10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2013

OR

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

For the transition period from to

Commission file number 1-7584

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

(Exact Name of Registrant as Specified in Its Charter)

Delaware	74-1079400
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)
2800 Post Oak Boulevard, Houston, Texas	77056
(Address of Principal Executive Offices)	(Zip Code)

713-215-2000

(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  þ

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    þ

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

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

(Do not check if a smaller reporting company)

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

DOCUMENTS INCORPORATED BY REFERENCE

None

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

TRANSCONTINTENTAL GAS PIPE LINE COMPANY, LLC

FORM 10-K

TABLE OF CONTENTS

		Page
	PART I
Item 1.	Business	3
Item 1A.	Risk Factors	8
Item 1B.	Unresolved Staff Comments	18
Item 2.	Properties	19
Item 3.	Legal Proceedings	19
Item 4.	Mine Safety Disclosures	19
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	19
Item 6.	Selected Financial Data (Omitted)	19
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 7A.	Quantitative and Qualitative Disclosure About Market Risk	24
Item 8.	Financial Statements and Supplementary Data	25
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosures	50
Item 9A.	Controls and Procedures	50
Item 9B.	Other Information	52
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance (Omitted)
Item 11.	Executive Compensation (Omitted)
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters (Omitted)
Item 13.	Certain Relationships and Related Transactions, and Director Independence (Omitted)
Item 14.	Principal Accountant Fees and Services	53
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	54

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DEFINITIONS

We use the following gas measurements in this report:

Bcf – means billion cubic feet.

Mdth – means thousand dekatherms.

Mdth/d – means thousand dekatherms per day.

MMdth – means million dekatherms.

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PART 1

Item 1. Business.

In this report, Transcontinental Gas Pipe Line Company, LLC (Transco) is at times referred to in the first person as “we”, “us” or “our”.

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

GENERAL

We are an interstate natural gas transmission company that owns a natural gas pipeline system extending from Texas, Louisiana, Mississippi and the Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Delaware, Pennsylvania and New Jersey to the New York City metropolitan area. We also hold a minority interest in Cardinal Pipeline Company, LLC (Cardinal), an intrastate natural gas pipeline located in North Carolina. Our principal business is the interstate transportation of natural gas which is regulated by the Federal Energy Regulatory Commission (FERC).

At December 31, 2013, our system had a mainline delivery capacity of approximately 5.9 MMdth of gas per day from production areas to our primary markets including delivery capacity from the mainline to locations on our Mobile Bay Lateral. Using our Leidy Line along with market-area storage and transportation capacity, we can deliver an additional 4.3 MMdth of gas per day for a system-wide delivery capacity total of approximately 10.2 MMdth of gas per day. The system is comprised of approximately 9,700 miles of mainline and branch transmission pipelines, 45 compressor stations, four underground storage fields and one liquefied natural gas (LNG) storage facility. Compression facilities at sea level rated capacity total approximately 1.7 million horsepower.

We have natural gas storage capacity in four underground storage fields located on or near our pipeline system and/or market areas, and we operate two of these storage fields. We also have storage capacity in an LNG storage facility that we own and operate. The total usable gas storage capacity available to us and our customers in such underground storage fields and LNG storage facility and through storage service contracts is approximately 200 Bcf of gas. At December 31, 2013, our customers had stored in our facilities approximately 143 Bcf of gas. In addition, through wholly-owned subsidiaries we operate and own a 35 percent interest in Pine Needle LNG Company, LLC (Pine Needle), an LNG storage facility with 4 Bcf of storage capacity. Storage capacity permits our customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter demand periods.

MARKETS AND TRANSPORTATION

Our natural gas pipeline system serves customers in Texas and 12 southeast and Atlantic seaboard states including major metropolitan areas in Georgia, North Carolina, Washington, D.C., Maryland, New York, New Jersey and Pennsylvania.

Our major customers are public utilities and municipalities that provide service to residential, commercial, industrial and electric generation end users. Shippers on our pipeline system include public utilities, municipalities, intrastate pipelines, direct industrial users, electrical generators, gas marketers and producers. Our two largest customers in 2013 were Public Service Enterprise Group and National Grid, which accounted for approximately 9.7 percent and 6.6 percent, respectively, of our total operating revenues. Our firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of our business. Additionally, we offer interruptible transportation services under shorter-term agreements.

Our facilities are divided into eight rate zones. Five are located in the production area and three are located in the market area. Long-haul transportation is gas that is received in one of the production-area zones and delivered in

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a market-area zone. Market-area transportation is gas that is both received and delivered within market-area zones. Production–area transportation is gas that is both received and delivered within production–area zones.

PIPELINE PROJECTS

The pipeline projects listed below were either completed during 2013 or are significant future pipeline projects for which we have customer commitments. In 2014, we expect to invest capital of approximately $660 million in pipeline expansion projects.

Mid-South

The Mid-South Expansion Project involves an expansion of our mainline from Station 85 in Choctaw County, Alabama to markets as far downstream as North Carolina. In August 2011, we received approval from the FERC for the project. The capital cost of the project was approximately $202 million. We placed the first phase of the project into service in September 2012 which increased capacity by 95 Mdth/d. We placed the second phase of the project into service in June 2013 which increased capacity by an additional 130 Mdth/d.

Mid-Atlantic Connector

The Mid-Atlantic Connector Project involves an expansion of our mainline from an existing interconnection with East Tennessee Natural Gas in North Carolina to markets as far downstream as Maryland. In July 2011, we received approval from the FERC for the project. The capital cost of the project was approximately $60 million. We placed the project into service in the first quarter of 2013, and it increased capacity by 142 Mdth/d.

Northeast Supply Link

The Northeast Supply Link Project involves an expansion of our existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in Zone 6. In November 2012, we received approval from the FERC for the project. The capital cost of the project is estimated to be approximately $390 million. We placed a portion of the project into service in the third quarter of 2013 increasing capacity by 125 Mdth/d. We placed the remaining portion into service in November 2013, and it increased capacity by an additional 125 Mdth/d.

Rockaway Delivery Lateral

The Rockaway Delivery Lateral Project involves the construction of a three-mile offshore lateral to National Grid’s distribution system in New York. We filed an application with the FERC in January 2013 for approval of the project. We plan to place the project into service during the second half of 2014, and the capacity of the lateral is expected to be 647 Mdth/d.

Northeast Connector Project

The Northeast Connector Project involves an expansion of our existing natural gas transmission system from southeastern Pennsylvania to the proposed Rockaway Delivery Lateral. We filed an application with the FERC in April 2013 for approval of the project. We plan to place the project into service during the second half of 2014, and it is expected to increase capacity by 100 Mdth/d.

Virginia Southside

The Virginia Southside Project involves an expansion of our existing natural gas transmission system from the Zone 6 Station 210 Pooling Point in New Jersey to Dominion Virginia Power’s proposed power station in Brunswick County, Virginia, and both our Cascade Creek interconnect with East Tennessee Natural Gas and our Pleasant Hill delivery point to Piedmont Natural Gas Company, Inc. in North Carolina. In November 2013, we received approval from the FERC for the project. We plan to place the project into service during the third quarter of 2015, and it is expected to increase capacity by 270 Mdth/d.

Leidy Southeast

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The Leidy Southeast Project involves an expansion of our existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line in Pennsylvania to the Station 85 pooling point in Alabama. We filed an application with the FERC in September 2013 for approval of the project. We plan to place the project into service during the fourth quarter of 2015, and it is expected to increase capacity by 525 Mdth/d.

Mobile Bay South III

The Mobile Bay South III Project involves an expansion of the Mobile Bay line south from Station 85 in west central Alabama to delivery points along the line. We filed an application with the FERC in July 2013 for approval of the project. We plan to place the project into service during the second quarter of 2015, and it is expected to increase capacity on the line by 225 Mdth/d.

Rock Springs Expansion

The Rock Springs Expansion Project involves an expansion of our existing natural gas transmission system southbound from the Zone 6 Station 210 Pooling Point in New Jersey along with a new eleven mile lateral to Old Dominion Electric Cooperative's proposed Wildcat Point generation facility in Cecil County, Maryland. We plan to file an application with the FERC in the second quarter of 2014 for approval of the project. We plan to place the project into service during the third quarter of 2016, and it is expected to increase capacity by 192 Mdth/d.

Hillabee Expansion

The Hillabee Expansion Project involves an expansion of our existing natural gas transmission system from Transco's Station 85 pooling point in Choctaw County, Alabama to a proposed new interconnection with Sabal Trail Transmission's system in Tallapoosa County, Alabama. The project will be constructed in phases and all of the project expansion capacity will be leased to Sabal Trail Transmission. We plan to file an application with the FERC in the fourth quarter of 2014 for approval of the initial phases of the project. We plan to place the initial phases of the project into service during the second quarter of 2017 and 2020, and together they are expected to increase capacity by 1,025 Mdth/d.

Atlantic Sunrise Expansion

The Atlantic Sunrise Expansion Project involves an expansion of our existing natural gas transmission system along with greenfield facilities to provide firm transportation from the northeastern Marcellus producing area to markets along Transco's mainline as far south as Station 85 in Alabama. We plan to file an application with the FERC in the second quarter of 2015 for approval of the project. We plan to place the project into service during the second half of 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 1,700 Mdth/d.

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 and volume throughput assumptions. The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the reservation and commodity rates also impact profitability. As a result of these proceedings, certain revenues may be collected subject to refund. We record estimates of rate refund liabilities considering our and third-party regulatory proceedings, advice of counsel and other risks.

Since September 1, 1992, we have designed our rates using the straight fixed-variable (SFV) method of rate design. Under the SFV method of rate design, substantially all fixed costs, including return on equity and income taxes, are included in a reservation charge to customers and all variable costs are recovered through a commodity charge to customers. While the use of SFV rate design limits our opportunity to earn incremental revenues through increased throughput, it also limits our risk associated with fluctuations in throughput.

General rate case (Docket No. RP12-993) On August 31, 2012, we submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in our Docket No.

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RP06-569 rate proceeding (see below) which required us to file a rate case no later than August 31, 2012. On September 28, 2012, the FERC issued an order accepting our filing subject to the outcome of a hearing. The rates for certain services that were proposed as overall rate decreases became effective October 1, 2012, without suspension. The increase rates became effective March 1, 2013, subject to refund and the outcome of the hearing. On August 27, 2013, after reaching an agreement in principle with the participants, we filed a stipulation and agreement (Agreement) proposing to resolve all issues in this proceeding without the need for a hearing. On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement will become effective March 1, 2014. We have provided a reserve for rate refunds which we believe is adequate for required refunds as of December 31, 2013, under the Agreement. Refunds will be made on or before April 30, 2014.

General rate case (Docket No. RP06-569) On August 31, 2006, we submitted to the FERC a general rate filing principally designed to recover increased costs. The rates became effective March 1, 2007, subject to refund and the outcome of a hearing. All issues in this proceeding except one have been resolved by settlement.

The one issue reserved for litigation or further settlement relates to our proposal to change the design of the rates for service under one of our storage rate schedules, which was implemented subject to refund on March 1, 2007. A hearing on that issue was held before a FERC Administrative Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision in which he determined that our proposed incremental rate design is unjust and unreasonable. On January 21, 2010, the FERC reversed the ALJ’s initial decision, and approved our proposed incremental rate design. Certain parties sought rehearing of the FERC’s order and, on April 2, 2012, the FERC denied the rehearing request. On June 1, 2012, one of the parties filed an appeal in the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit). On February 21, 2014, the D.C. Circuit issued an opinion that vacated and remanded the FERC's order because the FERC did not adequately support its conclusions. We intend to continue to pursue approval of our proposed rate design. If we are unsuccessful, we believe any refunds would not be material to our results of operations.

REGULATION

FERC Regulation.

Our interstate transmission and storage activities are subject to regulation by the FERC under the Natural Gas Act of 1938, as amended (NGA), and under the Natural Gas Policy Act of 1978, as amended (NGPA), 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 onshore and offshore 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.

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

For additional information regarding the potential impact of federal, state or local regulatory measures on our business and specific environmental issues, please refer to “Risk Factors – Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities and expenditures and could exceed current expectations,” and “Environmental Matters” in Note 2 of our Notes to Consolidated Financial Statements.

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 that was completed in 2012 along with periodic reassessments to be completed within required timeframes. In meeting the integrity regulations, we have identified high consequence areas and developed our baseline assessment plan. The required pipeline segments originally identified for assessment were completed within the required timeframe, with one exception which was reported to PHMSA. Ongoing periodic reassessments and initial assessments of any new high consequence areas will be completed within the timeframes required by the rule. We estimate that the cost to be incurred in 2014 associated with this program to be approximately $34 million, most of which we expect to be capital expenditures. 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

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

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TRANSACTIONS WITH AFFILIATES

We engage in transactions with WPZ, Williams and other Williams’ subsidiaries. (See Note 1 and Note 7 of Notes to Consolidated Financial Statements.)

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;

• Natural gas prices, supply and demand; and

• Demand for our services.

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

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

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

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

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

• Development of alternative energy sources;

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

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

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

• Changes in maintenance and construction costs;

• Changes in the current geopolitical situation;

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

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

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

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

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

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

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

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

RISK FACTORS

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

Risks Inherent to Our Industry and Business

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

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

• fires, blowouts, cratering, and explosions;

• uncontrolled releases of natural gas;

• pollution and other environmental risks;

• aging infrastructure and mechanical problems;

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

• operator error; and

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

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

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

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

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

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

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

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

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

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

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

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

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

We compete primarily with other interstate pipelines and storage facilities in the transportation and storage of natural gas. Some of our competitors may have greater financial resources and access to greater supplies of natural gas than we do. Some of these competitors may expand or construct transportation and storage systems that would create additional competition for natural gas supplies or the services we provide to our customers. Moreover, WPZ and its other affiliates, including Williams, may not be limited in their ability to compete with us. In a number of key markets, interstate pipelines are now facing competitive pressure from other major pipeline systems, enabling local distribution companies and end users to choose a transmission provider based on considerations other than location. Other entities could construct new pipelines or expand existing pipelines that could potentially serve the same markets as our pipeline system. Any such new pipelines could offer transportation services that are more desirable to shippers because of locations, facilities, or other factors. These new pipelines could charge rates or provide service to locations that would result in greater net profit for shippers and producers and thereby force us to lower the rates charged for service on our pipeline in order to extend our existing transportation service agreements or to attract new customers. We are aware of proposals by competitors to expand pipeline capacity in certain markets we also serve which, if the proposed projects proceed, could increase the competitive pressure upon us. Further, natural gas also competes with

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other forms of energy available to our customers, including electricity, coal, fuel oils, and other alternative energy sources. We may not be able to successfully compete against current and future competitors and any failure to do so could have a material adverse effect on our business, cash flows and results of operations.

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

Our ability to maintain and expand our business depends on the level of drilling and production by third parties in our supply basins. Production from existing wells and natural gas supply basins with access to our pipeline will naturally decline over time. The amount of natural gas reserves underlying these existing wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. In addition, low prices for natural gas, regulatory limitations, including environmental regulations, or the lack of available capital for these projects could adversely affect the development and production of additional reserves, as well as gathering, storage, pipeline transportation, and import and export of natural gas supplies. The competition for natural gas supplies to serve other markets could also reduce the amount of natural gas supply for our customers.

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

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

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

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

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

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

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

Public and regulatory scrutiny of the energy industry has resulted in the proposal and/or implementation of increased regulations. Such scrutiny has also resulted in various inquiries, investigations and court proceedings, including litigation of energy industry matters. Both the shippers on our pipeline and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.

Certain inquiries, investigations and court proceedings are ongoing. Adverse effects may continue as a result of the uncertainty of these ongoing inquiries, investigations and court proceedings, or additional inquiries and proceedings

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

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

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

Our operations are subject to extensive federal, state and local laws and regulations governing environmental protection, endangered and threatened species, the discharge of materials into the environment and the security of chemical and industrial facilities. Substantial costs, liabilities, delays and other significant issues related to environmental laws and regulations are inherent in the gathering, transportation, and storage of natural gas as well as waste disposal practices.

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

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

We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or

unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.

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

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

We rely on a limited number of customers for a significant portion of our revenues. Although some of these customers are subject to long-term contracts, we may be unable to negotiate extensions or replacements of these contracts on favorable terms, or at all. For the year ended December 31, 2013, our two largest customers were Public Service Enterprise Group and National Grid. These customers accounted for approximately 9.7 percent and 6.6 percent, respectively, of our operating revenues for the year ended December 31, 2013. The loss of all, or even a portion of, the revenues from contracted volumes supplied by our key customers, as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition, and cash flows, unless we are able to acquire comparable volumes from other sources.

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

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business. Generally, our customers are rated investment grade, are otherwise considered creditworthy, or are required to make pre-payments or provide security to satisfy credit concerns. However, our credit procedures and policies may not be adequate to fully eliminate customer credit risk. Our customers and counterparties include industrial customers, local distribution companies, natural gas producers and marketers whose creditworthiness may be suddenly and disparately impacted by, among other factors, commodity price volatility, deteriorating energy market conditions, and public and regulatory opposition to energy producing activities. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off doubtful accounts. Such write-downs or write-offs could negatively affect our operating results for the period in which they occur, and, if significant, could have a material adverse effect on our business, results of operations, cash flows, and financial condition.

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

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

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

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

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

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

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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. Offshore assets are covered for property damage when loss is due to a named windstorm event and coverage for loss caused by a named windstorm is significantly sub-limited and subject to a large deductible. All of our insurance is subject to deductibles.

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

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

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

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

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

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

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

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

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

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

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

to loss of institutional knowledge or service disruptions. Our reliance on Williams and others as service providers and on Williams’ outsourcing relationships, and our limited ability to control certain costs, could have a material adverse effect on our business, results of operations and financial condition.

Risks Related to Strategy and Financing

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

Our total outstanding long-term debt (including current portion) as of December 31, 2013, was $1,428.4 million.

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

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

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

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

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

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

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

Our ability to comply with our debt covenants, to repay, extend or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance. Our ability to refinance existing debt obligations or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to comply with these covenants, meet our debt service obligations or obtain future credit on favorable terms, or at all, we could 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

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could cause a default or acceleration to have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. For more information regarding our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity”.

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

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

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

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

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

A downgrade of our credit ratings might increase our cost of borrowing and could require us to provide collateral to our counterparties, negatively impacting our available liquidity. In addition, our ability to access capital markets could be limited by a downgrade of our credit ratings as well as by economic, market or other disruptions. Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria such as business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are subject to revision or withdrawal at any time by the ratings agencies.

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

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

• payment of distributions and repayment of advances;

• decisions on financings and our capital raising activities;

• mergers or other business combinations; and

• acquisition or disposition of assets.

