments and other. Current regulatory liabilities are included in other accrued liabilities and noncurrent regulatory liabilities are included in deferred credits and other noncurrent liabilities. 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, 2012 and 2011:

NORTHWEST PIPELINE GP

NOTES TO FINANCIAL STATEMENTS


	2012		2011
	(Thousands of Dollars)
Current regulatory assets:
Environmental costs	$	1,300	$	2,200
Fuel recovery		1,249		78

Total current regulatory assets		2,549		2,278

Noncurrent regulatory assets:
Environmental costs		739		1,117
Grossed-up deferred taxes on equity funds used during construction		16,083		17,034
Levelized depreciation		33,979		33,485
Asset retirement obligations, net		9,497		7,969

Total noncurrent regulatory assets		60,298		59,605

Total regulatory assets	$	62,847	$	61,883

Current regulatory liabilities:
Fuel recovery	$	—	$	3,562

Noncurrent regulatory liabilities:
Postretirement benefits		17,395		17,386

Total regulatory liabilities	$	17,395	$	20,948

The significant regulatory assets and liabilities include:

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

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

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

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

Asset Retirement Obligations We record an asset and a liability equal to the present value of each expected future ARO. The ARO asset is depreciated in a manner consistent with the expected future abandonment of the underlying physical assets. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and is offset by a regulatory asset. The regulatory asset is being recovered through the net negative salvage component of depreciation included in our rates, and is being amortized to expense consistent with the amounts collected in rates.

NORTHWEST PIPELINE GP

NOTES TO FINANCIAL STATEMENTS

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.

NORTHWEST PIPELINE GP

QUARTERLY FINANCIAL DATA

(Unaudited)

The following is a summary of unaudited quarterly financial data for 2012 and 2011:


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

	Quarter of 2011
	First		Second		Third		Fourth
	(Thousands of Dollars)
Operating revenues	$	109,919	$	106,576	$	107,216	$	110,773
Operating income		51,232		46,596		46,082		53,319
Net income		39,683		35,379		35,241		42,510

Item 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A.

Controls and Procedures

Disclosure Controls and Procedures

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

Evaluation of Disclosure Controls and Procedures

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

Management’s Annual Report on Internal Control over Financial Reporting

See report set forth in Item 8, “Financial Statements and Supplementary Data.”

Fourth Quarter 2012 Changes in Internal Controls

There have been no changes during the fourth quarter of 2012 that have materially affected, or are reasonably likely to materially affect, our Internal Controls over financial reporting.

Item 9B.

OTHER INFORMATION

None.

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:


	2012		2011
	(Thousands of Dollars)
Audit fees	$	752	$	800
Audit related fees		—		—
Tax fees		—		—
All other fees		—		—

	$	752	$	800

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

As a wholly-owned subsidiary of WPZ, we do not have a separate audit committee. The policies and procedures for pre-approving audit and non-audit services of the Audit Committee of the Board of Directors of WPZ’s general partner have been set forth in WPZ’s 2012 annual report on Form 10-K, which is available on the SEC’s website at http://www.sec.gov and on WPZ’s website at http://williamslp.com under the heading “Investors – SEC Filings.”

PART IV

Item 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES


	Page Reference to 2012 Form 10-K

(a) 1. and 2. Northwest Pipeline GP financials

Index

Covered by reports of independent auditors:

Statement of Comprehensive Income for the Years Ended December 31, 2012, 2011, and 2010		28

Balance Sheet at December 31, 2012 and 2011		29

Statement of Owners’ Equity for the Years Ended December 31, 2012, 2011, and 2010		31

Statement of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010		32

Notes to Financial Statements		33

Schedule II – Valuation and Qualifying Accounts for the Years Ended December 31, 2012 and 2011		51

Not covered by reports of independent auditors:

Quarterly Financial Data (Unaudited)		47

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.

