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

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

Commission File Number 1-7584

Transcontinental Gas Pipe Line Company, LLC

(Exact name of Registrant as specified in its charter)

Delaware (State or Other Jurisdiction of Incorporation or Organization)		74-1079400 (IRS Employer Identification No.)
2800 Post Oak Blvd., Houston, Texas (Address of principal executive offices)		77056 (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 not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o 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 o

     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 o No o

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) 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 definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check One):

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

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

     The registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.

 

 

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
FORM 10-K

TABLE OF CONTENTS

PART 1				PAGE
Item 1.		Business			4
Item 1A.		Risk Factors			9
Item 1B.		Unresolved Staff Comments			28
Item 2.		Properties			28
Item 3.		Legal Proceedings			28
PART II
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			28
Item 6.		Selected Financial Data (Omitted)			29
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			29
Item 7A.		Quantitative and Qualitative Disclosure About Market Risk			34
Item 8.		Financial Statements and Supplementary Data			35
Item 9.		Changes in and Disagreements With Accountants on Accounting and Financial Disclosures			67
Item 9A.		Controls and Procedures			67
Item 9B.		Other Information			68
PART III
Item 10.		Directors, Executive Officers and Corporate Governance (Omitted)			69
Item 11.		Executive Compensation (Omitted)			69
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters (Omitted)			69
Item 13.		Certain Relationships and Related Transactions, and Director Independence (Omitted)			69
Item 14.		Principal Accountant Fees and Services			69
PART IV
Item 15.		Exhibits and Financial Statement Schedules			70
EX-2.1
EX-3.1
EX-31.1
EX-31.2
EX-32

DEFINITIONS

We use the following gas measurements in this report:

     Mcf — means thousand cubic feet.

     MMcf — means million cubic feet.

     Bcf — means billion cubic feet.

     Tcf — means trillion cubic feet.

     Mcf/d — means thousand cubic feet per day.

     MMcf/d — means million cubic feet per day.

     Bcf/d — means billion cubic feet per day.

     MMBtu — means million British Thermal Units.

     TBtu — means trillion British Thermal Units.

     Dt — means dekatherm.

     Mdt — means thousand dekatherms.

     Mdt/d — means thousand dekatherms per day.

     MMdt — means million dekatherms.

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”.

     At December 31, 2010, Transco is owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams), and Williams holds an approximate 75 percent interest in WPZ, comprised of an approximate 73 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, 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 the Federal Energy Regulatory Commission (FERC) regulates.

     At December 31, 2010, our system had a mainline delivery capacity of approximately 4.9 MMdt of gas per day from production areas to our primary markets. Using our Leidy Line along with market-area storage and transportation capacity, we can deliver an additional 3.9 MMdt of gas per day for a system-wide delivery capacity total of approximately 8.8 MMdt of gas per day. The system is comprised of approximately 10,000 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 1.5 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, 2010, our customers had stored in our facilities approximately 154 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 11 southeast and Atlantic seaboard states including major metropolitan areas in Georgia, North Carolina, Washington, D.C., 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 2010 were Public Service Enterprise Group and National Grid, which accounted for approximately 11.0 percent and 9.7 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 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 2010 or are significant future pipeline projects for which we have customer commitments.

Mobile Bay South Expansion Project

     The Mobile Bay South Expansion Project involved the addition of compression at our Station 85 in Choctaw County, Alabama to allow us to provide firm transportation service southbound on the Mobile Bay line from Station 85 to various delivery points. In May 2009 we received approval from the FERC. The capital cost of the project was approximately $32 million. The project was placed into service in May 2010 and increased capacity by 254 Mdt/d.

Mobile Bay South II Expansion Project

     The Mobile Bay South II Expansion Project involves the addition of compression at our Station 85 in Choctaw County, Alabama and modifications to existing facilities at our Station 83 in Mobile County, Alabama to allow us to provide additional firm transportation service southbound on the Mobile Bay line from Station 85 to various delivery points. In July 2010 we received approval from the FERC. The capital cost of the project is estimated to be approximately $35 million, and it will increase capacity by 380 Mdt/d. We plan to place the project into service by May 2011.

85 North Expansion Project

     The 85 North Expansion Project involves an expansion of our existing natural gas transmission system from Station 85 in Choctaw County, Alabama to various delivery points as far north as North Carolina. In September 2009 we received approval from the FERC. The capital cost of the project is estimated to be approximately $236 million, and it will increase capacity by 309 Mdt/d. The first phase, for 90 Mdt/d, was placed into service in July 2010, and the second phase is expected to be placed into service in May 2011.

Pascagoula Expansion Project

     The Pascagoula Expansion Project involves the construction of a new pipeline to be jointly owned with Florida Gas Transmission connecting our existing Mobile Bay Lateral to the outlet pipeline of a proposed LNG import terminal in Mississippi. In July 2010 we received approval from the FERC. Our share of the capital cost of the project is estimated to be approximately $32 million. We plan to place the project into service in September 2011, and our share of its capacity will be 467 Mdt/d.

Mid-South Expansion Project

     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 October 2010 we filed an application with the FERC. The capital cost of the project is estimated to be approximately $219 million. We plan to place the project into service in phases in September 2012 and June 2013, and it will increase capacity by 225 Mdt/d.