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

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Risks Related to Regulations That Affect Our Industry

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

In addition to regulation by other federal, state, and local regulatory authorities, under the Natural Gas Act of 1938, our interstate pipeline transportation and storage services and related assets are subject to regulation by the FERC. Federal regulation extends to such matters as:

• transportation of natural gas in interstate commerce;

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

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

• certification and construction of new interstate pipelines and storage facilities;

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

• accounts and records;

• depreciation and amortization policies;

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

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

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

Unlike other interstate pipelines that own facilities in the offshore Gulf of Mexico, we charge our transportation customers a separate fee to access our offshore facilities. The separate charge is referred to as an “IT feeder” charge. The “IT feeder” rate is charged only when gas is actually transported on the facilities and typically it is paid by producers or marketers. Because the “IT feeder” rate is typically paid by producers and marketers, it generally results in netback prices to producers that are slightly lower than the netbacks realized by producers transporting on other interstate pipelines. This rate design disparity can result in producers bypassing our offshore facilities in favor of alternative transportation facilities.

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

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

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

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

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

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

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

Risks Related to Weather, Other Natural Phenomena and Business Disruption

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

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

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

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

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

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

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

Item 1B.Unresolved Staff Comments

None.

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Item 2. Properties

Our gas pipeline facilities are generally owned in fee. However, a substantial portion of such facilities are constructed and maintained pursuant to rights-of-way, easements, permits, licenses or consents on and across real property owned by others. Compressor stations, with appurtenant facilities, are located in whole or in part either on lands owned or on sites held under leases or permits issued or approved by public authorities. Our storage facilities are either owned or contracted for under long-term leases or easements. We lease our company offices in Houston, Texas.

Item 3. Legal Proceedings

The information called for by this item is provided in “Item 8. Financial Statements and Supplementary Data – Notes to Consolidated Financial Statements – Note 2. Contingent Liabilities and Commitments”.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

At December 31, 2013, we are owned, through WPO, by WPZ, and Williams holds an approximate 64 percent interest in WPZ, comprised of an approximate 62 percent limited partner interest and all of WPZ’s 2 percent general partner interest.

Distributions totaling $250 million were declared and paid by us to our parent during the year ended December 31, 2013. An additional distribution of $112 million was declared and paid by us to our parent in January 2014. Distributions totaling $246 million were declared and paid by us to our parent during the year ended December 31, 2012.

In the year ended December 31, 2013, WPO made contributions totaling $264 million to us to fund a portion of our expenditures for additions to property, plant and equipment. In January 2014, WPO made an additional $54 million contribution to us. In the year ended December 31, 2012, WPO made contributions to us totaling $150 million. In 2012, we received a non-cash contribution of approximately $1.5 million related to the transfer of certain property, plant and equipment and other assets.

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 and analysis 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 Item 8.

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.

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Regulatory Accounting

We are regulated by the FERC. The Accounting Standards Codification (ASC) 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 consolidated 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 Consolidated Balance Sheet and included in the Consolidated 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 U.S. GAAP. The aggregate amount of regulatory assets reflected in the Consolidated Balance Sheet is $294.1 million at December 31, 2013. The aggregate amount of regulatory liabilities reflected in the Consolidated Balance Sheet is $287.6 million at December 31, 2013. A summary of regulatory assets and liabilities is included in Note 9 of Notes to Consolidated Financial Statements.

Revenue Subject to Refund

FERC regulations promulgate policies and procedures which govern a process to establish the rates that we are permitted to charge customers for natural gas sales and services, including the transportation and storage of natural gas. Key determinants in the ratemaking process are (i) costs of providing service, including depreciation expense, (ii) allowed rate of return, including the equity component of the capital structure and related taxes, and (iii) volume throughput assumptions.

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 risk. Depending on the results of these proceedings, the actual amounts allowed to be collected from customers could differ from management's estimate. In addition, as a result of rate orders, tariff provisions or regulations, we are required to refund or credit certain revenues to our customers. At December 31, 2013, we had accrued approximately $98 million for potential amounts to be refunded.

Results of Operations

Analysis of Financial Results

This analysis discusses financial results of our operations for the years 2013 and 2012. Variances due to changes in natural gas prices and transportation volumes have little impact on revenues, because under our rate design methodology, the majority of overall cost of service is recovered through firm capacity reservation charges in our transportation rates.

2013 COMPARED TO 2012

Operating Income and Net IncomeOperating Income for 2013 was $429.1 million compared to $330.1 million for 2012. Net Income for 2013 was $374.0 million compared to $272.5 million for 2012. The increase in Operating Income of $99.0 million (30.0 percent) was primarily due to higher Natural gas transportation revenues and a decrease in certain Operating Costs and Expenses in 2013 compared to 2012, as discussed below. The increase in Net Income of $101.5 million (37.2 percent) was mostly attributable to the increase in Operating Income, and a favorable change in net expenses in Other (Income) and Other Expenses, as discussed below.

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Sales Revenues We have cash out sales, which settle gas imbalances with shippers. In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems, which may deliver different quantities of gas on our behalf than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables. Our tariff includes a method whereby the majority of transportation imbalances are settled on a monthly basis through cash out sales or purchases. The cash out sales have no impact on our operating income or results of operations.

Operating Revenues: Natural gas sales increased $48.4 million (74.3 percent) to $113.5 million for 2013 when compared to 2012. The increase was primarily due to higher cash-out sales. Cash-out sales are offset in our costs of natural gas sold and therefore had no impact on our operating income or results of operations.

Transportation RevenuesOperating Revenues: Natural gas transportation for 2013 was $1,094.8 million compared to $1,023.0 million for 2012. The $71.8 million (7.0 percent) increase was partly due to the implementation of new rates in March 2013 which were higher as compared to the rates provided in the settlement of the prior rate proceedings. Also contributing to the positive variance were higher transportation reservation revenues related to new incremental projects of $58.6 million, ($30.8 million from our Mid-South project Phase 1 placed in service in September 2012 and Phase 2 placed in service in June 2013, $14.3 million from our Northeast Supply Link project placed in partial service in third quarter 2013, with full service in November 2013 and $13.5 million from our Mid-Atlantic Connector project placed in service in January 2013), partially offset by $6.6 million lower transportation revenues due to a firm contract termination on the Mobile Bay lateral, $6.3 million lower recovery of electric power costs, and $2.2 million lower revenues due to one less billable day, as of result of leap year in 2012. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations.

Operating Costs and Expenses Excluding the Cost of natural gas sales, which is directly offset in revenues, our operating expenses decreased approximately $25.2 million (3.0 percent) from the comparable period in 2012. This decrease was primarily attributable to:

• A $35.1 million (11.7 percent) decrease in Operation and maintenance costs primarily resulting from a $16.1 million decrease in employee labor and related costs and a $19.0 million decrease primarily related to compressor and pipeline operation, maintenance and repairs;

• A $6.9 million (21.7 percent) decrease in Cost of natural gas transportation primarily resulting from lower electric power costs. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations;

• Partially offset by $11.4 million (53.8 percent) unfavorable change in Other expense, net primarily due to a $23.4 million increase due to the amortization of regulatory assets resulting from ARO cost incurred prior to the Docket No. RP12-993 rate case, and a $11.5 million expense in 2013 related to a charge for the portion of the Eminence regulatory asset that will not be recovered in rates associated with Eminence abandonment discussed below, partially offset by a $16.1 million gain recognized in 2013 related to insurance recoveries associated with Eminence abandonment discussed below, a $2.3 million decrease in expense for a certain litigation matter and a $2.3 million decrease of loss on disposal of property, plant and equipment.

• A $7.8 million (4.5 percent) increase in Administrative and general costs primarily resulting from employee labor and related benefit costs.

Other (Income) and Other DeductionsOther (income) and other expenses in 2013 had a favorable change of $2.5 million (4.3 percent) over 2012 primarily due to lower interest expense due to the July 2012 refinancing of debt at lower interest rates.

Eminence Storage Field Leak

On December 28, 2010, we detected a leak in one of the seven underground natural gas storage caverns at our Eminence Storage Field in Covington County, Mississippi. We initially reduced the pressure in the cavern by safely venting and flaring gas, and began the process of flowing all remaining gas into our pipeline. Due to the leak at this cavern and damage to the well at an adjacent cavern, both caverns were taken out of service. In addition, two other

21

caverns at the field, which were constructed at or about the same time as those caverns, experienced operating problems, and we determined that they should be retired. The event did not affect the performance of our obligations under our service agreements with our customers.

In September 2011, we filed an application with the FERC seeking authorization to abandon these four caverns. In February 2013, the FERC issued an order approving the abandonment. We estimate the remaining cost to complete the abandonment of the caverns will be approximately $7 million, and is expected to be spent through the first half of 2014. 

As of December 31, 2013, we have incurred approximately $93.2 million of these abandonment costs. Consistent with the terms of the Agreement in the Docket No. RP12-993 rate case, for the year ended December 31, 2013, we expensed $11.5 million, related to the Eminence abandonment regulatory asset that will not be recovered in rates.

We have reached settlement agreements with insurance counterparties related to this event. A portion of the proceeds from these settlements has been credited to the Eminence regulatory asset pursuant to the terms of the Agreement in the Docket No. RP12-993 rate case. The remaining balance of the proceeds are allocated to us to offset the expense associated with the write off of the uncollectible portion of the Eminence regulatory asset and a portion of our costs incurred to ensure the safety of the surrounding area. For the year ended December 31, 2013, we have recognized $16.1 million related to these insurance recoveries.

During 2013, 2012 and 2011, we incurred $4.3 million, $2.5 million and $14.6 million, respectively, of expense, related primarily to costs to ensure the safety of the surrounding area. We anticipate incurring additional expense of approximately $2.6 million during 2014.

Filing of Rate Case.

On August 31, 2012, we filed a general rate case with the FERC for an overall increase in rates. In September 2012, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general rate filing to be effective March 1, 2013, subject to refund and the outcome of a hearing. The specific rates that reflected a rate decrease were accepted, without suspension, to be effective October 1, 2012 and will not be subject to refund. On August 27, 2013, after reaching an agreement in principle with the participants, we filed a stipulation and agreement (Agreement) proposing to resolve all issues in this proceeding without the need for a hearing. On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement will become effective March 1, 2014. We have provided a reserve for rate refunds which we believe is adequate for required refunds as of December 31, 2013, under the Agreement.

Effects of Inflation

We have generally 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 material and supplies inventory is subject to ratemaking treatment, and under current FERC practices, recovery is limited to historical costs. We believe that we will be allowed to recover and earn a return based on increased actual costs incurred when existing facilities are replaced. Cost based regulation along with competition and other market factors limit our ability to price services or products based upon inflation’s effect on costs.

CAPITAL RESOURCES AND LIQUIDITY

Method of Financing

We fund our capital requirements with cash flows from operating activities, equity contributions from WPZ, collection of advances to WPZ, accessing capital markets, and, if required, borrowings under the credit facility described below 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 amounts raised, if any, in

22

the capital markets. We anticipate that we will be able to access public and private markets on terms commensurate with our credit ratings to finance our capital requirements.

On July 31, 2013, WPZ amended the $2.4 billion credit facility to increase the aggregate commitments to $2.5 billion and extend the maturity date to July 31, 2018. The amended credit facility may also, under certain conditions, be increased up to an additional $500 million. Total letter of credit capacity available to WPZ under the credit facility is $1.3 billion. We may borrow up to $500 million under the amended credit facility to the extent not otherwise utilized by WPZ and Northwest Pipeline LLC. See Note 3 of Notes to Consolidated Financial Statements for further discussion of the credit facility.

We are a participant in WPZ's cash management program, and we make advances to and receive advances from WPZ. At December 31, 2013, our advances to WPZ totaled approximately $526.4 million. These advances are represented by demand notes. In April 2014, we expect repayment of a portion of these advances in order to pay rate refunds to our customers under the Agreement in Docket No. RP12-993.

Through wholly-owned subsidiaries, we hold a 35 percent interest in Pine Needle and approximately a 45 percent interest in Cardinal, which have interest rate swap agreements that qualify as cash flow hedge transactions under the accounting and reporting standards established by ASC Topic 815, Derivatives and Hedging. As such, our equity interest in the changes in fair value of Pine Needle’s hedge and Cardinal’s hedge are recognized in other comprehensive income.

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 existing assets, extend useful lives, increase transmission or storage capacities from existing levels, reduce costs or enhance revenues. We anticipate 2014 capital expenditures will be approximately $830 million. Of this total, approximately $750 million is considered nondiscretionary due to legal, regulatory, and/or contractual requirements, primarily due to expansion projects.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

At December 31, 2013, our debt portfolio included only fixed rate issues. The following table provides information about our long-term debt, including current maturities, as of December 31, 2013. The table presents principal cash flows and weighted-average interest rates by expected maturity dates.

December 31, 2013	Expected Maturity Date
	2014			2015			2016			2017
	(Dollars in millions)
Long-term debt:
Fixed rate	$	—		$	—		$	200		$	—
Interest rate	5.65		%	5.65		%	5.57		%	5.53		%
December 31, 2013	Expected Maturity Date
	2018			Thereafter			Total			Fair Value
	(Dollars in millions)
Long-term debt:
Fixed rate	$	250		$	983		$	1,433		$	1,513
Interest rate	5.47		%	5.10		%

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Item 8. Financial Statements and Supplementary Data

	Page
Report of Independent Registered Public Accounting Firm	26
Consolidated Statement of Comprehensive Income	27
Consolidated Balance Sheet	28
Consolidated Statement of Owner’s Equity	30
Consolidated Statement of Cash Flows	31
Notes to Consolidated Financial Statements	33

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Management Committee of Transcontinental Gas Pipe Line Company, LLC

We have audited the accompanying consolidated balance sheets of Transcontinental Gas Pipe Line Company, LLC as of December 31, 2013 and 2012, and the related consolidated statements of comprehensive income, owner’s equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Transcontinental Gas Pipe Line Company, LLC at December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

/S/ ERNST & YOUNG LLP

Houston, Texas

February 26, 2014

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Thousands of Dollars)

	Years Ended December 31,
	2013			2012			2011
Operating Revenues:
Natural gas sales	$	113,488		$	65,120		$	108,359
Natural gas transportation	1,094,807			1,022,990			983,554
Natural gas storage	143,047			140,390			142,556
Other	4,990			5,601			8,045
Total operating revenues	1,356,332			1,234,101			1,242,514
Operating Costs and Expenses:
Cost of natural gas sales	113,488			65,120			108,359
Cost of natural gas transportation	24,936			31,815			35,674
Operation and maintenance	264,631			299,734			281,496
Administrative and general	182,352			174,610			148,113
Depreciation and amortization	265,273			266,445			259,660
Taxes — other than income taxes	43,898			45,086			41,673
Other expense, net	32,606			21,230			12,988
Total operating costs and expenses	927,184			904,040			887,963
Operating Income	429,148			330,061			354,551
Other (Income) and Other Expenses:
Interest expense - affiliate	190			309			262
- other	84,000			88,766			94,920
Interest income - affiliate	(45		)	(35		)	(29		)
- other	(2,068		)	(2,351		)	(2,119		)
Allowance for equity and borrowed funds used during construction (AFUDC)	(18,595		)	(19,257		)	(15,339		)
Equity in earnings of unconsolidated affiliates	(5,678		)	(7,458		)	(5,164		)
Miscellaneous other (income) expenses, net	(2,682		)	(2,379		)	2,362
Total other (income) and other expenses	55,122			57,595			74,893
Net Income	374,026			272,466			279,658
Other comprehensive income (loss):
Equity interest in unrealized gain (loss) on interest rate hedges (includes $330, $220, and $170 for the years ended December 31, 2013, 2012, and 2011, respectively, of accumulated other comprehensive income reclassification for realized losses on interest rate hedges)	464			(376		)	(519		)
Comprehensive Income	$	374,490		$	272,090		$	279,139

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

	December 31,
	2013		2012
ASSETS
Current Assets:
Cash	$	113	$	185
Receivables:
Trade	137,808		116,847
Affiliates	2,601		2,656
Advances to affiliate	526,380		312,165
Other	10,364		8,928
Transportation and exchange gas receivables	6,757		2,876
Inventories:
Gas in storage, at original cost	790		812
Gas in storage, LIFO	1,056		—
Gas available for customer nomination, at average cost	8,553		8,600
Material and supplies, at lower of average cost or market	37,133		36,506
Regulatory assets	37,520		36,706
Other	13,451		14,342
Total current assets	782,526		540,623
Investments, at cost plus equity in undistributed earnings	50,262		55,603
Property, Plant and Equipment:
Natural gas transmission plant	8,867,626		8,506,189
Less-Accumulated depreciation and amortization	3,090,234		2,954,276
Total property, plant and equipment, net	5,777,392		5,551,913
Other Assets:
Regulatory assets	256,612		214,912
Other	57,785		47,764
Total other assets	314,397		262,676
Total assets	$	6,924,577	$	6,410,815

(continued)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)

	December 31,
	2013			2012
LIABILITIES AND OWNER’S EQUITY
Current Liabilities:
Payables:
Trade	$	106,096		$	107,795
Affiliates	28,268			32,006
Cash overdrafts	8,539			11,512
Transportation and exchange gas payables	3,599			3,513
Reserve for rate refunds	98,217			—
Accrued liabilities:
Property and other taxes	14,180			13,326
Interest	19,894			20,784
Regulatory liabilities	18,014			14,624
Customer advances	17,811			11,020
Asset retirement obligations	35,902			43,472
Other	47,462			36,107
Total current liabilities	397,982			294,159
Long-Term Debt	1,428,355			1,428,323
Other Long-Term Liabilities:
Asset retirement obligations	238,085			253,398
Regulatory liabilities	269,563			232,888
Other	5,307			5,339
Total other long-term liabilities	512,955			491,625
Contingent Liabilities and Commitments (Note 2)
Owner’s Equity:
Member’s capital	2,257,499			1,993,412
Retained earnings	2,328,044			2,204,018
Accumulated other comprehensive income (loss)	(258		)	(722		)
Total owner’s equity	4,585,285			4,196,708
Total liabilities and owner’s equity	$	6,924,577		$	6,410,815

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED STATEMENT OF OWNER’S EQUITY

(Thousands of Dollars)

	Years Ended December 31,
	2013			2012			2011
Member's Capital:
Balance at beginning of period	$	1,993,412		$	1,841,888		$	1,727,434
Cash contributions from parent	264,000			150,000			115,000
Non-cash contributions from parent	87			1,524			—
Non-cash return of capital	—			—			(546		)
Balance at end of period	2,257,499			1,993,412			1,841,888
Retained Earnings:
Balance at beginning of period	2,204,018			2,177,811			2,117,153
Net income	374,026			272,466			279,658
Cash distributions to parent	(250,000		)	(246,259		)	(219,000		)
Balance at end of period	2,328,044			2,204,018			2,177,811
Accumulated Other Comprehensive Income (Loss):
Balance at beginning of period	(722		)	(346		)	173
Equity interest in unrealized gain (loss) on interest rate hedge	464			(376		)	(519		)
Balance at end of period	(258		)	(722		)	(346		)
Total Owner's Equity	$	4,585,285		$	4,196,708		$	4,019,353

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED STATEMENT OF CASH FLOWS

(Thousands of Dollars)