(a) 2. Financial Statement Schedules

NORTHWEST PIPELINE GP

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

(Thousands of Dollars)


			Charged to
	Beginning		Costs and					Ending
Description	Balance		Expenses		Deductions			Balance
Year ended December 31, 2012:
Reserve for doubtful receivables	$	—	$	—	$	—		$	—
Reserve for obsolescence of materials and supplies		816		162		(897	)		81
Year ended December 31, 2011:
Reserve for doubtful receivables		—		—		—			—
Reserve for obsolescence of materials and supplies		613		640		(437	)		816
Year ended December 31, 2010:
Reserve for doubtful receivables		—		—		—			—
Reserve for obsolescence of materials and supplies		11		622		(20	)		613

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

(a) 3 and b. Exhibits:


Exhibit		Description

2(a)		Certificate of Conversion of Northwest Pipeline Corporation (Exhibit 2.1 to our report on Form 8-K, filed October 2, 2007 (File No. 001-07414)) and incorporated herein by reference.

3(a)		Statement of Partnership Existence of Northwest Pipeline GP (Exhibit 3.1 to our report on Form 8-K, filed October 2, 2007 (File No. 001-07414)) and incorporated herein by reference.

3(b)		Amended and Restated General Partnership Agreement of Northwest Pipeline GP (Exhibit 3.1 to our report on Form 8-K, filed January 30, 2008 (File No. 001-07414)) and incorporated herein by reference.

4(a)		Senior Indenture, dated as of November 30, 1995 between Northwest Pipeline Corporation and Chemical Bank, relating to Northwest Pipeline’s 7.125% Debentures due 2025 (Exhibit 4.1 to our Registration Statement on Form S-3, filed September 14, 1995 (File No. 033-62639)) and incorporated herein by reference.

4(b)		Indenture, dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., relating to Northwest Pipeline’s $175 million aggregate principal amount of 7.0% Senior Notes due 2016 (Exhibit 4.1 to our report on Form 8-K, filed June 23, 2006 (File No. 001-07414)) and incorporated herein by reference.

4(c)		Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York (Exhibit 4.1 to our report on Form 8-K, filed April 6, 2007 (File No. 001-07414)) and incorporated herein by reference.

4(d)		Indenture, dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trustee (Exhibit 4.1 to our Form 8-K, filed May 23, 2008 (File No. 001-07414)) and incorporated herein by reference.

10(a)		Administrative Services Agreement, dated January 24, 2008, between Northwest Pipeline GP and Northwest Pipeline Services, LLC (Exhibit 10.1 to our report on Form 8-K, filed January 30, 2008 (File No. 001-07414)) and incorporated herein by reference.

10(b)*		Assignment Agreement dated February 13, 2013, by and between Northwest Pipeline Services, LLC and Williams WPC-I, LLC, effective January 1, 2013.

10(c)		Contribution, Conveyance and Assumption Agreement, dated January 24, 2008, among Williams Pipeline Partners L.P., Williams Pipeline Operating LLC, WPP Merger LLC, Williams Pipeline Partners Holdings LLC, Northwest Pipeline GP, Williams Pipeline GP LLC, Williams Gas Pipeline Company, LLC, WGPC Holdings LLC and Williams Pipeline Services Company (Exhibit 10.2 to our report on Form 8-K, filed January 30, 2008 (File No. 001-07414)) and incorporated herein by reference.



10(d)		Credit Agreement, dated as of June 3, 2011, by and among Williams Partners L.P., Northwest Pipeline GP, and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A., as Administrative Agent (filed as Exhibit 10.1 to Williams Partners L.P.’s, No. 1-32599, quarterly report on Form 10-Q, filed on August 4, 2011 (File No. 001-32599)) and incorporated herein by reference.

10(e)		Commitment Increase and First Amendment dated as of September 25, 2012, by and among Williams Partners L.P., Northwest Pipeline GP, and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, the Issuing Banks, and Citibank N.A., as Administrative Agent (filed on September 27, 2012 as exhibit 10.1 to Williams Partners L.P.’s Form 8-K, (File No. 001-32599) and incorporated herein by reference).