Mid-Atlantic Connector Project

     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 November 2010 we filed an application with the FERC. The capital cost of the project is estimated to be approximately $55 million. We plan to place the project into service in November 2012, and it will increase capacity by 142 Mdt/d.

Rockaway Delivery Lateral Project

     The Rockaway Delivery Lateral Project involves the construction of a three-mile offshore lateral to National Grid’s distribution system in New York. We anticipate filing an application with the FERC in the fourth quarter of 2011. The capital cost of the project is estimated to be approximately $159 million. We plan to place the project into service as early as November 2013, and its capacity will be 647 Mdt/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 anticipate filing an application with the FERC in the fourth quarter of 2011. The capital cost of the project is estimated to be approximately $38 million. We plan to place the project into service as early as November 2013, and it will increase capacity by 100 Mdt/d.

Northeast Supply Link Project

     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. We anticipate filing an application with the FERC in the fourth quarter of 2011. The capital cost of the project is estimated to be approximately $341 million. We plan to place the project into service in November 2013, and it will increase capacity by 250 Mdt/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.

     On March 1, 2001, we submitted to the FERC a general rate filing (Docket No. RP01-245) to recover increased costs. On September 16, 2010, the FERC issued an order resolving the one remaining issue in this proceeding. The rates were effective from September 1, 2001 to March 1, 2007.

     On August 31, 2006, we submitted to the FERC a general rate filing (Docket No. RP06-569) 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 Transco’s 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. Two parties have requested rehearing of the FERC’s order. If the FERC were to reverse their opinion on rehearing, 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 FERC under the Natural Gas Act of 1938 (NGA), as amended, and under the Natural Gas Policy Act of 1978 (NGPA), as amended, and as such, our rates and charges for the transportation of natural gas in interstate commerce, the extension, enlargement or abandonment of jurisdictional facilities, and accounting, among other things, are subject to regulation. We hold certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of pipelines, facilities and properties under the NGA. The FERC’s Standards of Conduct govern the

relationship between natural gas transmission providers and marketing function employees as defined by the rule. The standards of conduct are intended to prevent natural gas transmission providers from preferentially benefiting gas marketing functions by requiring the employees of a transmission provider that perform transmission functions to function independently from gas marketing employees and by restricting the information that transmission providers may provide to gas marketing employees. Under the Energy Policy Act of 2005, the FERC is authorized to impose civil penalties of up to $1 million per day for each violation of its rules.

Environmental

     We are subject to the National Environmental Policy Act and federal, state and local laws and regulations relating to environmental quality control. Management believes that capital expenditures and operation and maintenance expenses required to meet applicable environmental standards and regulations are generally recoverable in rates. For these reasons, management believes that compliance with applicable environmental requirements is not likely to have a material effect upon our competitive position or earnings. (See Note 2 of Notes to Consolidated Financial Statements.)

Safety and Maintenance

     Pipeline Integrity Regulations We are also subject to the Natural Gas Pipeline Safety Act of 1968, as amended by Title I of the Pipeline Safety Act of 1979, and the Pipeline Safety Improvement Act of 2002 which regulate safety requirements in the design, construction, operation and maintenance of interstate gas transmission facilities.

     We have developed an Integrity Management Plan that we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for transmission pipelines that could affect high consequence areas in the event of pipeline failure. The Integrity Management Program includes a baseline assessment plan along with periodic reassessments to be completed within required timeframes. In meeting the integrity regulations, we have identified high consequence areas and developed our baseline assessment plan. We are on schedule to complete the required assessments within required timeframes. Currently, we estimate that the cost to complete the required initial assessments over the period of 2011 through 2012 and associated remediation will be primarily capital in nature and range between $80 million and $110 million. Ongoing periodic reassessments and initial assessments of any new high consequence areas will be completed within the timeframes required by the rule. 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 Transco Pipeline Services LLC (TPS), a Williams affiliate. As of January 31, 2011, TPS had 1,353 employees.

TRANSACTIONS WITH AFFILIATES

     We engage in transactions with WPZ, Williams and other Williams’ subsidiaries. (See Note 1 and Note 8 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,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will” or other similar expressions. These statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

	•		Amounts and nature of future capital expenditures;
	•		Expansion and growth of our business and operations;
	•		Financial condition and liquidity;
	•		Business strategy;
	•		Cash flow from operations or results of operations;
	•		Rate case filings; and
	•		Natural gas prices and demand.

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

	•		Availability of supplies (including the uncertainties inherent in assessing and estimating future natural gas reserves), market demand, volatility of prices, and the availability and cost of capital;
	•		Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);
	•		The strength and financial resources of our competitors;
	•		Development of alternative energy sources;
	•		The impact of operational and development hazards;
	•		Costs of, changes in, or the results of laws, government regulations (including climate change legislation), environmental liabilities, litigation, and rate proceedings;
	•		Our allocated costs for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates;
	•		Changes in maintenance and construction costs;
	•		Changes in the current geopolitical situation;
	•		Our exposure to the credit risks of our customers;
	•		Risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings, and the availability and cost of credit;
	•		Risks associated with future weather conditions;
	•		Acts of terrorism; and
	•		Additional risks described in our filings with the Securities and Exchange Commission (SEC).