	Years Ended December 31,
	2013			2012			2011
Cash flows from operating activities:
Net income	$	374,026		$	272,466		$	279,658
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	263,949			266,981			260,069
Allowance for equity funds used during construction (equity AFUDC)	(13,299		)	(13,222		)	(10,588		)
Changes in operating assets and liabilities:
Receivables — affiliates	55			3,247			(982		)
— trade and other	(21,772		)	(4,186		)	(11,155		)
Transportation and exchange gas receivable	(3,881		)	2,038			(2,497		)
Regulatory assets - current	28,536			1,171			10,567
Regulatory assets - non-current	21,910			(5,980		)	(8,698		)
Inventories	232			673			50,295
Payables — affiliates	(3,738		)	15,069			(1,832		)
— trade	(26,463		)	3,727			14,577
Accrued liabilities	28,322			8,256			27,775
Asset retirement obligations	13,105			35,195			(6,964		)
Asset retirement obligation - removal costs	(26,919		)	(41,052		)	(43,666		)
Reserve for rate refunds	98,217			—			—
Other, net	10,731			(2,934		)	15,085
Net cash provided by operating activities	743,011			541,449			571,644
Cash flows from financing activities:
Additions to long-term debt	—			398,804			372,518
Retirement of long-term debt	—			(325,000		)	(300,000		)
Debt issue costs	—			(4,403		)	(3,846		)
Cash distributions to parent	(250,000		)	(246,259		)	(219,000		)
Cash contributions from parent	264,000			150,000			115,000
Other, net	(3,034		)	(3,333		)	(4,681		)
Net cash provided by (used in) financing activities	10,966			(30,191		)	(40,009		)

(continued)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED STATEMENT OF CASH FLOWS

(Thousands of Dollars)

	Years Ended December 31,
	2013			2012			2011
Cash flows from investing activities:
Property, plant and equipment additions, net of equity AFUDC*	$	(526,916	)	$	(475,450	)	$	(385,671	)
Disposal of property, plant and equipment, net	(3,621		)	7,157			2,698
Advances to affiliate, net	(214,215		)	(58,554		)	(144,773		)
Return of capital from unconsolidated affiliates	1,438			11,327			1,925
Contributions to unconsolidated affiliates	—			(5,806		)	(14,834		)
Purchase of ARO Trust investments	(58,242		)	(34,430		)	(41,310		)
Proceeds from sale of ARO Trust investments	45,607			43,205			56,576
Other, net	1,900			1,314			(6,230		)
Net cash used in investing activities	(754,049		)	(511,237		)	(531,619		)
Increase (decrease) in cash	(72		)	21			16
Cash at beginning of period	185			164			148
Cash at end of period	$	113		$	185		$	164
____________________________
*   Increase to property, plant and equipment	$	(558,201	)	$	(466,115	)	$	(386,462	)
Changes in related accounts payable and accrued liabilities	31,285			(9,335		)	791
Property, plant and equipment additions, net of equity AFUDC	$	(526,916	)	$	(475,450	)	$	(385,671	)
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest (exclusive of amount capitalized)	$	76,803		$	86,586		$	88,357
Income taxes	116			254			728

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES.

Corporate Structure and Control.

In this report, Transco (which includes Transcontinental Gas Pipe Line Company, LLC and unless the context otherwise requires, all of our majority-owned subsidiaries) is at times referred to in the first person as “we,” “us” or “our.”

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

Transco is a single member limited liability company, and as such, single member losses are limited to the amount of their investment.

Related Party Transaction.

A member of Williams' Board of Directors, who was elected in 2013, is also the current chairman, president, and chief executive officer of an energy services company that is a customer of ours. We recorded $130.7 million in operating revenues in the Consolidated Statement of Comprehensive Income from this company for transportation and storage of natural gas for the year ended December 31, 2013. This board member does not have any material interest in any transactions between the energy services company and us and he had no role in any such transactions.

Nature of Operations.

We are an interstate natural gas transmission company that owns a natural gas pipeline system extending from Texas, Louisiana, Mississippi and the Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Delaware, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and the 12 southeast and Atlantic seaboard states mentioned above, including major metropolitan areas in Georgia, Washington D.C., Maryland, North Carolina, New York, New Jersey and Pennsylvania.

Regulatory Accounting.

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

Basis of Presentation.

Williams’ acquisition of Transco Energy Company and its subsidiaries, including us, in 1995 was accounted for using the purchase method of accounting. Accordingly, an allocation of the purchase price was assigned to our assets

33

and liabilities based on their estimated fair values. The purchase price allocation to us primarily consisted of a $1.5 billion allocation to property, plant and equipment and adjustments to deferred taxes based upon the book basis of the net assets recorded as a result of the acquisition. The amount allocated to property, plant and equipment is being depreciated on a straight-line basis over 40 years, the estimated useful lives of these assets at the date of acquisition, at approximately $35 million per year. At December 31, 2013, the remaining property, plant and equipment allocation was approximately $0.7 billion. Current FERC policy does not permit us to recover through rates amounts in excess of original cost.

We are a participant in WPZ’s cash management program. We make advances to and receive advances from WPZ. The 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.

Certain prior period amounts reported within Total operating costs and expenses in the Consolidated Statement of Comprehensive Income have been reclassified to conform to the current presentation. The effect of the correction increased Operation and maintenance costs $7.1 million and $6.8 million for the years ended December 31, 2012 and 2011, respectively, for the reclassification from Taxes-other than income taxes with no net impact on Total operating costs and expenses, Operating Income and Net Income.

Principles of Consolidation.

The consolidated financial statements include our accounts and the accounts of the subsidiaries we control. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments as of December 31, 2013 and December 31, 2012 consist of Cardinal Pipeline Company, LLC (Cardinal) with ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC (Pine Needle) with ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $11.5 million, $14.3 million, and $6.2 million in 2013, 2012 and 2011, respectively. Included in the distributions are $1.4 million return of capital from Pine Needle in 2013 and $11.3 million return of capital from Cardinal in 2012. We made capital contributions to Cardinal related to Cardinal’s expansion project totaling $5.8 million in 2012.

Use of Estimates.

The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4) impairment assessments of long-lived assets; 5) depreciation; and 6) asset retirement obligations.

Revenue Recognition.

Revenues for transportation of gas under long-term firm agreements are recognized considering separately the reservation and commodity charges. Reservation revenues are recognized monthly over the term of the agreement regardless of the volume of natural gas transported. Commodity revenues from both firm and interruptible transportation are recognized in the period transportation services are provided based on volumes of natural gas physically delivered at the agreed upon delivery point. Revenues for the storage of gas under firm agreements are recognized considering separately the reservation, capacity, and injection and withdrawal charges. Reservation and capacity revenues are recognized monthly over the term of the agreement regardless of the volume of storage service actually utilized. Injection and withdrawal revenues are recognized in the period when volumes of natural gas are physically injected into or withdrawn from storage.

In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through

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the purchase and sale of gas with our customers under terms provided for in our FERC tariff. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances (See Gas Imbalances in this Note).

As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel and other risks.

Environmental Matters.

We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their economic benefit and potential for rate recovery. We believe that 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 is recorded at cost. The carrying values of these assets are also based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. These estimates, assumptions and judgments reflect FERC regulations, as well as historical experience and expectations regarding future industry conditions and operations. 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. All other costs are expensed as incurred. Gains or losses from the ordinary sale or retirement of property, plant and equipment are credited or charged to accumulated depreciation; certain other gains or losses are recorded in operating income.

We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission facilities, production and gathering facilities and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2013, 2012 and 2011 are as follows:

Category of Property	2013 (1)	2012-2011
Gathering facilities	1.35% - 2.50%	0.18% - 1.66%
Storage facilities	2.10% -  2.25%	2.10% -  3.70%
Onshore transmission facilities	2.61%  -  5.00%	2.79%  -  5.71%
Offshore transmission facilities	1.20%  -  1.20%	1.01%  -  1.01%

(1) Changes in depreciation rates in 2013 due to placing into effect, subject to refund, the rates in Docket No. RP12-993 on March 1, 2013.

We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. Measurements of AROs include, 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 a market-risk premium. The ARO asset is depreciated in a manner consistent with the expected timing of the future abandonment of the underlying physical assets. We measure changes in the liability due to passage of time by applying an interest method of allocation. The depreciation of the ARO asset and accretion of the ARO liability are recognized as an increase to a regulatory asset, as management expects to recover such amounts in future rates. The regulatory asset is amortized commensurate with our collection of these costs in rates.

Impairment of Long-lived Assets.

We evaluate the long lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable.

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When an indicator of impairment has occurred we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. We apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

For assets identified to be disposed of in the future and considered held for sale in accordance with the ASC Property, Plant, and Equipment (Topic 360), we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.

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

Allowance for Funds Used During Construction.

Allowance for funds used during construction (AFUDC) represents the estimated cost of borrowed and equity funds applicable to utility plant in process of construction and are included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. The FERC has prescribed a formula to be used in computing separate allowances for borrowed and equity AFUDC. The allowance for borrowed funds used during construction was $5.3 million, $6.0 million and $4.7 million, for 2013, 2012 and 2011, respectively. The allowance for equity funds was $13.3 million, $13.2 million, and $10.6 million, for 2013, 2012 and 2011, respectively.

Income Taxes.

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

Accounts Receivable and Allowance for Doubtful Receivables.

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

Gas Imbalances.

In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems which may deliver different quantities of gas on behalf of us than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables which are recovered or repaid in cash or through the receipt or delivery of gas in the future and are recorded in the accompanying Consolidated Balance Sheet. 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. Our tariff includes a method whereby most transportation imbalances are settled on a monthly basis. Each month a portion of the

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imbalances are not identified to specific parties and remain unsettled. These are generally identified to specific parties and settled in subsequent periods. We believe that amounts that remain unidentified to specific parties and unsettled at year end are valid balances that will be settled with no material adverse effect upon our financial position, results of operations or cash flows. Management has implemented a policy of continuing to carry any unidentified transportation and exchange imbalances on the books for a three-year period. At the end of the three year period a final assessment will be made of their continued validity. Absent a valid reason for maintaining the imbalance, any remaining balance will be recognized in income. Certain imbalances are being recovered or repaid in cash or through the receipt or delivery of gas upon agreement of the parties as to the allocation of the gas volumes, and as permitted by pipeline operating conditions. These imbalances have been classified as current assets and current liabilities at December 31, 2013 and 2012. We utilize the average cost method of accounting for gas imbalances.

Deferred Cash Out.

Most transportation imbalances are settled in cash on a monthly basis (cash out). We are required by our tariff to refund revenues received from the cash out of transportation imbalances in excess of costs incurred during the annual August through July reporting period. Revenues received in excess of costs incurred are deferred until refunded in accordance with the tariff.

Gas Inventory.

We utilize the last-in, first-out (LIFO) method of accounting for inventory gas in storage. If inventories valued using the LIFO cost method were valued at current replacement cost, the amounts would increase by $1.3 million at December 31, 2013. At December 31, 2012, physical withdrawals from the Eminence Storage facility exceeded the customer nominations for withdrawals, resulting in a liability. The basis for determining current cost at the end of each year is the December monthly average gas price delivered to pipelines in Texas and Louisiana. We utilize the average cost method of accounting for gas available for customer nomination. Liquefied natural gas in storage is valued at original cost.

Materials and Supplies Inventory.

All inventories are stated at lower of average cost or market. We perform an annual review of Materials and Supplies inventories, including a quarterly analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 2013 and at December 31, 2012.

Contingent Liabilities.

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

Pension and Other Postretirement Benefits.

We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 6.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us and thus paid by us, is based on our share of net periodic benefit cost.

Cash Flows from Operating Activities and Cash Equivalents.

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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.

2. CONTINGENT LIABILITIES AND COMMITMENTS.

Rate Matters.

General rate case (Docket No. RP12-993) On August 31, 2012, we submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in our Docket No. RP06-569 rate proceeding (see below) which required us to file a rate case no later than August 31, 2012. On September 28, 2012, the FERC issued an order accepting our filing subject to the outcome of a hearing. The rates for certain services that were proposed as overall rate decreases became effective October 1, 2012, without suspension. The increased rates became effective March 1, 2013, subject to refund and the outcome of the hearing. On August 27, 2013, after reaching an agreement in principle with the participants, we filed a stipulation and agreement (Agreement) proposing to resolve all issues in this proceeding without the need for a hearing. On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement will become effective March 1, 2014. We have provided a reserve for rate refunds which we believe is adequate for required refunds as of December 31, 2013, under the Agreement. Refunds will be made on or before April 30, 2014.

General rate case (Docket No. RP06-569) On August 31, 2006, we submitted to the FERC a general rate filing principally designed to recover increased costs. The rates became effective March 1, 2007, subject to refund and the outcome of a hearing. All issues in this proceeding except one have been resolved by settlement.

The one issue reserved for litigation or further settlement relates to our proposal to change the design of the rates for service under one of our storage rate schedules, which was implemented subject to refund on March 1, 2007. A hearing on that issue was held before a FERC Administrative Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision in which he determined that our proposed incremental rate design is unjust and unreasonable. On January 21, 2010, the FERC reversed the ALJ’s initial decision, and approved our proposed incremental rate design. Certain parties sought rehearing of the FERC’s order and, on April 2, 2012, the FERC denied the rehearing request. On June 1, 2012, one of the parties filed an appeal in the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit). On February 21, 2014, the D.C. Circuit issued an opinion that vacated and remanded the FERC's order because the FERC did not adequately support its conclusions. We intend to continue to pursue approval of our proposed rate design. If we are unsuccessful, we believe any refunds would not be material to our results of operations.

Environmental Matters.

We have had studies underway to test some of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. We have responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that environmental assessment and remediation costs under various federal and state statutes will total approximately $6 million to $8 million (including both expense and capital expenditures), measured on an undiscounted basis, and will be spent over the next three to five years. This estimate depends on a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of the remedial measures. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At December 31, 2013, we had a balance of approximately $4.1 million for the expense portion of these estimated costs recorded in current liabilities ($2.3 million) and other long-term liabilities ($1.8 million) in the accompanying Consolidated Balance Sheet. At December 31, 2012, we had a balance of approximately $3.3 million for the expense portion of these estimated costs recorded in current liabilities ($1.1 million) and other long-term liabilities ($2.2 million) in the accompanying Consolidated Balance Sheet.

Although we discontinued the use of lubricating oils containing polychlorinated biphenyls (PCBs) in the 1970s, we have discovered residual PCB contamination in equipment and soils at certain gas compressor station sites. We have worked closely with the EPA and state regulatory authorities regarding PCB issues, and we have a program to assess and remediate such conditions where they exist. In addition, we commenced negotiations with certain

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environmental authorities and other parties concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. All such costs are included in the $6 million to $8 million range discussed above.

We have been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, our estimated aggregate exposure for remediation of these sites is less than $0.5 million. The estimated remediation costs for all of these sites are included in the $6 million to $8 million range discussed above. Liability under the Comprehensive Environmental Response, Compensation and Liability Act and applicable state law can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.

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. Several Transco facilities are located in 2008 ozone non-attainment areas; however, each facility has been previously subjected to federal and/or state emission control requirements implemented to address preceding ozone standards. To date, no new federal or state actions have been proposed to mandate additional emission controls at these facilities. At this time, it is unknown whether future federal or 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 federal or state regulatory actions are proposed, we are unable to estimate the cost of additions that may be required to meet this new regulation.

Additionally, in August 2010, the EPA promulgated National Emission Standards for Hazardous Air Pollutants (NESHAP) regulations that will impact our operations. All capital expenditures related to compliance with these hazardous air pollutant regulations were completed, and affected facilities were in compliance by the October 2013 regulatory deadline.

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

We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. As a result, as estimated costs of environmental assessment and remediation are incurred, they are recorded as regulatory assets in the Consolidated Balance Sheet until collected through rates. At December 31, 2013, we had a balance of approximately $1.8 million of uncollected environmental related regulatory assets recorded in current assets ($1.2 million) and other assets ($0.6 million) in the accompanying Consolidated Balance Sheet. We had no uncollected environmental related regulatory assets at December 31, 2012.

By letter dated September 20, 2007, the EPA required us to provide information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPA’s investigation of our compliance with the Federal Clean Air Act (Act). By January 2008, we responded with the requested information. By Notices of Violation (NOVs)

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dated March 28, 2008, the EPA found us to be in violation of the requirements of the Act with respect to these compressor stations. We met with the EPA in May 2008 to discuss the allegations contained in the NOVs; in June 2008, we submitted to the EPA a written response denying the allegations. The EPA has requested additional information pertaining to these compressor stations and in May 2011, we submitted information in response to the EPA’s latest request. In August, 2010, the EPA requested, and we provided, similar information for a compressor station in Maryland. Since 2011, we have not received any additional requests from the EPA for information related to these facilities.

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.

Commitments for construction We have commitments for construction and acquisition of property, plant and equipment of approximately $368 million at December 31, 2013.

3.DEBT, FINANCING ARRANGEMENTS AND LEASES.

Long-Term Debt.

At December 31, 2013 and 2012, long-term debt issues were outstanding as follows (in thousands):

	2013			2012
Debentures:
7.08% due 2026	$	7,500		$	7,500
7.25% due 2026	200,000			200,000
Total debentures	207,500			207,500
Notes:
6.4% due 2016	200,000			200,000
6.05% due 2018	250,000			250,000
5.4% due 2041	375,000			375,000
4.45% due 2042	400,000			400,000
Total notes	1,225,000			1,225,000
Total long-term debt issues	1,432,500			1,432,500
Unamortized debt premium and discount	(4,145		)	(4,177		)
Total long-term debt, less current maturities	$	1,428,355		$	1,428,323

Aggregate minimum maturities (face value) applicable to long-term debt outstanding at December 31, 2013, for the next five years, are as follows (in thousands):

2016:     6.4% Notes	$200,000
2018:     6.05% Notes	$250,000

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There are no maturities applicable to long-term debt outstanding for the years 2014, 2015, and 2017.

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

Restrictive Debt Covenants.

At December 31, 2013, none of our debt instruments restrict the amount of distributions to our parent. Our debt agreements contain restrictions on our ability to incur secured debt beyond certain levels.

Credit Facility.

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

Under the credit facility, WPZ is required to maintain a ratio of debt to EBITDA (each as defined in the credit facility) that must be no greater than 5.0 to 1.0. 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. In addition, the ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for us and our consolidated subsidiaries. At December 31, 2013, we are in compliance with these financial covenants.

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

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

WPZ participates in a commercial paper program and WPZ management considers amounts outstanding under this program to be a reduction of available capacity under the credit facility. The program allows a maximum outstanding amount at any time of $2 billion of unsecured commercial paper notes. At December 31, 2013, WPZ had $225 million in outstanding commercial paper.

Issuance and Retirement of Long-Term Debt.

On July 13, 2012, we issued $400 million aggregate principal amount of 4.45 percent senior unsecured notes due 2042 (4.45 percent Notes) to certain institutional investors pursuant to certain exemptions from registration under the Securities Act of 1933, as amended. Interest is payable on February 1 and August 1 of each year, beginning February 1, 2013. A portion of these proceeds was used to repay our $325 million 8.875 percent notes that matured on July 15, 2012. We used the remainder for general corporate purposes, including the funding of capital expenditures.