31(a)*		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(b)*		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(a)**		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

SIGNATURES

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


NORTHWEST PIPELINE GP
(Registrant)

By		/s/ Jeffrey P. Heinrichs
		Jeffrey P. Heinrichs
		Controller

Date: February 27, 2013

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


Signature		Title

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

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

/s/ Jeffrey P. Heinrichs		Controller (Principal Accounting Officer)
Jeffrey P. Heinrichs

/s/ Donald R. Chappel		Management Committee Member
Donald R. Chappel

Date: February 27, 2013

EXHIBIT INDEX


Exhibit		Description

2(a)		Certificate of Conversion of Northwest Pipeline Corporation (Exhibit 2.1 to our report on Form 8-K, filed October 2, 2007 (File No. 001-07414)) and incorporated herein by reference.

3(a)		Statement of Partnership Existence of Northwest Pipeline GP (Exhibit 3.1 to our report on Form 8-K, filed October 2, 2007 (File No. 001-07414)) and incorporated herein by reference.

3(b)		Amended and Restated General Partnership Agreement of Northwest Pipeline GP (Exhibit 3.1 to our report on Form 8-K, filed January 30, 2008 (File No. 001-07414)) and incorporated herein by reference.

4(a)		Senior Indenture, dated as of November 30, 1995 between Northwest Pipeline Corporation and Chemical Bank, relating to Northwest Pipeline’s 7.125% Debentures due 2025 (Exhibit 4.1 to our Registration Statement on Form S-3, filed September 14, 1995 (File No. 033-62639)) and incorporated herein by reference.

4(b)		Indenture, dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., relating to Northwest Pipeline’s $175 million aggregate principal amount of 7.0% Senior Notes due 2016 (Exhibit 4.1 to our report on Form 8-K, filed June 23, 2006 (File No. 001-07414)) and incorporated herein by reference.

4(c)		Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York (Exhibit 4.1 to our report on Form 8-K, filed April 6, 2007 (File No. 001-07414)) and incorporated herein by reference.

4(d)		Indenture, dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trustee (Exhibit 4.1 to our Form 8-K, filed May 23, 2008 (File No. 001-07414)) and incorporated herein by reference.

10(a)		Administrative Services Agreement, dated January 24, 2008, between Northwest Pipeline GP and Northwest Pipeline Services, LLC (Exhibit 10.1 to our report on Form 8-K, filed January 30, 2008 (File No. 001-07414)) and incorporated herein by reference.

10(b)*		Assignment Agreement dated February 13, 2013, by and between Northwest Pipeline Services, LLC and Williams WPC-I, LLC, effective January 1, 2013.

10(c)		Contribution, Conveyance and Assumption Agreement, dated January 24, 2008, among Williams Pipeline Partners L.P., Williams Pipeline Operating LLC, WPP Merger LLC, Williams Pipeline Partners Holdings LLC, Northwest Pipeline GP, Williams Pipeline GP LLC, Williams Gas Pipeline Company, LLC, WGPC Holdings LLC and Williams Pipeline Services Company (Exhibit 10.2 to our report on Form 8-K, filed January 30, 2008 (File No. 001-07414)) and incorporated herein by reference.

10(d)		Credit Agreement, dated as of June 3, 2011, by and among Williams Partners L.P., Northwest Pipeline GP, and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A., as Administrative Agent (filed as Exhibit 10.1 to Williams Partners L.P.’s, No. 1-32599, quarterly report on Form 10-Q, filed on August 4, 2011 (File No. 001-32599)) and incorporated herein by reference.

10(e)		Commitment Increase and First Amendment dated as of September 25, 2012, by and among Williams Partners L.P., Northwest Pipeline GP, and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, the Issuing Banks, and Citibank N.A., as Administrative Agent (filed on September 27, 2012 as exhibit 10.1 to Williams Partners L.P.’s Form 8-K, (File No. 001-32599) and incorporated herein by reference).

31(a)*		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(b)*		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(a)**		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

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