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

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

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

RISK FACTORS

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

Risks Inherent to Our Industry and Business

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

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

	•		fires, blowouts, cratering, and explosions;
	•		uncontrolled releases of natural gas;
	•		pollution and other environmental risks;
	•		natural disasters;
	•		aging infrastructure and mechanical problems;
	•		damages to pipelines and pipeline blockages;
	•		operator error;
	•		damage inadvertently caused by third party activity, such as operation of construction equipment; and
	•		terrorist attacks or threatened attacks on our facilities or those of other energy companies.

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

with existing services. Such circumstances could adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business, financial condition, results of operations and cash flows.

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

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

     The principal elements of competition among natural gas transportation and storage assets are rates, terms of service, access to natural gas supplies, flexibility, and reliability. FERC’s policies promoting competition in natural gas markets are having the effect of increasing the natural gas transportation and storage options for our traditional customer base. Similarly, a highly-liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. As a result, pipeline capacity is being used more efficiently, and peaking and storage services are increasingly effective substitutes for annual pipeline capacity. As a result, we could experience some “turnback” of firm capacity as the primary terms of existing agreements expire. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we or our remaining customers may have to bear the costs associated with the turned back capacity. Increased competition could reduce the amount of transportation or storage capacity contracted on our system or, in cases where we do not have long-term fixed rate contracts, could force us to lower our transportation or storage rates. Competition could intensify the negative impact of factors that significantly decrease demand for natural gas or increase the price of natural gas in the markets served by our pipeline system, such as competing or alternative forms of energy, a regional or national recession or other adverse economic conditions, weather, higher fuel costs and taxes, or other governmental or regulatory actions that directly or indirectly increase the price of natural gas or limit the use of natural gas. Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. All of these competitive pressures could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

     We provide some services pursuant to long-term, fixed-price contracts. It is possible that costs to perform services under such contracts will exceed the revenues we collect for our services. Although most of the services are priced at cost-based rates that are subject to adjustment in rate cases, under 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 FERC regulated cost-based rate for that service. These “negotiated rate” contracts are not

generally subject to adjustment for increased costs that could be produced by inflation or other factors relating to the specific facilities being used to perform the services.

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

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

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

	•		the level of existing and new competition to deliver natural gas to our markets;
	•		the growth in demand for natural gas in our markets;
	•		whether the market will continue to support long-term firm contracts;
	•		whether our business strategy continues to be successful;
	•		the level of competition for natural gas supplies in the production basins serving us; and
	•		the effects of state regulation on customer contracting practices.

     Any failure to extend or replace a significant portion of our existing contracts may have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

     Although most of our pipeline system’s current capacity is fully contracted, FERC has taken certain actions to strengthen market forces in the natural gas pipeline industry that have led to increased competition throughout the industry. In a number of key markets, interstate pipelines are now facing competitive pressure from other major pipeline systems, enabling local distribution companies and end users to choose a transmission provider based on considerations other than location. Other entities could construct new pipelines or expand existing pipelines that could potentially serve the same markets as our pipeline system. Any such new pipelines could offer transportation services that are more desirable to shippers because of locations, facilities, or other factors. These new pipelines could charge rates or provide service to locations that would result in greater net profit for shippers and producers and thereby force us to lower the rates charged for service on our pipeline in order to extend our existing transportation service agreements or to attract new customers. We are aware of proposals by competitors to expand pipeline capacity in certain markets we also serve which, if the proposed projects proceed, could increase the competitive pressure upon us. There can be no assurance that we will be able to compete successfully against current and future competitors and any failure to do so could have a material adverse effect on our business and results of operations.

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

     Our business is dependent on the continued availability of natural gas production and reserves. The development of the additional natural gas reserves requires significant capital expenditures by others for exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to our pipeline system. Low prices for natural gas, regulatory limitations, including environmental regulations, or the lack of available capital for these projects could adversely affect the development and production of additional reserves, as well as gathering, storage, pipeline transportation, and import and export of natural gas supplies, adversely impacting our ability to fill the capacities of our transportation facilities.

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

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

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

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

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

     We could experience unexpected leaks or ruptures on our gas pipeline system, or be required by regulatory authorities to undertake modifications to our systems that could result in a material adverse impact on our business, financial condition and results of operations if the costs of maintaining or repairing our facilities exceed current expectations and the FERC or competition in our markets do not allow us to recover such costs in the rates we charge for our service.

Our business is subject to complex government regulations. The operation of our business might be adversely affected by changes in these regulations or in their interpretation or implementation, or the introduction of new laws or regulations applicable to our business or our customers.

     Existing regulations might be revised or reinterpreted, new laws and regulations might be adopted or become applicable to us, our facilities or our customers, and future changes in laws and regulations could have a material adverse effect on our financial condition and results of operations. For example, several ruptures on third party pipelines have occurred recently. In response, various legislative and regulatory reforms associated with pipeline safety and integrity have been proposed, including reforms that would require increased periodic inspections, installation of additional valves and other equipment operated by us and subjecting additional pipelines (including gathering facilities) to more stringent regulation. Such reforms, if adopted could significantly increase our costs.