As part of the new issuance, we entered into a registration rights agreement with the initial purchasers of the 4.45 percent Notes. An offer to exchange these unregistered notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended, was commenced in November 2012 and completed in December 2012.

Lease Obligations.

The future minimum lease payments under our various operating leases are as follows (in thousands):

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2014	$	10,154
2015	10,025
2016	10,025
2017	9,971
2018	9,956
Thereafter	22,401
Total net minimum obligations	$	72,532

Our lease expense was $11.4 million in 2013, $10.9 million in 2012, and $9.1 million in 2011.

4. INVESTMENTS.

Available-for-Sale Investments.

We are entitled to collect in rates the amounts necessary to fund our asset retirement obligations (ARO). We deposit monthly, into an external trust account, the revenues specifically designated for ARO. We established the ARO trust account (ARO Trust) on June 30, 2008. The ARO Trust carries a moderate risk portfolio. We measure the financial instruments held in our ARO Trust at fair value. However, in accordance with the ASC Topic 980, Regulated Operations, both realized and unrealized gains and losses of the ARO Trust are recorded as regulatory assets or liabilities.

Effective March 1, 2013, based on the Agreement in Docket No. RP12-993, the annual funding obligation is approximately $36.4 million, with installments paid monthly.

Investments in available-for-sale securities within the ARO Trust at fair value were as follows (in millions):

	December 31, 2013				December 31, 2012
	Amortized Cost Basis		Fair Value		Amortized Cost Basis		Fair Value
Cash and Money Market Funds	$	6.5	$	6.5	$	1.3	$	1.3
U.S. Equity Funds	8.0		11.1		5.4		7.4
International Equity Funds	4.2		4.9		3.4		3.8
Municipal Bond Funds	10.2		10.2		4.9		5.3
Total	$	28.9	$	32.7	$	15.0	$	17.8

5. FAIR VALUE MEASUREMENTS.

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities.

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							Fair Value Measurements Using
	Carrying Amount			Fair Value			Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
							(Millions)
Assets (liabilities) at December 31, 2013:
Measured on a recurring basis:
ARO Trust investments	$	32.7		$	32.7		$	32.7	$	—		$	—
Additional disclosures:
Notes receivable	6.3			6.3			—		6.3			—
Long-term debt	(1,428.4		)	(1,512.9		)	—		(1,512.9		)	—
Assets (liabilities) at December 31, 2012:
Measured on a recurring basis:
ARO Trust investments	$	17.8		$	17.8		$	17.8	$	—		$	—
Additional disclosures:
Notes receivable	8.2			8.2			—		8.2			—
Long-term debt, including current portion	(1,428.3		)	(1,704.5		)	—		(1,704.5		)	—

Fair Value of Methods.

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 short-term financial assets (advances to affiliates) that have variable interest rates - The carrying amount is a reasonable estimate of fair value due to the short maturity of those instruments.

ARO Trust investments - We deposit a portion of our collected rates, pursuant to the Docket No. RP06-569 rate case settlement, into the ARO Trust which is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market, are classified as available-for-sale, and are reported in Other Assets-Other in the Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 4 for more information regarding the ARO Trust.

Notes receivable - The disclosed fair value of our notes receivable is determined by an income approach which considers the underlying contract amounts and our assessment of our ability to recover these amounts. The current portion is reported in Trade and other receivables, and the noncurrent portion is reported in Other Assets-Other in the Consolidated Balance Sheet.

Long-term debt - The disclosed fair value of our long-term debt 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.

Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the year ended December 31, 2013 or 2012.

6. BENEFIT PLANS.

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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.

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 $22.3 million, $20.3 million and $16.4 million for 2013, 2012, and 2011, respectively.

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 or December 31, 1995, if they were employees or retirees of Transco Energy Company and its subsidiaries. We recognized other postretirement benefit income of $4.2 million and $3.0 million for 2013 and 2011, respectively, and cost of $2.5 million for 2012.

We have been allowed by rate case settlements to collect or refund in future rates any differences between the actuarially determined costs and amounts currently being recovered in rates related to other postretirement benefits. Any differences between the annual actuarially determined cost and amounts currently being recovered in rates are recorded as an adjustment to expense and collected or refunded through future rate adjustments. The amounts of other postretirement benefits costs deferred as a regulatory liability at December 31, 2013 is $25.3 million and is comprised of $6.6 million being deferred for future rate treatment and $18.7 million being amortized over approximately an 8 year period per Docket No. RP12-993. At December 31, 2012, the amount of other postretirement benefit costs deferred consisted of a regulatory liability of $24.7 million deferred for future rate treatment, and a regulatory asset of $4.6 million which was being amortized over a 10 year period per Docket No. RP06-569. Effective March 1, 2013, the residual regulatory asset balance from the prior rate filing was netted against the accumulated regulatory liability.

Defined Contribution Plan.

Williams charged us compensation expense of $6.0 million in 2013, $7.2 million in 2012, and $6.9 million in 2011 for Williams’ company 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 non-management directors. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets achieved.

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

Total stock-based compensation expense for the years ended December 31, 2013, 2012 and 2011 was $3.0 million, $2.8 million and $2.4 million, respectively, excluding amounts allocated from WPZ and Williams.

7. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES.

Major Customers.

Operating revenues received from our two major customers in 2013, 2012 and 2011 are as follows (in millions):

	2013		2012		2011
Public Service Enterprise Group	$	130.7	$	127.4	$	136.7
National Grid	88.5		93.5		98.2

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Affiliates.

We are a participant in WPZ’s cash management program, and we make advances to and receive advances from WPZ. At December 31, 2013 and 2012, our advances to WPZ totaled approximately $526.4 million and $312.2 million, respectively. These advances are represented by demand notes and are classified as Current Assets in the accompanying Consolidated Balance Sheet. Advances are stated at the historical carrying amounts. Interest income is recognized when chargeable and collectability is reasonably assured. 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. At December 31, 2013, the interest rate was 0.01 percent.

On December 31, 2011, Williams completed the spin-off of its former exploration and production business, WPX, by means of a special stock dividend to its shareholders. Included in our operating revenues and cost of sales listed below for the year 2011 are amounts related to activity with WPX.

Included in Operating Revenues in the accompanying Consolidated Statement of Comprehensive Income for 2013, 2012 and 2011 are revenues received from affiliates of $16.3 million, $17.0 million, and $18.5 million, respectively. The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.

Included in Cost of natural gas sales in the accompanying Consolidated Statement of Comprehensive Income for 2013, 2012 and 2011 is purchased gas cost from affiliates of $6.9 million, $3.9 million, and $8.8 million, respectively. All gas purchases are made at market or contract prices.

We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams and its affiliates for all direct and indirect expenses incurred or payments made (including salary, bonus, incentive compensation and benefits) in connection with these services. Employees of Williams also provide general, administrative and management services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. We were billed $310.3 million, $320.1 million, and $278.6 million during 2013, 2012 and 2011, respectively, for these services. Such expenses are primarily included in Administrative and general and Operation and maintenance expenses in the accompanying Consolidated Statement of Comprehensive Income.

Pursuant to an operating agreement, we serve as contract operator on certain Williams Field Services (WFS) facilities. We recorded reductions in operating expenses for services provided to and reimbursed by WFS of $2.3 million, $4.5 million, and $6.4 million in 2013, 2012 and 2011, respectively, under terms of the operating agreement. In 2013, we received $3.6 million of reimbursements from WFS, related to a capital project. Pursuant to construction agreements, we received pre-payments from WFS of $2.3 million and $4.5 million during 2012 and 2011, respectively, associated with capital projects. We received reimbursements totaling $3.1 million from Williams Gas Processing – Gulf Coast Company, L.P. in 2012 associated with costs related to a transfer and assignment agreement.

We made equity distributions of $250 million, $246 million and $219 million during 2013, 2012 and 2011, respectively. In January 2014, an additional distribution of $112 million was declared and paid.

During 2013, 2012 and 2011, WPO made contributions totaling $264 million, $150 million and $115 million, respectively, to us to fund a portion of our expenditures for additions to property, plant and equipment. In January 2014, WPO made an additional $54 million contribution. During 2012, we received a non-cash contribution of $1.5 million from WPO. During 2011, we made a non-cash return of capital to WPO of approximately $0.5 million.

8. ASSET RETIREMENT OBLIGATIONS.

The accrued obligations relate to underground storage caverns, offshore platforms, pipelines, and gas transmission facilities. At the end of the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any related surface equipment, to dismantle offshore platforms, to cap certain gathering pipelines at the wellhead

45

connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground.

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

	2013			2012
Beginning balance	$	296,870		$	302,768
Accretion	31,461			23,052
New obligations	2,225			2,556
Changes in estimates of existing obligations (1)	(27,628		)	10,895
Property dispositions/obligations settled	(28,941		)	(42,401		)
Ending balance	$	273,987		$	296,870

(1) The 2013 changes in estimates of existing obligations reflects decreases of $36 million, primarily due to a revision in the estimated remaining life of the assets, which is among several factors considered in the annual review process, including inflation rates, current estimates for removal cost and discount rates. These decreases are partially offset by an increase of $9 million related to changes in the timing and method of abandonment of our Eminence natural gas storage caverns that were associated with a leak in 2010. The 2012 changes in estimates of existing obligations is primarily due to an increase of $13 million related to changes in the timing and method of abandonment of our Eminence natural gas storage caverns that were associated with a leak in 2010.

We are entitled to collect in rates the amounts necessary to fund our ARO. All funds received for such retirements are deposited into an external trust account dedicated to funding our ARO. Under our current rate settlement our annual funding obligation is approximately $36.4 million, with installments to be deposited monthly.

9. REGULATORY ASSETS AND LIABILITIES.

The regulatory assets and regulatory liabilities resulting from our application of the provisions of ASC Topic 980, Regulated Operations, included in the accompanying Consolidated Balance Sheet at December 31, 2013 and December 31, 2012 are as follows (in millions):

Regulatory Assets	2013		2012
Grossed-up deferred taxes on equity funds used during construction	$	80.6	$	83.5
Asset retirement obligations	128.5		125.1
Asset retirement costs - Eminence	68.2		—
Deferred taxes	8.1		9.1
Postretirement benefits other than pension	—		4.6
Fuel cost	0.7		29.3
Other	8.0		—
Total Regulatory Assets	$	294.1	$	251.6

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Regulatory Liabilities	2013		2012
Negative salvage	$	241.7	$	203.8
Deferred cash out	1.6		6.2
Sentinel meter station depreciation	5.0		3.9
Postretirement benefits other than pension	25.3		24.7
Electric power cost	13.8		7.7
Other	0.2		1.2
Total Regulatory Liabilities	$	287.6	$	247.5

The significant regulatory assets and liabilities include:

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

Asset retirement obligations: Regulatory asset balance established to offset depreciation of the ARO asset and changes in the ARO liability due to the passage of time. The regulatory asset is being recovered through our rates, and is being amortized to expense consistent with the amounts collected in rates.

Asset retirement costs - Eminence: Regulatory asset balance associated with the Eminence Storage Field retirement costs. The regulatory asset is being recovered through our rates, and is being amortized to expense consistent with the amounts collected in rates (See Note 10).

Deferred taxes: Regulatory asset balance was established as a result of an increase to rate base deferred taxes due to an increase to the effective state income tax rate. The regulatory asset is being collected from rate payers over the remaining depreciable lives of the long-lived asset to which they relate.

Postretirement benefits: We recover the actuarially determined cost of postretirement benefits through rates that are set through periodic general rate filings. Any difference between the annual actuarially determined cost and the amount recovered in rates is recorded as a regulatory asset or liability to be collected or refunded through future rate adjustments. These amounts are not included in the rate base.

Fuel cost: This amount represents the 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/refunded in subsequent annual fuel tracker filing periods.

Electric power cost: This amount represents the difference between the electric power costs recovered from our customers and the electric power costs incurred in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual electric power tracker filing periods.

Negative salvage: Our rates include a component designed to recover certain future retirement costs for which we are not required to record an asset retirement obligation. We record a regulatory liability representing the cumulative residual amount of recoveries through rates, net of expenditures associated with these retirement costs.

Deferred cash out: This amount represents the deferral of gains or losses on the purchases and sales of gas imbalances with shippers. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual cash out filing periods.

Sentinel meter station depreciation: This amount reflects the incremental depreciation being recorded related to the meter station modifications made for three of the Sentinel shippers. These modifications will be recovered through a surcharge over a defined period of time as stated in the Sentinel FERC order. The incremental depreciation represents the difference between the FERC granted depreciation rate for such facilities in the last rate case as compared to the

47

depreciation rates in the Sentinel order which are based on the contractual terms in the surcharge agreements. The incremental depreciation will be recorded through the end of the contractual term and then will be amortized.

10. OTHER.

During 2012, we capitalized $8.7 million and $2.4 million, respectively, of project feasibility costs associated with the Rockaway Delivery Lateral Project and the Northeast Connector Project, which had been expensed in prior periods in Other expense, net, upon determining that the projects were probable of development. During 2011, we capitalized $10.1 million of project feasibility costs associated with the Northeast Supply Link Expansion Project, which had been expensed in prior periods in Other expense, net, upon determining that the project was probable of development. These costs will be included in the capital costs of the projects, which we believe are probable of recovery through the projects’ rates.

We detected a leak in an underground cavern at our Eminence Storage Field in Mississippi on December 28, 2010. During 2013, 2012 and 2011, we recorded $4.3 million, $2.5 million and $14.6 million, respectively, of charges to Operation and maintenance expenses primarily related to costs to ensure the safety of the surrounding area.

Due to the abandonment and retirement of four of the seven caverns at our Eminence Storage Field in 2013 and the expected recovery of such costs in our rates, we have reclassified $92 million of costs related to the Eminence ARO from Total property, plant and equipment, netto Regulatory assets (Eminence abandonment regulatory asset). Included inOther expense, net, for the year 2013, consistent with the Agreement in our Docket No. RP12-993 general rate case proceeding, is a charge of $11.5 million, related to the portion of the Eminence abandonment regulatory asset that will not be recovered in rates. We have also recognized income during 2013 of $16.1 million, related to insurance recoveries associated with this event.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized quarterly financial data are as follows (in thousands):

2013	First			Second (1)			Third (2)			Fourth (3)
Operating revenues	$	331,062		$	342,879		$	332,255		$	350,136
Operating expenses	229,301			231,922			235,248			230,713
Operating income	101,761			110,957			97,007			119,423
Interest expense	20,554			20,746			21,416			21,474
Other (income) and deductions, net	(7,768		)	(7,838		)	(8,127		)	(5,335		)
Net income	88,975			98,049			83,718			103,284
Equity interest in unrealized gain (loss) on interest rate hedge	102			404			(102		)	60
Comprehensive income	$	89,077		$	98,453		$	83,616		$	103,344

2012	First			Second			Third			Fourth (4)
Operating revenues	$	309,879		$	293,764		$	302,957		$	327,501
Operating expenses	216,421			230,274			231,945			225,400
Operating income	93,458			63,490			71,012			102,101
Interest expense	23,718			23,668			21,132			20,557
Other (income) and deductions, net	(5,043		)	(8,859		)	(10,082		)	(7,496		)
Net income	74,783			48,681			59,962			89,040
Equity interest in unrealized gain (loss) on interest rate hedge	(25		)	(133		)	(283		)	65
Comprehensive income	$	74,758		$	48,548		$	59,679		$	89,105

(1) Includes a $6.4 million increase to operating expenses related to the portion of the Eminence abandonment regulatory asset that will not be recovered in rates and a $12.1 million decrease for related insurance recoveries.

(2) Includes a $8.1 million increase to operating expenses related to the portion of the Eminence abandonment regulatory asset that will not be recovered in rates and a $3.3 million decrease for related insurance recoveries.

(3) Includes a $3.0 million decrease to operating expenses related to Eminence abandonment costs reduction.

(4) Includes a $15.9 million decrease to operating expenses resulting from the reversal of project feasibility costs from expense to capital associated with Leidy Southeast, Rockaway Lateral and Northeast Connector Expansion projects. Of this amount, $4.8 million was expensed in the first three quarters of 2012.

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Item 9.Changes In and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

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

Evaluation of Disclosure Controls and Procedures

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

Fourth Quarter 2013 Changes in Internal Controls

Except as described below, there have been no changes during the fourth quarter of 2013 that have materially affected, or are reasonably likely to materially affect, our Internal Controls over financial reporting.

Management’s Annual Report on Internal Control over Financial Reporting

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

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

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Under the supervision and with the participation of our management, including our Senior Vice President – Atlantic-Gulf and our Vice President and Chief Accounting Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2013, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (1992). Based on our assessment, we concluded that, as of December 31, 2013, our internal control over financial reporting was effective.

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

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Item 9B.Other information

None.

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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.

Items 14.Principal Accounting Fees and Services

Fees for professional services provided by our independent registered public accounting firm in each of the last two fiscal years in each of the following categories are (in thousands):

	2013		2012
Audit fees	$	1,678	$	1,879
Audit-related fees	—		—
Tax fees	—		—
All other fees	—		—
Total fees	$	1,678	$	1,879

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 consultation.

As a wholly owned subsidiary of WPZ, we do not have a separate audit committee. The policies and procedures for pre-approving audit and non-audit services of the Audit Committee of the Board of Directors of WPZ’s general partner have been set forth in WPZ’s 2013 annual report on Form 10-K, which is available on the SEC’s website at http://www.sec.gov and on WPZ’s website at http://www.williamslp.com under the heading “Investors-SEC Filings”.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

	Page Reference to 2013 10-K
A. 1 and 2. Transcontinental Gas Pipe Line Company, LLC financials
Index
Covered by Report of Independent Registered Public Accounting Firm:
Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2013, 2012 and 2011	27
Consolidated Balance Sheet as of December 31, 2013 and 2012	28
Consolidated Statement of Owner’s Equity for the Years Ended December 31, 2013, 2012 and 2011	30
Consolidated Statement of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011	31
Notes to Consolidated Financial Statements	33
Not covered by Report of Independent Registered Public Accounting Firm :
Quarterly Financial Data (Unaudited)	49
The following schedules are omitted because of the absence of the conditions under which they are required: I, II, III, IV, and V.

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3. Exhibits:

Exhibit Number	Description
2.1	Certificate of Conversion dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 2.1 to our Form 10-K and incorporated herein by reference).
3.1	Certificate of Formation dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 3.1 to our Form 10-K and incorporated herein by reference).
3.2	Amended and Restated Operating Agreement of Transcontinental Gas Pipe Line Company, LLC dated February 17, 2010 (filed on October 28, 2010 as Exhibit 3.2 to our Form 10-Q and incorporated herein by reference).
4.1	Senior Indenture dated July 15, 1996 between Transco and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to our Form S-3 (File No. 333-02155) and incorporated herein by reference).
4.2	Indenture dated April 11, 2006 between Transco and JP Morgan Chase Bank, N.A., as Trustee (filed on April 11, 2006 as Exhibit 4.1 to our Form 8-K (File No. 001-07584) and incorporated herein by reference).
4.3	Indenture, dated as of May 22, 2008 between Transco and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to our Form 8-K (File No. 001-07584) and incorporated herein by reference).
4.4	Indenture, dated as of August 12, 2011 between Transco and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on August 12, 2011 as Exhibit 4.1 to our Form 8-K (File No. 001-07584) and incorporated herein by reference).
4.5	Indenture, dated as of July 13, 2012, between Transco and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on July 16, 2012 as Exhibit 4.1 to our Form 8-K (File No. 001-07584) and incorporated herein by reference).
10.1	Administrative Services Agreement, dated as of February 17, 2010, by and between Transco Pipeline Services LLC and Transco (filed on February 22, 2010 as Exhibit 10.3 to Williams Partners L.P.’s, Form 8-K (File No. 001-32599) and incorporated herein by reference).
10.2	Assignment Agreement dated February 13, 2013 by and between Transco Pipeline Services LLC and Williams WPC-I, LLC, effective January 1, 2013 (filed on February 27, 2013 as Exhibit 10.2 to our Form 10-K and incorporated herein by reference).
10.3	First Amended & Restated Credit Agreement, dated as of July 31, 2013, by and among Williams Partners L.P., Northwest Pipeline LLC and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (filed on July 31, 2013 as Exhibit 10 to Williams Partners L.P.'s Quarterly Report on Form 10-Q and incorporated herein by reference).
31.1*	Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32**	Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

55

101.INS** 101.I SCH ** 101.CAL** 101.DEF** 101.LAB**	XBRL Instance Document. XBRL Taxonomy Extension Schema. XBRL Taxonomy Extension Calculation Linkbase. XBRL Taxonomy Extension Definition Linkbase. XBRL Taxonomy Extension Label Linkbase.
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase.

*     Filed herewith.

**    Furnished herewith.

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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.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC (Registrant)
By:	/s/ Jeffrey P. Heinrichs
	Jeffrey P. Heinrichs
	Controller

Date: February 26, 2014

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

Signature	Title
/s/ Rory L. Miller	Management Committee Member and Senior Vice President – Atlantic-Gulf (Principal Executive Officer)
Rory L. Miller
/s/ Ted T. Timmermans	Vice President and Chief Accounting Officer (Principal Financial Officer)
Ted T. Timmermans
/s/ Jeffrey P. Heinrichs	Controller (Principal Accounting Officer)
Jeffrey P. Heinrichs
/s/ Frank J. Ferazzi	Management Committee Member and Vice President
Frank J. Ferazzi

Date: February 26, 2014

INDEX OF EXHIBITS

Exhibit Number	Description
2.1	Certificate of Conversion dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 2.1 to our Form 10-K and incorporated herein by reference).
3.1	Certificate of Formation dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 3.1 to our Form 10-K and incorporated herein by reference).
3.2	Amended and Restated Operating Agreement of Transcontinental Gas Pipe Line Company, LLC dated February 17, 2010 (filed on October 28, 2010 as Exhibit 3.2 to our Form 10-Q and incorporated herein by reference).
4.1	Senior Indenture dated July 15, 1996 between Transco and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to our Form S-3 (File No. 333-02155) and incorporated herein by reference).
4.2	Indenture dated April 11, 2006 between Transco and JP Morgan Chase Bank, N.A., as Trustee (filed on April 11, 2006 as Exhibit 4.1 to our Form 8-K (File No. 001-07584) and incorporated herein by reference).
4.3	Indenture, dated as of May 22, 2008 between Transco and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to our Form 8-K (File No. 001-07584) and incorporated herein by reference).
4.4	Indenture, dated as of August 12, 2011 between Transco and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on August 12, 2011 as Exhibit 4.1 to our Form 8-K (File No. 001-07584) and incorporated herein by reference).
4.5	Indenture, dated as of July 13, 2012, between Transco and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on July 16, 2012 as Exhibit 4.1 to our Form 8-K (File No. 001-07584) and incorporated herein by reference).
10.1	Administrative Services Agreement, dated as of February 17, 2010, by and between Transco Pipeline Services LLC and Transco (filed on February 22, 2010 as Exhibit 10.3 to Williams Partners L.P.’s, Form 8-K (File No. 001-32599) and incorporated herein by reference).
10.2	Assignment Agreement dated February 13, 2013 by and between Transco Pipeline Services LLC and Williams WPC-I, LLC, effective January 1, 2013 (filed on February 27, 2013 as Exhibit 10.2 to our Form 10-K and incorporated herein by reference).
10.3	First Amended & Restated Credit Agreement, dated as of July 31, 2013, by and among Williams Partners L.P., Northwest Pipeline LLC and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (filed on July 31, 2013 as Exhibit 10 to Williams Partners L.P.'s Quarterly Report on Form 10-Q and incorporated herein by reference).
31.1*	Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32 **	Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS**	XBRL Instance Document.
101.I SCH **	XBRL Taxonomy Extension Schema.
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF**	XBRL Taxonomy Extension Definition Linkbase.
101.LAB**	XBRL Taxonomy Extension Label Linkbase.
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase.

*     Filed herewith.

**    Furnished herewith.

EX-31.1

Exhibit 31.1

SECTION 302 CERTIFICATION

I, Rory L. Miller, certify that:

1. I have reviewed this annual report on Form 10-K of Transcontinental Gas Pipe Line Company, LLC;

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

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

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

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

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

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

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

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

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

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

Date: February 26, 2014

By:	/s/ Rory L. Miller
	Rory L. Miller
	Senior Vice President — Atlantic-Gulf
	(Principal Executive Officer)

EX-31.2

Exhibit 31.2

SECTION 302 CERTIFICATION

I, Ted T. Timmermans, certify that:

1. I have reviewed this annual report on Form 10-K of Transcontinental Gas Pipe Line Company, LLC;

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

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

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

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

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

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

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

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

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

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

Date: February 26, 2014

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

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annul Report of Transcontinental Gas Pipe Line Company, LLC (the “Company”) on Form 10-K for the period ending December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies, in his capacity as an officer of the Company, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

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

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

/s/ Rory L. Miller

Rory L. Miller

Senior Vice President — Atlantic-Gulf

February 26, 2014

/s/ Ted T. Timmermans

Ted T. Timmermans

Vice President and Chief Accounting Officer

February 26, 2014

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

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

XML

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 296,870,000	$ 302,768,000
Accretion	31,461,000	23,052,000
New obligations	2,225,000	2,556,000
Changes in estimates of existing obligations (1)	(27,628,000)	10,895,000
Property dispositions/obligations settled	(28,941,000)	(42,401,000)
Ending balance	273,987,000	296,870,000
Annual funding obligation	36,400,000
Asset retirement obligation [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Changes in estimates of existing obligations (1)	(36,000,000)
Eminence natural gas storage caverns [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Changes in estimates of existing obligations (1)	9,000,000	13,000,000
External ARO trust [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Annual funding obligation	$ 36,400,000

XML

Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets [Table Text Block]

The regulatory assets and regulatory liabilities resulting from our application of the provisions of ASC Topic 980, Regulated Operations, included in the accompanying Consolidated Balance Sheet at December 31, 2013 and December 31, 2012 are as follows (in millions):

Regulatory Assets	2013		2012
Grossed-up deferred taxes on equity funds used during construction	$	80.6	$	83.5
Asset retirement obligations	128.5		125.1
Asset retirement costs - Eminence	68.2		—
Deferred taxes	8.1		9.1
Postretirement benefits other than pension	—		4.6
Fuel cost	0.7		29.3
Other	8.0		—
Total Regulatory Assets	$	294.1	$	251.6

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory Liabilities	2013		2012
Negative salvage	$	241.7	$	203.8
Deferred cash out	1.6		6.2
Sentinel meter station depreciation	5.0		3.9
Postretirement benefits other than pension	25.3		24.7
Electric power cost	13.8		7.7
Other	0.2		1.2
Total Regulatory Liabilities	$	287.6	$	247.5

XML

Debt, Financing Arrangements and Leases (Notes)

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Debt, Financing Arrangements and Leases

DEBT, FINANCING ARRANGEMENTS AND LEASES.

Long-Term Debt.

At December 31, 2013 and 2012, long-term debt issues were outstanding as follows (in thousands):

	2013			2012
Debentures:
7.08% due 2026	$	7,500		$	7,500
7.25% due 2026	200,000			200,000
Total debentures	207,500			207,500
Notes:
6.4% due 2016	200,000			200,000
6.05% due 2018	250,000			250,000
5.4% due 2041	375,000			375,000
4.45% due 2042	400,000			400,000
Total notes	1,225,000			1,225,000
Total long-term debt issues	1,432,500			1,432,500
Unamortized debt premium and discount	(4,145		)	(4,177		)
Total long-term debt, less current maturities	$	1,428,355		$	1,428,323

Aggregate minimum maturities (face value) applicable to long-term debt outstanding at December 31, 2013, for the next five years, are as follows (in thousands):

2016:     6.4% Notes	$200,000
2018:     6.05% Notes	$250,000

There are no maturities applicable to long-term debt outstanding for the years 2014, 2015, and 2017.

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

Restrictive Debt Covenants.

At December 31, 2013, none of our debt instruments restrict the amount of distributions to our parent. Our debt agreements contain restrictions on our ability to incur secured debt beyond certain levels.

Credit Facility.

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

Under the credit facility, WPZ is required to maintain a ratio of debt to EBITDA (each as defined in the credit facility) that must be no greater than 5.0 to 1.0. 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. In addition, the ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for us and our consolidated subsidiaries. At December 31, 2013, we are in compliance with these financial covenants.

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

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

WPZ participates in a commercial paper program and WPZ management considers amounts outstanding under this program to be a reduction of available capacity under the credit facility. The program allows a maximum outstanding amount at any time of $2 billion of unsecured commercial paper notes. At December 31, 2013, WPZ had $225 million in outstanding commercial paper.

Issuance and Retirement of Long-Term Debt.

On July 13, 2012, we issued $400 million aggregate principal amount of 4.45 percent senior unsecured notes due 2042 (4.45 percent Notes) to certain institutional investors pursuant to certain exemptions from registration under the Securities Act of 1933, as amended. Interest is payable on February 1 and August 1 of each year, beginning February 1, 2013. A portion of these proceeds was used to repay our $325 million 8.875 percent notes that matured on July 15, 2012. We used the remainder for general corporate purposes, including the funding of capital expenditures.

As part of the new issuance, we entered into a registration rights agreement with the initial purchasers of the 4.45 percent Notes. An offer to exchange these unregistered notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended, was commenced in November 2012 and completed in December 2012.

Lease Obligations.

The future minimum lease payments under our various operating leases are as follows (in thousands):

2014	$	10,154
2015	10,025
2016	10,025
2017	9,971
2018	9,956
Thereafter	22,401
Total net minimum obligations	$	72,532

Our lease expense was $11.4 million in 2013, $10.9 million in 2012, and $9.1 million in 2011.

XML

Investments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Investments, Debt and Equity Securities [Abstract]
Annual funding obligation	$ 36.4
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, amortized cost basis	28.9	15.0
Available-for-sale securities, fair value	32.7	17.8
Cash And Money Market Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, amortized cost basis	6.5	1.3
Available-for-sale securities, fair value	6.5	1.3
U.S. Equity Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, amortized cost basis	8.0	5.4
Available-for-sale securities, fair value	11.1	7.4
International Equity Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, amortized cost basis	4.2	3.4
Available-for-sale securities, fair value	4.9	3.8
Municipal Bond Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, amortized cost basis	10.2	4.9
Available-for-sale securities, fair value	$ 10.2	$ 5.3

XML

Debt, Financing Arrangements and Leases (Details) (USD $)	12 Months Ended					12 Months Ended		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 Williams Partners L.P. [Member]	Jul. 31, 2013 $2.4 billion credit facility [Member] Williams Partners L.P. [Member]	Dec. 31, 2013 $2.5 billion credit facility [Member]	Jul. 31, 2013 $2.5 billion credit facility [Member]	Dec. 31, 2013 $2.5 billion credit facility [Member] Williams Partners L.P. [Member]	Jul. 31, 2013 $2.5 billion credit facility [Member] Williams Partners L.P. [Member]	Jul. 31, 2013 $2.5 billion credit facility [Member] Williams Partners L.P. [Member] Letter of credit [Member]	Dec. 31, 2013 Commercial paper [Member] Williams Partners L.P. [Member]	Jul. 13, 2012 4.45% senior unsecured notes due 2042 [Member]	Jul. 15, 2012 8.875% senior unsecured notes due 2012 [Member]	Dec. 31, 2013 Debentures	Dec. 31, 2012 Debentures	Dec. 31, 2013 Debentures 7.08% due 2026 [Member]	Dec. 31, 2012 Debentures 7.08% due 2026 [Member]	Dec. 31, 2013 Debentures 7.25% due 2026 [Member]	Dec. 31, 2012 Debentures 7.25% due 2026 [Member]	Dec. 31, 2013 Notes	Dec. 31, 2012 Notes	Dec. 31, 2013 Notes 6.4% due 2016 [Member]	Dec. 31, 2012 Notes 6.4% due 2016 [Member]	Dec. 31, 2013 Notes 6.05% due 2018 [Member]	Dec. 31, 2012 Notes 6.05% due 2018 [Member]	Dec. 31, 2013 Notes 5.4% due 2041 [Member]	Dec. 31, 2012 Notes 5.4% due 2041 [Member]	Dec. 31, 2013 Notes 4.45% due 2042 [Member]	Dec. 31, 2012 Notes 4.45% due 2042 [Member]
Debt Instrument [Line Items]
Total long-term debt issues	$ 1,432,500,000	$ 1,432,500,000												$ 207,500,000	$ 207,500,000	$ 7,500,000	$ 7,500,000	$ 200,000,000	$ 200,000,000	$ 1,225,000,000	$ 1,225,000,000	$ 200,000,000	$ 200,000,000	$ 250,000,000	$ 250,000,000	$ 375,000,000	$ 375,000,000	$ 400,000,000	$ 400,000,000
Unamortized debt premium and discount	(4,145,000)	(4,177,000)
Total long-term debt, less current maturities	1,428,355,000	1,428,323,000
Debt instrument, face amount												400,000,000	325,000,000
Debt instrument, interest rate, stated percentage												4.45%	8.875%
Long-term Debt, Fiscal Year Maturity [Abstract]
2014	0
2015	0
2016: 6.4% Notes	200,000,000
2017	0
2018: 6.05% Notes	250,000,000
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity					2,400,000,000		500,000,000		2,500,000,000	1,300,000,000	2,000,000,000
Additional amount by which credit facility can be increased									500,000,000
Letters of credit outstanding, amount								0
Line of credit facility, amount outstanding								0
Line of credit facility, remaining borrowing capacity						500,000,000
Debt to EBITDA, ratio								5.0
Debt to EBITDA, after acquisitions, ratio								5.5
Purchase price of acquistions increasing debt to EBITDA ratio, aggregate								50,000,000
Ratio of indebtedness to net capital	0.65
Line of credit facility, unused capacity, commitment fee percentage						0.20%
Commercial paper				225,000,000
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2014	10,154,000
2015	10,025,000
2016	10,025,000
2017	9,971,000
2018	9,956,000
Thereafter	22,401,000
Total net minimum obligations	72,532,000
Operating leases, rent expense	$ 11,400,000	$ 10,900,000	$ 9,100,000

XML

Fair Value Measurements (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
ARO Trust investments	$ 32,700,000	$ 17,800,000
Fair Value, Transfers Between Level 1 and Level 2, Description and Policy [Abstract]
Fair Value, Assets, Level 1 to Level 2 Transfers, Amount	0	0
Fair Value, Assets, Level 2 to Level 1 Transfers, Amount	0	0
Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount	0	0
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount	0	0
Fair Value, Inputs, Level 1 [Member]
Additional Fair Value Elements [Abstract]
Notes Receivable, Fair Value Disclosure	0	0
Long-term Debt, Fair Value	0	0
Fair Value, Inputs, Level 2 [Member]
Additional Fair Value Elements [Abstract]
Notes Receivable, Fair Value Disclosure	6,300,000	8,200,000
Long-term Debt, Fair Value	(1,512,900,000)	(1,704,500,000)
Fair Value, Inputs, Level 3 [Member]
Additional Fair Value Elements [Abstract]
Notes Receivable, Fair Value Disclosure	0	0
Long-term Debt, Fair Value	0	0
Reported Value Measurement [Member]
Additional Fair Value Elements [Abstract]
Notes Receivable, Fair Value Disclosure	6,300,000	8,200,000
Long-term Debt, Fair Value	(1,428,400,000)	(1,428,300,000)
Estimate of Fair Value Measurement [Member]
Additional Fair Value Elements [Abstract]
Notes Receivable, Fair Value Disclosure	6,300,000	8,200,000
Long-term Debt, Fair Value	(1,512,900,000)	(1,704,500,000)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
ARO Trust investments	32,700,000	17,800,000
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
ARO Trust investments	0	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
ARO Trust investments	0	0
Fair Value, Measurements, Recurring [Member] | Reported Value Measurement [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
ARO Trust investments	32,700,000	17,800,000
Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
ARO Trust investments	$ 32,700,000	$ 17,800,000

XML

Benefit Plans (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension and Other Postretirement Benefit Expense [Abstract]
Pension cost	$ 22.3	$ 20.3	$ 16.4
Other postretirement benefit (income) expense	(4.2)	2.5	(3.0)
Defined contribution plan, cost recognized	6.0	7.2	6.9
Regulatory Assets [Line Items]
Regulatory assets	294.1	251.6
Regulatory Liabilities [Line Items]
Regulatory liabilities	287.6	247.5
Salaries, Wages and Officers' Compensation [Abstract]
Allocated share-based compensation expense	3.0	2.8	2.4
Other postretirement benefits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	25.3	24.7
Regulatory liability, deferred for future rate treatment	6.6
Regulatory liability, being amortized	18.7
Other postretirement benefits [Member]
Regulatory Assets [Line Items]
Regulatory assets	$ 0	$ 4.6

XML

Contingent Liabilities and Commitments (Notes)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Contingent Liabilities and Commitments

CONTINGENT LIABILITIES AND COMMITMENTS.

Rate Matters.

General rate case (Docket No. RP12-993) On August 31, 2012, we submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in our Docket No. RP06-569 rate proceeding (see below) which required us to file a rate case no later than August 31, 2012. On September 28, 2012, the FERC issued an order accepting our filing subject to the outcome of a hearing. The rates for certain services that were proposed as overall rate decreases became effective October 1, 2012, without suspension. The increased rates became effective March 1, 2013, subject to refund and the outcome of the hearing. On August 27, 2013, after reaching an agreement in principle with the participants, we filed a stipulation and agreement (Agreement) proposing to resolve all issues in this proceeding without the need for a hearing. On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement will become effective March 1, 2014. We have provided a reserve for rate refunds which we believe is adequate for required refunds as of December 31, 2013, under the Agreement. Refunds will be made on or before April 30, 2014.