We are subject to risks associated with climate change.

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

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

     The risk of substantial environmental costs and liabilities is inherent in natural gas transportation and storage operations, and we may incur substantial environmental costs and liabilities in the performance of these types of operations. Our operations are subject to extensive federal, state and local environmental laws and regulations governing environmental protection, the discharge of materials into the environment, and the security of chemical and industrial facilities. These laws include:

	•		Clean Air Act (CAA), and analogous state laws, which impose obligations related to air emissions;
	•		Clean Water Act (CWA), and analogous state laws, which regulate discharge of wastewaters from our facilities to state and federal waters;
	•		Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), and analogous state laws, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal; and
	•		Resource Conservation and Recovery Act (RCRA), and analogous state laws, which impose requirements for the handling and discharge of solid and hazardous waste from our facilities.

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

     There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to our handling of the products we transport and store, air emissions related to our operations, historical industry operations, waste disposal practices, and the prior use of flow meters containing mercury. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including CERCLA, RCRA and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of natural gas and wastes on, under, or from our properties and facilities. Private parties, including the owners of properties through which our pipeline passes and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites we operate are located near current or former third-party hydrocarbon storage and processing operations, and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.

     Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation of our facilities could be prevented or become subject to additional costs resulting in potentially material adverse consequences to our business, financial condition, results of operations and cash flows. We are also 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 addition, legislative and regulatory responses related to GHGs and climate change create the potential for financial risk. The U.S. Congress and certain states have for some time been considering various forms of legislation related to GHG emissions. There have also been international efforts seeking legally binding reductions in emissions of GHGs. In addition, increased public awareness and concern may result in more state, regional, and/or federal requirements to reduce or mitigate GHG emissions.

     Numerous states have announced or adopted programs to stabilize and reduce GHGs. In addition, on December 7, 2009, the EPA issued a final determination that six GHGs are a threat to public safety and welfare. This determination could lead to the direct regulation of GHG emissions in our industry under the EPA’s interpretation of its authority and obligations under the CAA. The recent actions of the EPA and the passage of any federal or state climate change laws or regulations could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations. 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.

     Certain environmental and other groups have suggested that additional laws and regulations may be needed to more closely regulate the hydraulic fracturing process commonly used in natural gas production. Legislation to further regulate hydraulic fracturing has been proposed in Congress and the U.S. Department of Interior has announced plans to formalize obligations for disclosure of chemicals associated with hydraulic fracturing on federal lands. In addition, some state and local authorities have considered or formalized new rules related to hydraulic fracturing and enacted moratoria on such activities. We cannot predict whether any additional federal, state or local legislation or regulation will be enacted in this area and if so, what its provisions would be. If additional levels of reporting, regulation and permitting were required, natural gas supplies and prices could be impacted and our operations could be adversely affected.

     We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change, and any new capital costs incurred to comply with such changes may not be recoverable under our regulatory rate structure or our customer contracts. In addition, new environmental laws and regulations might adversely affect our activities, including storage and transportation, as well as waste management and air emissions. For instance, federal and state agencies could impose additional safety requirements, any of which could affect our profitability.

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

     We rely on a limited number of customers for a significant portion of our revenues. Although some of these customers are subject to long-term contracts, we may be unable to

negotiate extensions or replacements of these contracts on favorable terms, if at all. For the year ended December 31, 2010, our two largest customers were Public Service Enterprise Group and National Grid. These customers accounted for approximately 11.0 percent and 9.7 percent, respectively, of our operating revenues for the year ended December 31, 2010. The loss of all, or even a portion of, the revenues from contracted volumes supplied by these customers, as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition, and cash flows, unless we are able to acquire comparable volumes from other sources.

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

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

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

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

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

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

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

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

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

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

     We currently maintain 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 us, our subsidiaries, and certain of our affiliates 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 property 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. Only certain offshore key-assets are covered for property damage and the resulting business interruption when loss is due to a named windstorm event and coverage for loss caused by a named windstorm is significantly sub-limited. All of our insurance is subject to deductibles. If a significant accident or event occurs for which we are not fully insured it could adversely affect our operations and financial condition.

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

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

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

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

	•		the ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on acceptable terms;
	•		the availability of skilled labor, equipment, and materials to complete expansion projects;
	•		potential changes in federal, state and local statutes and regulations, including environmental requirements, that prevent a project from proceeding or increase the anticipated cost of the project;
	•		impediments on our ability to acquire rights-of-way or land rights on a timely basis and on acceptable terms;
	•		the ability to construct projects within estimated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials, labor or other factors beyond our control, that may be material; and
	•		the ability to access capital markets to fund construction projects.

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

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

     Regulators and legislators continue to take a renewed look at accounting practices, financial disclosures, and companies’ relationships with their independent public accounting firms. It remains unclear what new laws or regulations will be adopted, and we cannot predict the ultimate impact that any such new laws or regulations could have. In addition, the Financial Accounting Standards Board (FASB), the SEC or FERC could enact new accounting standards or FERC orders that might impact how we are required to record revenues, expenses, assets, and liabilities. Any significant change in accounting standards or disclosure requirements could have a material adverse effect on our business, results of operations, and financial condition.