General rate case (Docket No. RP06-569) On August 31, 2006, we submitted to the FERC a general rate filing principally designed to recover increased costs. The rates became effective March 1, 2007, subject to refund and the outcome of a hearing. All issues in this proceeding except one have been resolved by settlement.

The one issue reserved for litigation or further settlement relates to our proposal to change the design of the rates for service under one of our storage rate schedules, which was implemented subject to refund on March 1, 2007. A hearing on that issue was held before a FERC Administrative Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision in which he determined that our proposed incremental rate design is unjust and unreasonable. On January 21, 2010, the FERC reversed the ALJ’s initial decision, and approved our proposed incremental rate design. Certain parties sought rehearing of the FERC’s order and, on April 2, 2012, the FERC denied the rehearing request. On June 1, 2012, one of the parties filed an appeal in the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit). On February 21, 2014, the D.C. Circuit issued an opinion that vacated and remanded the FERC's order because the FERC did not adequately support its conclusions. We intend to continue to pursue approval of our proposed rate design. If we are unsuccessful, we believe any refunds would not be material to our results of operations.

Environmental Matters.

We have had studies underway to test some of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. We have responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that environmental assessment and remediation costs under various federal and state statutes will total approximately $6 million to $8 million (including both expense and capital expenditures), measured on an undiscounted basis, and will be spent over the next three to five years. This estimate depends on a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of the remedial measures. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At December 31, 2013, we had a balance of approximately $4.1 million for the expense portion of these estimated costs recorded in current liabilities ($2.3 million) and other long-term liabilities ($1.8 million) in the accompanying Consolidated Balance Sheet. At December 31, 2012, we had a balance of approximately $3.3 million for the expense portion of these estimated costs recorded in current liabilities ($1.1 million) and other long-term liabilities ($2.2 million) in the accompanying Consolidated Balance Sheet.

Although we discontinued the use of lubricating oils containing polychlorinated biphenyls (PCBs) in the 1970s, we have discovered residual PCB contamination in equipment and soils at certain gas compressor station sites. We have worked closely with the EPA and state regulatory authorities regarding PCB issues, and we have a program to assess and remediate such conditions where they exist. In addition, we commenced negotiations with certain environmental authorities and other parties concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. All such costs are included in the $6 million to $8 million range discussed above.

We have been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, our estimated aggregate exposure for remediation of these sites is less than $0.5 million. The estimated remediation costs for all of these sites are included in the $6 million to $8 million range discussed above. Liability under the Comprehensive Environmental Response, Compensation and Liability Act and applicable state law can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.

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. Several Transco facilities are located in 2008 ozone non-attainment areas; however, each facility has been previously subjected to federal and/or state emission control requirements implemented to address preceding ozone standards. To date, no new federal or state actions have been proposed to mandate additional emission controls at these facilities. At this time, it is unknown whether future federal or 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 federal or state regulatory actions are proposed, we are unable to estimate the cost of additions that may be required to meet this new regulation.

Additionally, in August 2010, the EPA promulgated National Emission Standards for Hazardous Air Pollutants (NESHAP) regulations that will impact our operations. All capital expenditures related to compliance with these hazardous air pollutant regulations were completed, and affected facilities were in compliance by the October 2013 regulatory deadline.

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

We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. As a result, as estimated costs of environmental assessment and remediation are incurred, they are recorded as regulatory assets in the Consolidated Balance Sheet until collected through rates. At December 31, 2013, we had a balance of approximately $1.8 million of uncollected environmental related regulatory assets recorded in current assets ($1.2 million) and other assets ($0.6 million) in the accompanying Consolidated Balance Sheet. We had no uncollected environmental related regulatory assets at December 31, 2012.

By letter dated September 20, 2007, the EPA required us to provide information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPA’s investigation of our compliance with the Federal Clean Air Act (Act). By January 2008, we responded with the requested information. By Notices of Violation (NOVs) dated March 28, 2008, the EPA found us to be in violation of the requirements of the Act with respect to these compressor stations. We met with the EPA in May 2008 to discuss the allegations contained in the NOVs; in June 2008, we submitted to the EPA a written response denying the allegations. The EPA has requested additional information pertaining to these compressor stations and in May 2011, we submitted information in response to the EPA’s latest request. In August, 2010, the EPA requested, and we provided, similar information for a compressor station in Maryland. Since 2011, we have not received any additional requests from the EPA for information related to these facilities.

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.

Commitments for construction We have commitments for construction and acquisition of property, plant and equipment of approximately $368 million at December 31, 2013.

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Transactions with Major Customers and Affiliates (Details) (USD $)	1 Months Ended	12 Months Ended
	Jan. 31, 2014	Dec. 31, 2013 employee	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]
Advances to affiliate		$ 526,380,000	$ 312,165,000
Related party transaction, rate		0.01%
Operating revenues, related party		16,300,000	17,000,000	18,500,000
Purchases, related party		6,900,000	3,900,000	8,800,000
Entity number of employees		0
Expenses, related party		310,300,000	320,100,000	278,600,000
Equity distributions	112,000,000	250,000,000	246,259,000	219,000,000
Cash contributions from parent		264,000,000	150,000,000	115,000,000
Public Service Enterprise Group [Member]
Revenue, Major Customer [Line Items]
Operating revenues		130,700,000	127,400,000	136,700,000
National Grid [Member]
Revenue, Major Customer [Line Items]
Operating revenues		88,500,000	93,500,000	98,200,000
Williams Partners L.P. [Member]
Related Party Transaction [Line Items]
Advances to affiliate		526,400,000	312,200,000
Williams Field Services [Member]
Related Party Transaction [Line Items]
Expenses, related party		(2,300,000)	(4,500,000)	(6,400,000)
Reimbursements and pre-payments for capital projects		3,600,000	2,300,000	4,500,000
Williams Gas Processing - Gulf Coast Company, L.P. [Member]
Related Party Transaction [Line Items]
Reimbursement			3,100,000
Williams Partners Operating LLC [Member]
Related Party Transaction [Line Items]
Cash contributions from parent	54,000,000	264,000,000	150,000,000	115,000,000
Non-cash contributions from parent			1,500,000
Non-cash return of capital to parent				$ 500,000

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Consolidated Statement of Comprehensive Income (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Revenues:
Natural gas sales	$ 113,488	$ 65,120	$ 108,359
Natural gas transportation	1,094,807	1,022,990	983,554
Natural gas storage	143,047	140,390	142,556
Other	4,990	5,601	8,045
Total operating revenues	1,356,332	1,234,101	1,242,514
Operating Costs and Expenses:
Cost of natural gas sales	113,488	65,120	108,359
Cost of natural gas transportation	24,936	31,815	35,674
Operation and maintenance	264,631	299,734	281,496
Administrative and general	182,352	174,610	148,113
Depreciation and amortization	265,273	266,445	259,660
Taxes - other than income taxes	43,898	45,086	41,673
Other expense, net	32,606	21,230	12,988
Total operating costs and expenses	927,184	904,040	887,963
Operating Income	429,148	330,061	354,551
Other (Income) and Other Expenses:
Interest expense - affiliate	190	309	262
Interest expense - other	84,000	88,766	94,920
Interest income - affiliate	(45)	(35)	(29)
Interest income - other	(2,068)	(2,351)	(2,119)
Allowance for equity and borrowed funds used during construction (AFUDC)	(18,595)	(19,257)	(15,339)
Equity in earnings of unconsolidated affiliates	(5,678)	(7,458)	(5,164)
Miscellaneous other (income) expenses, net	(2,682)	(2,379)	2,362
Total other (income) and other expenses	55,122	57,595	74,893
Net Income	374,026	272,466	279,658
Other comprehensive income (loss):
Equity interest in unrealized gain (loss) on interest rate hedges (includes $330, $220, and $170 for the years ended December 31, 2013, 2012, and 2011, respectively, of accumulated other comprehensive income reclassification for realized losses on interest rate hedges)	464	(376)	(519)
Comprehensive Income	$ 374,490	$ 272,090	$ 279,139

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Consolidated Statement of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities:
Net income	$ 374,026	$ 272,466	$ 279,658
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	263,949	266,981	260,069
Allowance for equity funds used during construction (equity AFUDC)	(13,299)	(13,222)	(10,588)
Changes in operating assets and liabilities:
Receivables - affiliates	55	3,247	(982)
Receivables - trade and other	(21,772)	(4,186)	(11,155)
Transportation and exchange gas receivable	(3,881)	2,038	(2,497)
Regulatory assets - current	28,536	1,171	10,567
Regulatory assets - non-current	21,910	(5,980)	(8,698)
Inventories	232	673	50,295
Payables - affiliates	(3,738)	15,069	(1,832)
Payables - trade	(26,463)	3,727	14,577
Accrued liabilities	28,322	8,256	27,775
Asset retirement obligations	13,105	35,195	(6,964)
Asset retirement obligation - removal costs	(26,919)	(41,052)	(43,666)
Reserve for rate refunds	98,217	0	0
Other, net	10,731	(2,934)	15,085
Net cash provided by operating activities	743,011	541,449	571,644
Cash flows from financing activities:
Additions to long-term debt	0	398,804	372,518
Retirement of long-term debt	0	(325,000)	(300,000)
Debt issue costs	0	(4,403)	(3,846)
Cash distributions to parent	(250,000)	(246,259)	(219,000)
Cash contributions from parent	264,000	150,000	115,000
Other, net	(3,034)	(3,333)	(4,681)
Net cash provided by (used in) financing activities	10,966	(30,191)	(40,009)
Cash flows from investing activities:
Property, plant and equipment additions, net of equity AFUDC	(526,916)	(475,450)	(385,671)
Disposal of property, plant and equipment, net	(3,621)	7,157	2,698
Advances to affiliate, net	(214,215)	(58,554)	(144,773)
Return of capital from unconsolidated affiliates	1,438	11,327	1,925
Contributions to unconsolidated affiliates	0	(5,806)	(14,834)
Purchase of ARO Trust investments	(58,242)	(34,430)	(41,310)
Proceeds from sale of ARO Trust investments	45,607	43,205	56,576
Other, net	1,900	1,314	(6,230)
Net cash used in investing activities	(754,049)	(511,237)	(531,619)
Increase (decrease) in cash	(72)	21	16
Cash at beginning of period	185	164	148
Cash at end of period	113	185	164
Increase to property, plant and equipment	(558,201)	(466,115)	(386,462)
Changes in related accounts payable and accrued liabilities	31,285	(9,335)	791
Property, plant and equipment additions, net of equity AFUDC	(526,916)	(475,450)	(385,671)
Supplemental Cash Flow Elements [Abstract]
Interest (exclusive of amount capitalized)	76,803	86,586	88,357
Income taxes	$ 116	$ 254	$ 728

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Other (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment [Line Items]
Total property, plant and equipment, net	$ 5,777,392,000	$ 5,551,913,000
Other expense, net	(32,606,000)	(21,230,000)	(12,988,000)
Operation and maintenance	264,631,000	299,734,000	281,496,000
Regulatory assets	294,100,000	251,600,000
Rockaway Delivery Lateral Project [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment, net		8,700,000
Other expense, net		8,700,000
Northeast Connector Project [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment, net		2,400,000
Other expense, net		2,400,000
Northeast Supply Link Expansion Project [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment, net			10,100,000
Other expense, net			10,100,000
Eminence Storage Field [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment, net	(92,000,000)
Other expense, net	(11,500,000)
Operation and maintenance	4,300,000	2,500,000	14,600,000
Regulatory assets	92,000,000
Insurance recoveries	$ 16,100,000

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Schedule of fair value, assets and liabilities measured on recurring basis

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities.

							Fair Value Measurements Using
	Carrying Amount			Fair Value			Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
							(Millions)
Assets (liabilities) at December 31, 2013:
Measured on a recurring basis:
ARO Trust investments	$	32.7		$	32.7		$	32.7	$	—		$	—
Additional disclosures:
Notes receivable	6.3			6.3			—		6.3			—
Long-term debt	(1,428.4		)	(1,512.9		)	—		(1,512.9		)	—
Assets (liabilities) at December 31, 2012:
Measured on a recurring basis:
ARO Trust investments	$	17.8		$	17.8		$	17.8	$	—		$	—
Additional disclosures:
Notes receivable	8.2			8.2			—		8.2			—
Long-term debt, including current portion	(1,428.3		)	(1,704.5		)	—		(1,704.5		)	—

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Schedule of change in asset retirement obligation

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

	2013			2012
Beginning balance	$	296,870		$	302,768
Accretion	31,461			23,052
New obligations	2,225			2,556
Changes in estimates of existing obligations (1)	(27,628		)	10,895
Property dispositions/obligations settled	(28,941		)	(42,401		)
Ending balance	$	273,987		$	296,870

(1) The 2013 changes in estimates of existing obligations reflects decreases of $36 million, primarily due to a revision in the estimated remaining life of the assets, which is among several factors considered in the annual review process, including inflation rates, current estimates for removal cost and discount rates. These decreases are partially offset by an increase of $9 million related to changes in the timing and method of abandonment of our Eminence natural gas storage caverns that were associated with a leak in 2010. The 2012 changes in estimates of existing obligations is primarily due to an increase of $13 million related to changes in the timing and method of abandonment of our Eminence natural gas storage caverns that were associated with a leak in 2010.

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Summary of Significant Accounting Policies (Notes)

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES.

Corporate Structure and Control.

In this report, Transco (which includes Transcontinental Gas Pipe Line Company, LLC and unless the context otherwise requires, all of our majority-owned subsidiaries) is at times referred to in the first person as “we,” “us” or “our.”

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

Transco is a single member limited liability company, and as such, single member losses are limited to the amount of their investment.

Related Party Transaction.

A member of Williams' Board of Directors, who was elected in 2013, is also the current chairman, president, and chief executive officer of an energy services company that is a customer of ours. We recorded $130.7 million in operating revenues in the Consolidated Statement of Comprehensive Income from this company for transportation and storage of natural gas for the year ended December 31, 2013. This board member does not have any material interest in any transactions between the energy services company and us and he had no role in any such transactions.

Nature of Operations.

We are an interstate natural gas transmission company that owns a natural gas pipeline system extending from Texas, Louisiana, Mississippi and the Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Delaware, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and the 12 southeast and Atlantic seaboard states mentioned above, including major metropolitan areas in Georgia, Washington D.C., Maryland, North Carolina, New York, New Jersey and Pennsylvania.

Regulatory Accounting.

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

Basis of Presentation.

Williams’ acquisition of Transco Energy Company and its subsidiaries, including us, in 1995 was accounted for using the purchase method of accounting. Accordingly, an allocation of the purchase price was assigned to our assets and liabilities based on their estimated fair values. The purchase price allocation to us primarily consisted of a $1.5 billion allocation to property, plant and equipment and adjustments to deferred taxes based upon the book basis of the net assets recorded as a result of the acquisition. The amount allocated to property, plant and equipment is being depreciated on a straight-line basis over 40 years, the estimated useful lives of these assets at the date of acquisition, at approximately $35 million per year. At December 31, 2013, the remaining property, plant and equipment allocation was approximately $0.7 billion. Current FERC policy does not permit us to recover through rates amounts in excess of original cost.

We are a participant in WPZ’s cash management program. We make advances to and receive advances from WPZ. The 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.

Certain prior period amounts reported within Total operating costs and expenses in the Consolidated Statement of Comprehensive Income have been reclassified to conform to the current presentation. The effect of the correction increased Operation and maintenance costs $7.1 million and $6.8 million for the years ended December 31, 2012 and 2011, respectively, for the reclassification from Taxes-other than income taxes with no net impact on Total operating costs and expenses, Operating Income and Net Income.

Principles of Consolidation.

The consolidated financial statements include our accounts and the accounts of the subsidiaries we control. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments as of December 31, 2013 and December 31, 2012 consist of Cardinal Pipeline Company, LLC (Cardinal) with ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC (Pine Needle) with ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $11.5 million, $14.3 million, and $6.2 million in 2013, 2012 and 2011, respectively. Included in the distributions are $1.4 million return of capital from Pine Needle in 2013 and $11.3 million return of capital from Cardinal in 2012. We made capital contributions to Cardinal related to Cardinal’s expansion project totaling $5.8 million in 2012.

Use of Estimates.

The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4) impairment assessments of long-lived assets; 5) depreciation; and 6) asset retirement obligations.

Revenue Recognition.

Revenues for transportation of gas under long-term firm agreements are recognized considering separately the reservation and commodity charges. Reservation revenues are recognized monthly over the term of the agreement regardless of the volume of natural gas transported. Commodity revenues from both firm and interruptible transportation are recognized in the period transportation services are provided based on volumes of natural gas physically delivered at the agreed upon delivery point. Revenues for the storage of gas under firm agreements are recognized considering separately the reservation, capacity, and injection and withdrawal charges. Reservation and capacity revenues are recognized monthly over the term of the agreement regardless of the volume of storage service actually utilized. Injection and withdrawal revenues are recognized in the period when volumes of natural gas are physically injected into or withdrawn from storage.

In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided for in our FERC tariff. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances (See Gas Imbalances in this Note).

As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel and other risks.

Environmental Matters.

We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their economic benefit and potential for rate recovery. We believe that 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 is recorded at cost. The carrying values of these assets are also based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. These estimates, assumptions and judgments reflect FERC regulations, as well as historical experience and expectations regarding future industry conditions and operations. 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. All other costs are expensed as incurred. Gains or losses from the ordinary sale or retirement of property, plant and equipment are credited or charged to accumulated depreciation; certain other gains or losses are recorded in operating income.

We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission facilities, production and gathering facilities and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2013, 2012 and 2011 are as follows:

Category of Property	2013 (1)	2012-2011
Gathering facilities	1.35% - 2.50%	0.18% - 1.66%
Storage facilities	2.10% -  2.25%	2.10% -  3.70%
Onshore transmission facilities	2.61%  -  5.00%	2.79%  -  5.71%
Offshore transmission facilities	1.20%  -  1.20%	1.01%  -  1.01%

(1) Changes in depreciation rates in 2013 due to placing into effect, subject to refund, the rates in Docket No. RP12-993 on March 1, 2013.

We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. Measurements of AROs include, 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 a market-risk premium. The ARO asset is depreciated in a manner consistent with the expected timing of the future abandonment of the underlying physical assets. We measure changes in the liability due to passage of time by applying an interest method of allocation. The depreciation of the ARO asset and accretion of the ARO liability are recognized as an increase to a regulatory asset, as management expects to recover such amounts in future rates. The regulatory asset is amortized commensurate with our collection of these costs in rates.

Impairment of Long-lived Assets.

We evaluate the long lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. We apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

For assets identified to be disposed of in the future and considered held for sale in accordance with the ASC Property, Plant, and Equipment (Topic 360), we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.

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

Allowance for Funds Used During Construction.

Allowance for funds used during construction (AFUDC) represents the estimated cost of borrowed and equity funds applicable to utility plant in process of construction and are included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. The FERC has prescribed a formula to be used in computing separate allowances for borrowed and equity AFUDC. The allowance for borrowed funds used during construction was $5.3 million, $6.0 million and $4.7 million, for 2013, 2012 and 2011, respectively. The allowance for equity funds was $13.3 million, $13.2 million, and $10.6 million, for 2013, 2012 and 2011, respectively.

Income Taxes.

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

Accounts Receivable and Allowance for Doubtful Receivables.

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

Gas Imbalances.

In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems which may deliver different quantities of gas on behalf of us than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables which are recovered or repaid in cash or through the receipt or delivery of gas in the future and are recorded in the accompanying Consolidated Balance Sheet. 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. Our tariff includes a method whereby most transportation imbalances are settled on a monthly basis. Each month a portion of the imbalances are not identified to specific parties and remain unsettled. These are generally identified to specific parties and settled in subsequent periods. We believe that amounts that remain unidentified to specific parties and unsettled at year end are valid balances that will be settled with no material adverse effect upon our financial position, results of operations or cash flows. Management has implemented a policy of continuing to carry any unidentified transportation and exchange imbalances on the books for a three-year period. At the end of the three year period a final assessment will be made of their continued validity. Absent a valid reason for maintaining the imbalance, any remaining balance will be recognized in income. Certain imbalances are being recovered or repaid in cash or through the receipt or delivery of gas upon agreement of the parties as to the allocation of the gas volumes, and as permitted by pipeline operating conditions. These imbalances have been classified as current assets and current liabilities at December 31, 2013 and 2012. We utilize the average cost method of accounting for gas imbalances.

Deferred Cash Out.

Most transportation imbalances are settled in cash on a monthly basis (cash out). We are required by our tariff to refund revenues received from the cash out of transportation imbalances in excess of costs incurred during the annual August through July reporting period. Revenues received in excess of costs incurred are deferred until refunded in accordance with the tariff.

Gas Inventory.

We utilize the last-in, first-out (LIFO) method of accounting for inventory gas in storage. If inventories valued using the LIFO cost method were valued at current replacement cost, the amounts would increase by $1.3 million at December 31, 2013. At December 31, 2012, physical withdrawals from the Eminence Storage facility exceeded the customer nominations for withdrawals, resulting in a liability. The basis for determining current cost at the end of each year is the December monthly average gas price delivered to pipelines in Texas and Louisiana. We utilize the average cost method of accounting for gas available for customer nomination. Liquefied natural gas in storage is valued at original cost.

Materials and Supplies Inventory.

All inventories are stated at lower of average cost or market. We perform an annual review of Materials and Supplies inventories, including a quarterly analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 2013 and at December 31, 2012.

Contingent Liabilities.

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

Pension and Other Postretirement Benefits.

We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 6.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us and thus paid by us, is based on our share of net periodic benefit cost.

Cash Flows from Operating Activities and Cash Equivalents.

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

XML

Consolidated Statement of Comprehensive Income (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement [Abstract]
Accumulated other comprehensive income reclassification for realized losses on interest rate hedges	$ 330	$ 220	$ 170

XML

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Regulatory Accounting

Regulatory Accounting.

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

Basis of Presentation

Basis of Presentation.

Williams’ acquisition of Transco Energy Company and its subsidiaries, including us, in 1995 was accounted for using the purchase method of accounting. Accordingly, an allocation of the purchase price was assigned to our assets and liabilities based on their estimated fair values. The purchase price allocation to us primarily consisted of a $1.5 billion allocation to property, plant and equipment and adjustments to deferred taxes based upon the book basis of the net assets recorded as a result of the acquisition. The amount allocated to property, plant and equipment is being depreciated on a straight-line basis over 40 years, the estimated useful lives of these assets at the date of acquisition, at approximately $35 million per year. At December 31, 2013, the remaining property, plant and equipment allocation was approximately $0.7 billion. Current FERC policy does not permit us to recover through rates amounts in excess of original cost.

We are a participant in WPZ’s cash management program. We make advances to and receive advances from WPZ. The 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.

Certain prior period amounts reported within Total operating costs and expenses in the Consolidated Statement of Comprehensive Income have been reclassified to conform to the current presentation. The effect of the correction increased Operation and maintenance costs $7.1 million and $6.8 million for the years ended December 31, 2012 and 2011, respectively, for the reclassification from Taxes-other than income taxes with no net impact on Total operating costs and expenses, Operating Income and Net Income.

Principles of Consolidation

Principles of Consolidation.

The consolidated financial statements include our accounts and the accounts of the subsidiaries we control. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments as of December 31, 2013 and December 31, 2012 consist of Cardinal Pipeline Company, LLC (Cardinal) with ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC (Pine Needle) with ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $11.5 million, $14.3 million, and $6.2 million in 2013, 2012 and 2011, respectively. Included in the distributions are $1.4 million return of capital from Pine Needle in 2013 and $11.3 million return of capital from Cardinal in 2012. We made capital contributions to Cardinal related to Cardinal’s expansion project totaling $5.8 million in 2012.

Use of Estimates

Use of Estimates.

The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4) impairment assessments of long-lived assets; 5) depreciation; and 6) asset retirement obligations.

Revenue Recognition

Revenue Recognition.

Revenues for transportation of gas under long-term firm agreements are recognized considering separately the reservation and commodity charges. Reservation revenues are recognized monthly over the term of the agreement regardless of the volume of natural gas transported. Commodity revenues from both firm and interruptible transportation are recognized in the period transportation services are provided based on volumes of natural gas physically delivered at the agreed upon delivery point. Revenues for the storage of gas under firm agreements are recognized considering separately the reservation, capacity, and injection and withdrawal charges. Reservation and capacity revenues are recognized monthly over the term of the agreement regardless of the volume of storage service actually utilized. Injection and withdrawal revenues are recognized in the period when volumes of natural gas are physically injected into or withdrawn from storage.

In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided for in our FERC tariff. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances (See Gas Imbalances in this Note).

As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel and other risks.

Environmental Matters

Environmental Matters.

We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their economic benefit and potential for rate recovery. We believe that 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.

Property, plant and equipment is recorded at cost. The carrying values of these assets are also based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. These estimates, assumptions and judgments reflect FERC regulations, as well as historical experience and expectations regarding future industry conditions and operations. 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. All other costs are expensed as incurred. Gains or losses from the ordinary sale or retirement of property, plant and equipment are credited or charged to accumulated depreciation; certain other gains or losses are recorded in operating income.

We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission facilities, production and gathering facilities and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2013, 2012 and 2011 are as follows:

Category of Property	2013 (1)	2012-2011
Gathering facilities	1.35% - 2.50%	0.18% - 1.66%
Storage facilities	2.10% -  2.25%	2.10% -  3.70%
Onshore transmission facilities	2.61%  -  5.00%	2.79%  -  5.71%
Offshore transmission facilities	1.20%  -  1.20%	1.01%  -  1.01%

(1) Changes in depreciation rates in 2013 due to placing into effect, subject to refund, the rates in Docket No. RP12-993 on March 1, 2013.

We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. Measurements of AROs include, 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 a market-risk premium. The ARO asset is depreciated in a manner consistent with the expected timing of the future abandonment of the underlying physical assets. We measure changes in the liability due to passage of time by applying an interest method of allocation. The depreciation of the ARO asset and accretion of the ARO liability are recognized as an increase to a regulatory asset, as management expects to recover such amounts in future rates. The regulatory asset is amortized commensurate with our collection of these costs in rates.

Impairment of Long-Lived Assets

Impairment of Long-lived Assets.

We evaluate the long lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. We apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

For assets identified to be disposed of in the future and considered held for sale in accordance with the ASC Property, Plant, and Equipment (Topic 360), we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.

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

Allowance for Funds Used During Construction

Allowance for Funds Used During Construction.

Allowance for funds used during construction (AFUDC) represents the estimated cost of borrowed and equity funds applicable to utility plant in process of construction and are included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. The FERC has prescribed a formula to be used in computing separate allowances for borrowed and equity AFUDC. The allowance for borrowed funds used during construction was $5.3 million, $6.0 million and $4.7 million, for 2013, 2012 and 2011, respectively. The allowance for equity funds was $13.3 million, $13.2 million, and $10.6 million, for 2013, 2012 and 2011, respectively.

Income Taxes

Income Taxes.

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

Accounts Receivable and Allowance for Doubtful Receivables

Accounts Receivable and Allowance for Doubtful Receivables.

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

Gas Imbalances

Gas Imbalances.

In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems which may deliver different quantities of gas on behalf of us than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables which are recovered or repaid in cash or through the receipt or delivery of gas in the future and are recorded in the accompanying Consolidated Balance Sheet. 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. Our tariff includes a method whereby most transportation imbalances are settled on a monthly basis. Each month a portion of the imbalances are not identified to specific parties and remain unsettled. These are generally identified to specific parties and settled in subsequent periods. We believe that amounts that remain unidentified to specific parties and unsettled at year end are valid balances that will be settled with no material adverse effect upon our financial position, results of operations or cash flows. Management has implemented a policy of continuing to carry any unidentified transportation and exchange imbalances on the books for a three-year period. At the end of the three year period a final assessment will be made of their continued validity. Absent a valid reason for maintaining the imbalance, any remaining balance will be recognized in income. Certain imbalances are being recovered or repaid in cash or through the receipt or delivery of gas upon agreement of the parties as to the allocation of the gas volumes, and as permitted by pipeline operating conditions. These imbalances have been classified as current assets and current liabilities at December 31, 2013 and 2012. We utilize the average cost method of accounting for gas imbalances.

Deferred Cash Out.

Most transportation imbalances are settled in cash on a monthly basis (cash out). We are required by our tariff to refund revenues received from the cash out of transportation imbalances in excess of costs incurred during the annual August through July reporting period. Revenues received in excess of costs incurred are deferred until refunded in accordance with the tariff.

Inventory

Gas Inventory.

We utilize the last-in, first-out (LIFO) method of accounting for inventory gas in storage. If inventories valued using the LIFO cost method were valued at current replacement cost, the amounts would increase by $1.3 million at December 31, 2013. At December 31, 2012, physical withdrawals from the Eminence Storage facility exceeded the customer nominations for withdrawals, resulting in a liability. The basis for determining current cost at the end of each year is the December monthly average gas price delivered to pipelines in Texas and Louisiana. We utilize the average cost method of accounting for gas available for customer nomination. Liquefied natural gas in storage is valued at original cost.

Materials and Supplies Inventory.

All inventories are stated at lower of average cost or market. We perform an annual review of Materials and Supplies inventories, including a quarterly analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 2013 and at December 31, 2012.

Contingent Liabilities

Contingent Liabilities.

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

Pension and Other Postretirement Benefits

Pension and Other Postretirement Benefits.

We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 6.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us and thus paid by us, is based on our share of net periodic benefit cost.

Cash Equivalents

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

XML

Document and Entity Information Document (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 26, 2014
Entity Information [Line Items]
Entity Registrant Name	Transcontinental Gas Pipe Line Company, LLC
Entity Central Index Key	0000099250
Document Type	10-K
Document Period End Date	Dec. 31, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		0
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float		$ 0

XML

Fair Value Measurements (Policies)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value of Methods.

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 short-term financial assets (advances to affiliates) that have variable interest rates - The carrying amount is a reasonable estimate of fair value due to the short maturity of those instruments.

ARO Trust investments - We deposit a portion of our collected rates, pursuant to the Docket No. RP06-569 rate case settlement, into the ARO Trust which is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market, are classified as available-for-sale, and are reported in Other Assets-Other in the Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 4 for more information regarding the ARO Trust.

Notes receivable - The disclosed fair value of our notes receivable is determined by an income approach which considers the underlying contract amounts and our assessment of our ability to recover these amounts. The current portion is reported in Trade and other receivables, and the noncurrent portion is reported in Other Assets-Other in the Consolidated Balance Sheet.

Long-term debt - The disclosed fair value of our long-term debt 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.

Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the year ended December 31, 2013 or 2012.

XML

Consolidated Balance Sheet (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current Assets:
Cash	$ 113	$ 185
Receivables:
Trade	137,808	116,847
Affiliates	2,601	2,656
Advances to affiliate	526,380	312,165
Other	10,364	8,928
Transportation and exchange gas receivables	6,757	2,876
Inventories:
Gas in storage, at original cost	790	812
Gas in storage, LIFO	1,056	0
Gas available for customer nomination, at average cost	8,553	8,600
Material and supplies, at lower of average cost or market	37,133	36,506
Regulatory assets	37,520	36,706
Other	13,451	14,342
Total current assets	782,526	540,623
Investments, at cost plus equity in undistributed earnings	50,262	55,603
Property, Plant and Equipment:
Natural gas transmission plant	8,867,626	8,506,189
Less-Accumulated depreciation and amortization	3,090,234	2,954,276
Total property, plant and equipment, net	5,777,392	5,551,913
Other Assets:
Regulatory assets	256,612	214,912
Other	57,785	47,764
Total other assets	314,397	262,676
Total assets	6,924,577	6,410,815
Payables:
Trade	106,096	107,795
Affiliates	28,268	32,006
Cash overdrafts	8,539	11,512
Transportation and exchange gas payables	3,599	3,513
Reserve for rate refunds	98,217	0
Accrued liabilities:
Property and other taxes	14,180	13,326
Interest	19,894	20,784
Regulatory liabilities	18,014	14,624
Customer advances	17,811	11,020
Asset retirement obligations	35,902	43,472
Other	47,462	36,107
Total current liabilities	397,982	294,159
Long-Term Debt	1,428,355	1,428,323
Other Long-Term Liabilities:
Asset retirement obligations	238,085	253,398
Regulatory liabilities	269,563	232,888
Other	5,307	5,339
Total other long-term liabilities	512,955	491,625
Contingent Liabilities and Commitments (Note 2)
Owner's Equity:
Member's capital	2,257,499	1,993,412
Retained earnings	2,328,044	2,204,018
Accumulated other comprehensive income (loss)	(258)	(722)
Total owner's equity	4,585,285	4,196,708
Total liabilities and owner's equity	$ 6,924,577	$ 6,410,815

XML

Benefit Plans (Notes)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Benefit Plans

BENEFIT PLANS.

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

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 $22.3 million, $20.3 million and $16.4 million for 2013, 2012, and 2011, respectively.

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 or December 31, 1995, if they were employees or retirees of Transco Energy Company and its subsidiaries. We recognized other postretirement benefit income of $4.2 million and $3.0 million for 2013 and 2011, respectively, and cost of $2.5 million for 2012.

We have been allowed by rate case settlements to collect or refund in future rates any differences between the actuarially determined costs and amounts currently being recovered in rates related to other postretirement benefits. Any differences between the annual actuarially determined cost and amounts currently being recovered in rates are recorded as an adjustment to expense and collected or refunded through future rate adjustments. The amounts of other postretirement benefits costs deferred as a regulatory liability at December 31, 2013 is $25.3 million and is comprised of $6.6 million being deferred for future rate treatment and $18.7 million being amortized over approximately an 8 year period per Docket No. RP12-993. At December 31, 2012, the amount of other postretirement benefit costs deferred consisted of a regulatory liability of $24.7 million deferred for future rate treatment, and a regulatory asset of $4.6 million which was being amortized over a 10 year period per Docket No. RP06-569. Effective March 1, 2013, the residual regulatory asset balance from the prior rate filing was netted against the accumulated regulatory liability.

Defined Contribution Plan.

Williams charged us compensation expense of $6.0 million in 2013, $7.2 million in 2012, and $6.9 million in 2011 for Williams’ company 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 non-management directors. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets achieved.

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

Total stock-based compensation expense for the years ended December 31, 2013, 2012 and 2011 was $3.0 million, $2.8 million and $2.4 million, respectively, excluding amounts allocated from WPZ and Williams.

XML

Fair Value Measurements (Notes)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS.

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities.

							Fair Value Measurements Using
	Carrying Amount			Fair Value			Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
							(Millions)
Assets (liabilities) at December 31, 2013:
Measured on a recurring basis:
ARO Trust investments	$	32.7		$	32.7		$	32.7	$	—		$	—
Additional disclosures:
Notes receivable	6.3			6.3			—		6.3			—
Long-term debt	(1,428.4		)	(1,512.9		)	—		(1,512.9		)	—
Assets (liabilities) at December 31, 2012:
Measured on a recurring basis:
ARO Trust investments	$	17.8		$	17.8		$	17.8	$	—		$	—
Additional disclosures:
Notes receivable	8.2			8.2			—		8.2			—
Long-term debt, including current portion	(1,428.3		)	(1,704.5		)	—		(1,704.5		)	—

Fair Value of Methods.

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 short-term financial assets (advances to affiliates) that have variable interest rates - The carrying amount is a reasonable estimate of fair value due to the short maturity of those instruments.

ARO Trust investments - We deposit a portion of our collected rates, pursuant to the Docket No. RP06-569 rate case settlement, into the ARO Trust which is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market, are classified as available-for-sale, and are reported in Other Assets-Other in the Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 4 for more information regarding the ARO Trust.

Notes receivable - The disclosed fair value of our notes receivable is determined by an income approach which considers the underlying contract amounts and our assessment of our ability to recover these amounts. The current portion is reported in Trade and other receivables, and the noncurrent portion is reported in Other Assets-Other in the Consolidated Balance Sheet.

Long-term debt - The disclosed fair value of our long-term debt 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.

Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the year ended December 31, 2013 or 2012.

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Transactions with Major Customers and Affiliates (Tables)

12 Months Ended

Dec. 31, 2013

Transactions with Major Customers and Affiliates [Abstract]

Schedule of revenue by major customers

Operating revenues received from our two major customers in 2013, 2012 and 2011 are as follows (in millions):

	2013		2012		2011
Public Service Enterprise Group	$	130.7	$	127.4	$	136.7
National Grid	88.5		93.5		98.2

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Depreciation rates

We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission facilities, production and gathering facilities and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2013, 2012 and 2011 are as follows:

Category of Property	2013 (1)	2012-2011
Gathering facilities	1.35% - 2.50%	0.18% - 1.66%
Storage facilities	2.10% -  2.25%	2.10% -  3.70%
Onshore transmission facilities	2.61%  -  5.00%	2.79%  -  5.71%
Offshore transmission facilities	1.20%  -  1.20%	1.01%  -  1.01%

(1) Changes in depreciation rates in 2013 due to placing into effect, subject to refund, the rates in Docket No. RP12-993 on March 1, 2013.

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Regulatory Assets and Liabilities (Notes)

12 Months Ended

Dec. 31, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

REGULATORY ASSETS AND LIABILITIES.