We do not operate all of our assets. This reliance on others to operate our assets and to provide other services could adversely affect our business and operating results.

     Williams and other third parties operate certain of our assets. We have a limited ability to control these operations and the associated costs. The success of these operations is therefore dependent upon a number of factors that are outside our control, including the competence and financial resources of the operators.

     We rely on Williams for certain services necessary for us to be able to conduct our business. Williams may outsource some or all of these services to third parties, and a failure of all or part of Williams’ relationships with its outsourcing providers could lead to delays in or interruptions of these services. Our reliance on Williams and others as operators and on Williams’ outsourcing relationships, and our limited ability to control certain costs could have a material adverse effect on our business, results of operations, and financial condition.

Risks Related to Strategy and Financing

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

     Our total outstanding long-term debt (including current portion) as of December 31, 2010, was $1,280.0 million.

     Our debt service obligations and restrictive covenants in our new credit facility entered into as part of Williams’ restructuring (New Credit Facility) and the indentures governing our senior unsecured notes could have important consequences. For example, they could:

	•		Make it more difficult for us to satisfy our obligations with respect to our senior unsecured notes and our other indebtedness, which could in turn result in an event of default on such other indebtedness or our outstanding notes;
	•		Impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, 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, acquisitions, general corporate purposes, or other purposes;
	•		Limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
	•		Place us at a competitive disadvantage compared to our competitors that have proportionately less debt.

     Our ability to repay, extend or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance, which will be affected by general economic, financial, competitive, legislative, regulatory, business and other factors, many of which are beyond our control. 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 meet our debt service obligations, 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.

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

Our debt agreements and Williams’ and WPZ’s public indentures contain financial and operating restrictions that may limit our access to credit and affect our ability to operate our business. In addition, our ability to obtain credit in the future will be affected by Williams’ and WPZ’s credit ratings.

     Our public indentures contain various covenants that, among other things, limit our ability to grant certain liens to support indebtedness, merge, or sell substantially all of our assets. In addition, our New Credit Facility contains certain financial covenants and restrictions on our ability and our subsidiaries’ ability to incur indebtedness, to consolidate or allow any material change in the nature of our business, enter into certain affiliate transactions, and make certain distributions during an event of default. These covenants could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us. Our ability to comply with these covenants may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our current assumptions about future economic conditions turn out to be incorrect or unexpected events occur, our ability to comply with these covenants may be significantly impaired.

     Williams’ and WPZ’s public indentures contain covenants that restrict their and our ability to incur liens to support indebtedness. These covenants could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us. Williams’ and WPZ’s ability to comply with the covenants contained in their respective debt instruments may be affected by events beyond our and their control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, Williams’ or WPZ’s ability to comply with these covenants may be negatively impacted.

     Our failure to comply with the covenants in our debt agreements could result in events of default. Upon the occurrence of such an event of default, the lenders could elect to declare all amounts outstanding under a particular facility to be immediately due and payable and terminate all commitments, if any, to extend further credit. Certain payment defaults or an acceleration under our public indentures or other material indebtedness could cause a cross-default or cross-acceleration of our New Credit Facility. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if our New Credit Facility cross-defaults, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding to us, we may not have sufficient liquidity to repay amounts outstanding under such debt agreements. 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.”

     Substantially all of Williams’ and WPZ’s operations are conducted through their respective subsidiaries. Williams’ and WPZ’s cash flows are substantially derived from loans, dividends and distributions paid to them by their respective subsidiaries. Williams’ and WPZ’s cash flows are typically utilized to service debt and pay dividends or distributions on their equity, with the

balance, if any, reinvested in their respective subsidiaries as loans or contributions to capital. Due to our relationship with 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 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 would likely also result in a downgrading of our credit rating. A downgrading of a Williams or WPZ credit rating could limit our ability to obtain financing in the future upon favorable terms, if at all.

Future disruptions in the global credit markets may make debt markets less accessible, create a shortage in the availability of credit and lead to credit market volatility.

     In 2008, global credit markets experienced a shortage in overall liquidity and a resulting disruption in the availability of credit. Future disruptions in the global financial marketplace, including the bankruptcy or restructuring of financial institutions, could make debt markets inaccessible and adversely affect the availability of credit already arranged and the availability and cost of credit in the future. We have availability under the New 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.

Adverse economic conditions could negatively affect our results of operations.

     A slowdown in the economy has the potential to negatively impact our business in many ways. Included among these potential negative impacts are reduced demand and lower prices for our products and services, increased difficulty in collecting amounts owed to us by our customers and a reduction in our credit ratings (either due to tighter rating standards or the negative impacts described above), which could result in reducing our access to credit markets, raising the cost of such access or requiring us, WPZ, or Williams to provide additional collateral to third parties.

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

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

	•		economic downturns;
	•		deteriorating capital market conditions;
	•		declining market prices for natural gas;
	•		terrorist attacks or threatened attacks on our facilities or those of other energy companies;
	•		the overall health of the energy industry, including the bankruptcy or insolvency of other companies.

     Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the ratings agencies and no assurance can be given that we will maintain our current credit ratings.

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

     As of December 31, 2010, we are a wholly-owned subsidiary of WPZ, approximately 75 percent of whose limited and general partnership interests are owned by Williams. 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.

Risks Related to Regulations That Affect Our Industry

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

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

	•		transportation of natural gas in interstate commerce;
	•		rates, operating terms, and conditions of service, including initiation and discontinuation of services;
	•		the types of services we may offer to our customers;
	•		certification and construction of new facilities;
	•		acquisition, extension, disposition, or abandonment of 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.

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

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

     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 rates, terms and conditions for our interstate pipeline and storage services are set forth in our FERC-approved tariff. Pursuant to the terms of our most recent rate settlement agreement, we must file a new rate case no later than August 31, 2012. Any successful complaint or protest against our rates could have an adverse impact on our revenues associated with providing transportation and storage services.

We could be subject to penalties and fines if we fail to comply with FERC regulations.

     Our transportation and storage operations are regulated by FERC. Should we fail to comply with all applicable FERC administered statutes, rules, regulations, and orders, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1,000,000 per day for each violation. Any material penalties or fines imposed by FERC could have a material adverse impact on our business, financial condition, results of operations, and cash flows.

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

     There is a risk that rates set by FERC in our future rate cases will be inadequate to recover increases in operating costs or to sustain an adequate return on capital investments. There is also

the risk that higher rates will cause our customers to look for alternative ways to transport their natural gas.

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

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

Legal and regulatory proceedings and investigations relating to the energy industry have adversely affected our business and may continue to do so.

     Public and regulatory scrutiny of the energy industry has resulted in increased regulation being either proposed or implemented. Such scrutiny has also resulted in various inquiries, investigations and court proceedings. 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 and proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our revenues and net income or increase our operating costs in other ways. Current legal proceedings or other matters against us including environmental matters, suits, regulatory appeals and similar matters might result in adverse decisions against us. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.

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

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

     In our business, institutional knowledge resides with employees who have many years of service. As these employees reach retirement age, 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.

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

     Some studies indicate a high failure rate of outsourcing relationships. Although Williams has taken steps to build a cooperative and mutually beneficial relationship with its outsourcing providers and to closely monitor their performance, a deterioration in the timeliness or quality of the services performed by the outsourcing providers or a failure of all or part of these relationships could lead to loss of institutional knowledge and interruption of services necessary for us to be able to conduct our business. The expiration of such agreements or the transition of services between providers could lead to similar losses of institutional knowledge or disruptions.

     Certain of our accounting, information technology, application development, and help desk services are currently provided by Williams’ outsourcing provider from service centers outside of the United States. The economic and political conditions in certain countries from which Williams’ outsourcing providers may provide services to us present similar risks of business operations located outside of the United States, including risks of interruption of business, war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, that are greater than in the United States.

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

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

Risks Related to Weather, Other Natural Phenomena and Business Disruption

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

     Our assets and operations can be adversely affected by hurricanes, floods, earthquakes, landslides, tornadoes and other natural phenomena and weather conditions, including extreme temperatures, making it more difficult for us to realize the historic rates of return associated with these assets and operations. Insurance may be inadequate, and in some instances, we have been unable to obtain insurance on commercially reasonable terms or insurance has not been available at all. A significant disruption in operations or a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations, and financial condition.

     Our customers’ energy needs vary with weather conditions. To the extent weather conditions are affected by climate change or demand is impacted by regulations associated with climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes, leading either to increased investment or decreased revenues.

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

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

Item 1B. Unresolved Staff Comments

     None.

Item 2. Properties

     Our gas pipeline facilities are generally owned in fee. However, a substantial portion of such facilities 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. The 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”.

PART II

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

     At December 31, 2009, we were an indirect wholly-owned subsidiary of Williams. At December 31, 2010, we are an indirect wholly-owned subsidiary of WPZ, and Williams holds an approximate 75 percent interest in WPZ, comprised of an approximate 73 percent limited partner interest and all of WPZ’s 2 percent general partner interest.

     On January 29, 2010, our Management Committee authorized and we paid a $50 million cash distribution. In association with Williams’ restructuring of its gas pipeline and domestic midstream businesses, our Management Committee authorized a cash distribution of approximately $153.8 million on January 31, 2010, which we paid on February 16, 2010. On October 29, 2010, we paid a $130 million cash distribution.

     On October 29, 2010, we received a $75 million capital contribution from Williams Partners Operating LLC.

     During 2009, our Management Committee authorized, and we paid, cash distributions of $145 million.

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.

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 Balance Sheet and included in the Statement of Income for the period in which the discontinuance of regulatory accounting treatment occurs. The aggregate amounts of regulatory assets reflected in the Balance Sheet are $247.4 million and $272.7 million at December 31, 2010 and 2009, respectively. The aggregate amounts of

regulatory liabilities reflected in the Balance Sheet are $117.8 million and $75.9 million at December 31, 2010 and 2009, respectively. A summary of regulatory assets and liabilities is included in Note 10 of Notes to Consolidated Financial Statements.

Contingent liabilities

     We record liabilities for estimated loss contingencies when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are reflected in income in the period in which new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates, and advice of legal counsel or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, our assumptions and estimates of these liabilities may change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period.