The regulatory assets and regulatory liabilities resulting from our application of the provisions of ASC Topic 980, Regulated Operations, included in the accompanying Consolidated Balance Sheet at December 31, 2013 and December 31, 2012 are as follows (in millions):

Regulatory Assets	2013		2012
Grossed-up deferred taxes on equity funds used during construction	$	80.6	$	83.5
Asset retirement obligations	128.5		125.1
Asset retirement costs - Eminence	68.2		—
Deferred taxes	8.1		9.1
Postretirement benefits other than pension	—		4.6
Fuel cost	0.7		29.3
Other	8.0		—
Total Regulatory Assets	$	294.1	$	251.6

Regulatory Liabilities	2013		2012
Negative salvage	$	241.7	$	203.8
Deferred cash out	1.6		6.2
Sentinel meter station depreciation	5.0		3.9
Postretirement benefits other than pension	25.3		24.7
Electric power cost	13.8		7.7
Other	0.2		1.2
Total Regulatory Liabilities	$	287.6	$	247.5

The significant regulatory assets and liabilities include:

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

Asset retirement obligations: Regulatory asset balance established to offset depreciation of the ARO asset and changes in the ARO liability due to the passage of time. The regulatory asset is being recovered through our rates, and is being amortized to expense consistent with the amounts collected in rates.

Asset retirement costs - Eminence: Regulatory asset balance associated with the Eminence Storage Field retirement costs. The regulatory asset is being recovered through our rates, and is being amortized to expense consistent with the amounts collected in rates (See Note 10).

Deferred taxes: Regulatory asset balance was established as a result of an increase to rate base deferred taxes due to an increase to the effective state income tax rate. The regulatory asset is being collected from rate payers over the remaining depreciable lives of the long-lived asset to which they relate.

Postretirement benefits: We recover the actuarially determined cost of postretirement benefits through rates that are set through periodic general rate filings. Any difference between the annual actuarially determined cost and the amount recovered in rates is recorded as a regulatory asset or liability to be collected or refunded through future rate adjustments. These amounts are not included in the rate base.

Fuel cost: This amount represents the 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/refunded in subsequent annual fuel tracker filing periods.

Electric power cost: This amount represents the difference between the electric power costs recovered from our customers and the electric power costs incurred in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual electric power tracker filing periods.

Negative salvage: Our rates include a component designed to recover certain future retirement costs for which we are not required to record an asset retirement obligation. We record a regulatory liability representing the cumulative residual amount of recoveries through rates, net of expenditures associated with these retirement costs.

Deferred cash out: This amount represents the deferral of gains or losses on the purchases and sales of gas imbalances with shippers. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual cash out filing periods.

Sentinel meter station depreciation: This amount reflects the incremental depreciation being recorded related to the meter station modifications made for three of the Sentinel shippers. These modifications will be recovered through a surcharge over a defined period of time as stated in the Sentinel FERC order. The incremental depreciation represents the difference between the FERC granted depreciation rate for such facilities in the last rate case as compared to the depreciation rates in the Sentinel order which are based on the contractual terms in the surcharge agreements. The incremental depreciation will be recorded through the end of the contractual term and then will be amortized.

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Transactions with Major Customers and Affiliates (Notes)

12 Months Ended

Dec. 31, 2013

Transactions with Major Customers and Affiliates [Abstract]

Transactions with Major Customers and Affiliates

TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES.

Major Customers.

Operating revenues received from our two major customers in 2013, 2012 and 2011 are as follows (in millions):

	2013		2012		2011
Public Service Enterprise Group	$	130.7	$	127.4	$	136.7
National Grid	88.5		93.5		98.2

Affiliates.

We are a participant in WPZ’s cash management program, and we make advances to and receive advances from WPZ. At December 31, 2013 and 2012, our advances to WPZ totaled approximately $526.4 million and $312.2 million, respectively. These advances are represented by demand notes and are classified as Current Assets in the accompanying Consolidated Balance Sheet. Advances are stated at the historical carrying amounts. Interest income is recognized when chargeable and collectability is reasonably assured. 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. At December 31, 2013, the interest rate was 0.01 percent.

On December 31, 2011, Williams completed the spin-off of its former exploration and production business, WPX, by means of a special stock dividend to its shareholders. Included in our operating revenues and cost of sales listed below for the year 2011 are amounts related to activity with WPX.

Included in Operating Revenues in the accompanying Consolidated Statement of Comprehensive Income for 2013, 2012 and 2011 are revenues received from affiliates of $16.3 million, $17.0 million, and $18.5 million, respectively. The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.

Included in Cost of natural gas sales in the accompanying Consolidated Statement of Comprehensive Income for 2013, 2012 and 2011 is purchased gas cost from affiliates of $6.9 million, $3.9 million, and $8.8 million, respectively. All gas purchases are made at market or contract prices.

We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams and its affiliates for all direct and indirect expenses incurred or payments made (including salary, bonus, incentive compensation and benefits) in connection with these services. Employees of Williams also provide general, administrative and management services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. We were billed $310.3 million, $320.1 million, and $278.6 million during 2013, 2012 and 2011, respectively, for these services. Such expenses are primarily included in Administrative and general and Operation and maintenance expenses in the accompanying Consolidated Statement of Comprehensive Income.

Pursuant to an operating agreement, we serve as contract operator on certain Williams Field Services (WFS) facilities. We recorded reductions in operating expenses for services provided to and reimbursed by WFS of $2.3 million, $4.5 million, and $6.4 million in 2013, 2012 and 2011, respectively, under terms of the operating agreement. In 2013, we received $3.6 million of reimbursements from WFS, related to a capital project. Pursuant to construction agreements, we received pre-payments from WFS of $2.3 million and $4.5 million during 2012 and 2011, respectively, associated with capital projects. We received reimbursements totaling $3.1 million from Williams Gas Processing – Gulf Coast Company, L.P. in 2012 associated with costs related to a transfer and assignment agreement.

We made equity distributions of $250 million, $246 million and $219 million during 2013, 2012 and 2011, respectively. In January 2014, an additional distribution of $112 million was declared and paid.

During 2013, 2012 and 2011, WPO made contributions totaling $264 million, $150 million and $115 million, respectively, to us to fund a portion of our expenditures for additions to property, plant and equipment. In January 2014, WPO made an additional $54 million contribution. During 2012, we received a non-cash contribution of $1.5 million from WPO. During 2011, we made a non-cash return of capital to WPO of approximately $0.5 million.

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Asset Retirement Obligations (Notes)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS.

The accrued obligations relate to underground storage caverns, offshore platforms, pipelines, and gas transmission facilities. At the end of the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any related surface equipment, to dismantle offshore platforms, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground.

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

	2013			2012
Beginning balance	$	296,870		$	302,768
Accretion	31,461			23,052
New obligations	2,225			2,556
Changes in estimates of existing obligations (1)	(27,628		)	10,895
Property dispositions/obligations settled	(28,941		)	(42,401		)
Ending balance	$	273,987		$	296,870

(1) The 2013 changes in estimates of existing obligations reflects decreases of $36 million, primarily due to a revision in the estimated remaining life of the assets, which is among several factors considered in the annual review process, including inflation rates, current estimates for removal cost and discount rates. These decreases are partially offset by an increase of $9 million related to changes in the timing and method of abandonment of our Eminence natural gas storage caverns that were associated with a leak in 2010. The 2012 changes in estimates of existing obligations is primarily due to an increase of $13 million related to changes in the timing and method of abandonment of our Eminence natural gas storage caverns that were associated with a leak in 2010.

We are entitled to collect in rates the amounts necessary to fund our ARO. All funds received for such retirements are deposited into an external trust account dedicated to funding our ARO. Under our current rate settlement our annual funding obligation is approximately $36.4 million, with installments to be deposited monthly.

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Other (Notes)

12 Months Ended

Dec. 31, 2013

Other Income and Expenses [Abstract]

Other

OTHER.

During 2012, we capitalized $8.7 million and $2.4 million, respectively, of project feasibility costs associated with the Rockaway Delivery Lateral Project and the Northeast Connector Project, which had been expensed in prior periods in Other expense, net, upon determining that the projects were probable of development. During 2011, we capitalized $10.1 million of project feasibility costs associated with the Northeast Supply Link Expansion Project, which had been expensed in prior periods in Other expense, net, upon determining that the project was probable of development. These costs will be included in the capital costs of the projects, which we believe are probable of recovery through the projects’ rates.

We detected a leak in an underground cavern at our Eminence Storage Field in Mississippi on December 28, 2010. During 2013, 2012 and 2011, we recorded $4.3 million, $2.5 million and $14.6 million, respectively, of charges to Operation and maintenance expenses primarily related to costs to ensure the safety of the surrounding area.

Due to the abandonment and retirement of four of the seven caverns at our Eminence Storage Field in 2013 and the expected recovery of such costs in our rates, we have reclassified $92 million of costs related to the Eminence ARO from Total property, plant and equipment, netto Regulatory assets (Eminence abandonment regulatory asset). Included inOther expense, net, for the year 2013, consistent with the Agreement in our Docket No. RP12-993 general rate case proceeding, is a charge of $11.5 million, related to the portion of the Eminence abandonment regulatory asset that will not be recovered in rates. We have also recognized income during 2013 of $16.1 million, related to insurance recoveries associated with this event.

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Regulatory Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Regulatory Assets [Line Items]
Regulatory assets	$ 294.1	$ 251.6
Regulatory Liabilities [Line Items]
Regulatory liabilities	287.6	247.5
Negative salvage
Regulatory Liabilities [Line Items]
Regulatory liabilities	241.7	203.8
Deferred cash out
Regulatory Liabilities [Line Items]
Regulatory liabilities	1.6	6.2
Sentinel meter station depreciation
Regulatory Liabilities [Line Items]
Regulatory liabilities	5.0	3.9
Postretirement benefits other than pension
Regulatory Liabilities [Line Items]
Regulatory liabilities	25.3	24.7
Electric power cost
Regulatory Liabilities [Line Items]
Regulatory liabilities	13.8	7.7
Other
Regulatory Liabilities [Line Items]
Regulatory liabilities	0.2	1.2
Grossed-up deferred taxes on equity funds used during construction
Regulatory Assets [Line Items]
Regulatory assets	80.6	83.5
Asset retirement obligations
Regulatory Assets [Line Items]
Regulatory assets	128.5	125.1
Asset retirement costs - Eminence
Regulatory Assets [Line Items]
Regulatory assets	68.2	0
Deferred taxes
Regulatory Assets [Line Items]
Regulatory assets	8.1	9.1
Postretirement benefits other than pension
Regulatory Assets [Line Items]
Regulatory assets	0	4.6
Fuel cost
Regulatory Assets [Line Items]
Regulatory assets	0.7	29.3
Other
Regulatory Assets [Line Items]
Regulatory assets	$ 8.0	$ 0

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Investments (Tables)

12 Months Ended

Dec. 31, 2013

Investments, Debt and Equity Securities [Abstract]

Investments

Investments in available-for-sale securities within the ARO Trust at fair value were as follows (in millions):

	December 31, 2013				December 31, 2012
	Amortized Cost Basis		Fair Value		Amortized Cost Basis		Fair Value
Cash and Money Market Funds	$	6.5	$	6.5	$	1.3	$	1.3
U.S. Equity Funds	8.0		11.1		5.4		7.4
International Equity Funds	4.2		4.9		3.4		3.8
Municipal Bond Funds	10.2		10.2		4.9		5.3
Total	$	28.9	$	32.7	$	15.0	$	17.8

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Summary of Significant Accounting Policies (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Corporate Structure and Control
Parent, total ownership percentage	64.00%
Parent, limited partner ownership percentage	62.00%
Parent, general partner ownership percentage	2.00%
Related Party Transaction [Line Items]
Operating revenues, related party	$ 16,300,000	$ 17,000,000	$ 18,500,000
Purchase Price Allocation
Purchase price allocation, gross	1,500,000,000
Purchase price allocation, property, plant and equipment, estimated useful lIfe	40 years
Purchase price allocation, depreciation	35,000,000
Purchase price allocation, remaining allocation	700,000,000
Schedule of Equity Method Investments [Line Items]
Equity method investment, distributions	11,500,000	14,300,000	6,200,000
Equity method investment, return of capital	1,438,000	11,327,000	1,925,000
Equity method investment, capital contributions	0	5,806,000	14,834,000
Capitalized Interest Costs, Including Allowance for Funds Used During Construction [Abstract]
Allowance for funds used during construction, borrowed	5,300,000	6,000,000	4,700,000
Allowance for funds used during construction, equity	13,299,000	13,222,000	10,588,000
Inventory Disclosure [Abstract]
Excess of replacement cost over LIFO cost	1,300,000
Gathering facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation rates	1.35%	0.18%	0.18%
Gathering facilities | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation rates	2.50%	1.66%	1.66%
Storage facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation rates	2.10%	2.10%	2.10%
Storage facilities | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation rates	2.25%	3.70%	3.70%
Onshore transmission facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation rates	2.61%	2.79%	2.79%
Onshore transmission facilities | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation rates	5.00%	5.71%	5.71%
Offshore transmission facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation rates	1.20%	1.01%	1.01%
Offshore transmission facilities | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation rates	1.20%	1.01%	1.01%
Cardinal Pipeline Company, LLC
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage	45.00%
Equity method investment, return of capital		11,300,000
Equity method investment, capital contributions		5,800,000
Pine Needle LNG Company, LLC
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage	35.00%
Equity method investment, return of capital	1,400,000
Operation and maintenance
Prior Period Reclassification Adjustment [Line Items]
Prior period reclassification adjustment	(7,100,000)	(6,800,000)
Taxes-other than income taxes
Prior Period Reclassification Adjustment [Line Items]
Prior period reclassification adjustment	7,100,000	6,800,000
Total operating costs and expenses
Prior Period Reclassification Adjustment [Line Items]
Prior period reclassification adjustment	0	0
Operating Income
Prior Period Reclassification Adjustment [Line Items]
Prior period reclassification adjustment	0	0
Net Income
Prior Period Reclassification Adjustment [Line Items]
Prior period reclassification adjustment	0	0
Common management [Member]
Related Party Transaction [Line Items]
Operating revenues, related party	$ 130,700,000

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Consolidated Statement of Owner's Equity Consolidated Statement of Owner's Equity (USD $) In Thousands	Total	Member's Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period at Dec. 31, 2010		$ 1,727,434	$ 2,117,153	$ 173
Cash contributions from parent	115,000	115,000
Non-cash contributions from parent		0
Non-cash return of capital		(546)
Net income	279,658		279,658
Cash distributions to parent	(219,000)		(219,000)
Equity interest in unrealized gain (loss) on interest rate hedge	(519)			(519)
Balance at end of period at Dec. 31, 2011	4,019,353	1,841,888	2,177,811	(346)
Cash contributions from parent	150,000	150,000
Non-cash contributions from parent		1,524
Non-cash return of capital		0
Net income	272,466		272,466
Cash distributions to parent	(246,259)		(246,259)
Equity interest in unrealized gain (loss) on interest rate hedge	(376)			(376)
Balance at end of period at Dec. 31, 2012	4,196,708	1,993,412	2,204,018	(722)
Cash contributions from parent	264,000	264,000
Non-cash contributions from parent		87
Non-cash return of capital		0
Net income	374,026		374,026
Cash distributions to parent	(250,000)		(250,000)
Equity interest in unrealized gain (loss) on interest rate hedge	464			464
Balance at end of period at Dec. 31, 2013	$ 4,585,285	$ 2,257,499	$ 2,328,044	$ (258)

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Investments (Notes)

12 Months Ended

Dec. 31, 2013

Investments, Debt and Equity Securities [Abstract]

Investments

INVESTMENTS.

Available-for-Sale Investments.

We are entitled to collect in rates the amounts necessary to fund our asset retirement obligations (ARO). We deposit monthly, into an external trust account, the revenues specifically designated for ARO. We established the ARO trust account (ARO Trust) on June 30, 2008. The ARO Trust carries a moderate risk portfolio. We measure the financial instruments held in our ARO Trust at fair value. However, in accordance with the ASC Topic 980, Regulated Operations, both realized and unrealized gains and losses of the ARO Trust are recorded as regulatory assets or liabilities.

Effective March 1, 2013, based on the Agreement in Docket No. RP12-993, the annual funding obligation is approximately $36.4 million, with installments paid monthly.

Investments in available-for-sale securities within the ARO Trust at fair value were as follows (in millions):

	December 31, 2013				December 31, 2012
	Amortized Cost Basis		Fair Value		Amortized Cost Basis		Fair Value
Cash and Money Market Funds	$	6.5	$	6.5	$	1.3	$	1.3
U.S. Equity Funds	8.0		11.1		5.4		7.4
International Equity Funds	4.2		4.9		3.4		3.8
Municipal Bond Funds	10.2		10.2		4.9		5.3
Total	$	28.9	$	32.7	$	15.0	$	17.8

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Contingent Liabilities and Commitments (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Site Contingency [Line Items]
Regulatory assets, total	$ 294,100,000	$ 251,600,000
Regulatory assets, current	37,520,000	36,706,000
Regulatory assets, noncurrent	256,612,000	214,912,000
Other Commitments [Abstract]
Commitments for construction and acquisition of property, plant, and equipment	368,000,000
Environmental assessment and remediation
Site Contingency [Line Items]
Environmental assessment and remediation costs, low estimate	6,000,000
Environmental assessment and remediation costs, high estimate	8,000,000
Accrued environmental assessment and remediation costs, total	4,100,000	3,300,000
Accrued environmental assessment and remediation costs, current	2,300,000	1,100,000
Accrued environmental assessment and remediation costs, noncurrent	1,800,000	2,200,000
Regulatory assets, total	1,800,000	0
Regulatory assets, current	1,200,000
Regulatory assets, noncurrent	600,000
Environmental assessment and remediation | Minimum
Site Contingency [Line Items]
Expected duration of environmental assessment and remediation spending	3 years
Environmental assessment and remediation | Maximum
Site Contingency [Line Items]
Expected duration of environmental assessment and remediation spending	5 years
Potentially responsible party at various Superfund and state waste disposal sites
Site Contingency [Line Items]
Environmental assessment and remediation costs, high estimate	$ 500,000

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Debt, Financing Arrangements and Leases (Tables)

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Long-term debt

At December 31, 2013 and 2012, long-term debt issues were outstanding as follows (in thousands):

	2013			2012
Debentures:
7.08% due 2026	$	7,500		$	7,500
7.25% due 2026	200,000			200,000
Total debentures	207,500			207,500
Notes:
6.4% due 2016	200,000			200,000
6.05% due 2018	250,000			250,000
5.4% due 2041	375,000			375,000
4.45% due 2042	400,000			400,000
Total notes	1,225,000			1,225,000
Total long-term debt issues	1,432,500			1,432,500
Unamortized debt premium and discount	(4,145		)	(4,177		)
Total long-term debt, less current maturities	$	1,428,355		$	1,428,323

Maturities of long-term debt

Aggregate minimum maturities (face value) applicable to long-term debt outstanding at December 31, 2013, for the next five years, are as follows (in thousands):

2016:     6.4% Notes	$200,000
2018:     6.05% Notes	$250,000

Leases [Abstract]

Future minimum lease payments

The future minimum lease payments under our various operating leases are as follows (in thousands):

2014	$	10,154
2015	10,025
2016	10,025
2017	9,971
2018	9,956
Thereafter	22,401
Total net minimum obligations	$	72,532