Results of Operations

Analysis of Financial Results

     This analysis discusses financial results of our operations for the years 2010 and 2009. 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.

2010 COMPARED TO 2009

     Operating Income and Net Income Operating income for 2010 was $339.5 million compared to $335.3 million for 2009. Net income for 2010 was $270.8 million compared to $280.4 million for 2009. The increase in Operating income of $4.2 million (1.3 percent) was due primarily to higher Natural gas transportation revenues, partially offset by a decrease in Other revenues and an increase in operating costs and expenses as discussed below. The decrease in Net income of $9.6 million (3.4 percent) was mostly attributable to higher net deductions in Other (Income) and Other Deductions, partially offset by the increase in Operating income.

     Sales Revenues We make jurisdictional merchant gas sales pursuant to a blanket sales certificate issued by the FERC.

     Through an agency agreement, Williams Gas Marketing, Inc. (WGM) manages our long-term purchase agreements and our remaining jurisdictional merchant gas sales, which excludes our cash out sales in settlement of gas imbalances. The long-term purchase agreements managed by WGM remain in our name, as do the corresponding sales of such purchased gas. Therefore, we continue to record natural gas sales revenues and the related accounts receivable and cost of natural gas sales and the related accounts payable for the jurisdictional merchant sales that are managed by WGM. WGM receives all margins associated with jurisdictional merchant gas sales business and, as our agent, assumes all market and credit risk associated with our jurisdictional merchant gas sales. Consequently, our merchant gas sales service has no impact on our operating income or results of operations.

     In addition to our merchant gas sales, we also 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 $2.6 million (2.7 percent) to $99.3 million for 2010 when compared to 2009. These sales were offset in our costs of natural gas sold and therefore had no impact on our operating income or results of operations.

     Transportation Revenues Operating Revenues: Natural gas transportation for 2010 was $930.7 million compared to $891.8 million for 2009. The $38.9 million (4.4 percent) increase was primarily due to higher transportation reservation revenues of $31.7 million, ($22.3 million from Phase II of our Sentinel expansion placed in service in November 2009, $5.9 million from Mobile Bay South placed in service in May 2010 and $3.5 million from Phase I of our 85 North expansion placed in service in July 2010), and $18.8 million higher revenues which recover electric power and certain other costs. Electric power and certain other costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations. These increases were partially offset by a decrease of $8.6 million from lower commodity revenues resulting from lower IT Feeder revenue due to displacement of volumes as a result of new interconnects and declining production attached to our IT Feeder laterals.

     Storage Revenues Operating Revenues: Natural gas storage for 2010 were comparable to 2009.

     Other Revenues Operating Revenues: Other decreased $20.6 million (80.2 percent) to $5.1 million for 2010, when compared to 2009, primarily due to a $19.5 million decrease in revenues from the Park and Loan Service. The Park and Loan Service has decreased as a result of lower gas volumes parked and/or loaned by customers in 2010 due to unfavorable pricing conditions in the market.

     Operating Costs and Expenses Excluding the Cost of natural gas sales which is directly offset in revenues, our operating expenses were approximately $15.9 million (2.2 percent) higher than 2009. This increase was primarily attributable to:

•

An increase in Cost of natural gas transportation of $15.2 million (89.4 percent) primarily resulting from a $15.3 million increase due to higher electric power costs in 2010 and a $2.5 million gas loss at our Eminence storage facility in 2010, partially offset by a $1.4 million decrease due to lower gas supply expense resulting from a settlement of an imbalance recorded in 2009 and $1.0 million lower fuel expenses in 2010 resulting from less favorable pricing differentials between cost recoveries at spot prices and expenses recognized at weighted average prices in 2009. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations;

	•		An increase in Taxes – other than income taxes of $10.3 million (28.8 percent) primarily resulting from state franchise tax refunds for prior years recorded in 2009, and;
	•		An increase in Depreciation and amortization costs of $5.8 million (2.4 percent) primarily resulting from an increase in the depreciation base due to additional plant placed in-service.
	•		Partially offset by a decrease in Operation and maintenance expense of $10.0 million (4.0 percent), primarily resulting from a decrease in labor related costs, primarily lower incentive compensation costs and pension costs; and
	•		A decrease in Administrative and general expense of $6.8 million (4.1 percent), primarily resulting from a decrease in labor related costs, primarily lower incentive compensation costs and pension costs and lower corporate overhead charges.

     Other (Income) and Other Deductions Other (income) and other deductions in 2010 were $68.3 million compared to $55.2 million in 2009. The $13.1 million increase (23.7 percent) was primarily due to lower Interest income – affiliates of $16.9 million due to overall lower average advances to affiliates in 2010 as compared to the same period in 2009 and a lower interest rate on the note advance to WPZ, partially offset by a decrease in Miscellaneous other income, net of $4.2 million, primarily due to lower non-operating reimbursement gross-up in 2010.

Eminence Storage Field Leak

     On December 26, 2010, we detected a leak in one of the seven underground natural gas storage caverns at our Eminence Storage Field in Covington County, Mississippi. Since that time, we have reduced the pressure in the cavern by safely venting and flaring gas. Due to the leak at this cavern and damage to the well at an adjacent cavern, both caverns are out of service. To date, the event has not affected our performance of our obligations under our service agreements with our customers.

     As a result of these occurrences, we have determined that these two caverns cannot be returned to service. Therefore, we intend to file an application seeking authorization from the FERC to abandon those caverns. We estimate the cost to abandon these caverns will be approximately $31 million, which is expected to be spent in 2011.

     In the Fourth Quarter of 2010, we recorded a charge of $4.5 million related to this event. Of this, $2.5 million represents an estimate of gas lost net of insurance recovery, and $2.0 million related to costs to ensure the safety of the surrounding environment net of insurance recovery.

     We will also incur additional maintenance costs in 2011 related to this event, which we estimate to be in the range of $10 to $15 million. However, these estimates are subject to change as work progresses and additional information becomes known.

Effects of Inflation

     We generally have experienced increased costs due to the effect of inflation on the cost of labor, materials and supplies, and property, plant and equipment. A portion of the increased labor and materials and supplies cost can directly affect income through increased operation and

maintenance expenses. The cumulative impact of inflation over a number of years has resulted in increased costs for current replacement of productive facilities. The majority of our property, plant and equipment and 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 agreement 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 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, and we expect to do so in 2011.

     Prior to Williams’ restructuring of its business, we participated in Williams’ unsecured $1.5 billion revolving credit facility (Credit Facility) with a maturity date of May 1, 2012. As part of the restructuring, we were removed as borrowers under the Credit Facility and on February 17, 2010, we entered into a new $1.75 billion three-year senior unsecured revolving credit facility (New Credit Facility) with WPZ and Northwest Pipeline GP (Northwest), as co-borrowers, and Citibank N.A., as administrative agent, and certain other lenders named therein. The full amount of the New Credit Facility is available to WPZ, and may be increased by up to an additional $250 million. We may borrow up to $400 million under the New Credit Facility to the extent not otherwise utilized by WPZ and Northwest. At December 31, 2010, the full $400 million under the New Credit Facility was available. See Note 3 of Notes to Consolidated Financial Statements for further discussion of the New Credit Facility.

     Through a wholly-owned subsidiary, we hold a 35 percent interest in Pine Needle. In March 1998 Pine Needle executed an interest rate swap agreement (March 1998 swap) with a bank, which swapped floating rate debt into 6.58 percent fixed rate debt. In August 2010, Pine Needle settled the March 1998 swap and executed a new interest rate swap agreement (August 2010 swap) which swapped floating rate debt into 4.175 percent fixed rate debt. The March 1998 swap and the August 2010 swap 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 is recognized in other comprehensive income. For the years ended December 31, 2010 and 2009, our cumulative equity interest on Pine Needle’s hedge was a $0.2 million unrealized gain and a $0.7 million unrealized loss, respectively. The August 2010 interest rate swap is settled quarterly and terminates in August 2015.

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 2011 capital expenditures will be between $510 million to $560 million. Of this total, $440 million to $490 million is considered nondiscretionary due to legal, regulatory, and/or contractual requirements.

     Property, plant and equipment additions were $377 million, $303 million and $206 million for 2010, 2009 and 2008, respectively. The $74 million increase in 2010 compared to 2009 is primarily related to the maintenance of existing facilities, including pipeline safety expenditures, and expansion projects, primarily the 85 North and Mid South projects.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

     At December 31, 2010, 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, 2010. The table presents principal cash flows and weighted-average interest rates by expected maturity dates.

December 31, 2010		Expected Maturity Date
		2011				2012				2013				2014
						(Dollars in millions)
Long-term debt:
Fixed rate		$	300			$	325			$	—			$	—
Interest rate			7.26	%			7.03	%			6.53	%			6.53	%
December 31, 2010		Expected Maturity Date
		2015				Thereafter				Total				Fair Value
						(Dollars in millions)
Long term debt
Fixed rate		$	—			$	658			$	1,283			$	1,433
Interest rate			6.53	%			6.98	%

Item 8. Financial Statements and Supplementary Data

			Page
Management’s Annual Report on Internal Control over Financial Reporting			36
Report of Independent Registered Public Accounting Firm			37
Consolidated Statement of Income			38
Consolidated Balance Sheet			39-40
Consolidated Statement of Owner’s Equity			41
Consolidated Statement of Comprehensive Income			42
Consolidated Statement of Cash Flows			43-44
Notes to Consolidated Financial Statements			45-65

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING

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

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

     Under the supervision and with the participation of our management, including our Senior Vice President and our Vice President and Treasurer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2010, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment, we concluded that, as of December 31, 2010, 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.

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, 2010 and 2009, and the related consolidated statements of income, comprehensive income, owner’s equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

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

     In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Transcontinental Gas Pipe Line Company, LLC at December 31, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

		/S/ ERNST & YOUNG LLP

Houston, Texas
February 24, 2011

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)

		Years Ended December 31,
		2010				2009				2008
Operating Revenues:
Natural gas sales		$	99,346			$	96,713			$	150,056
Natural gas transportation			930,704				891,841				897,569
Natural gas storage			146,820				144,978				145,711
Other			5,125				25,741				7,876
Total operating revenues			1,181,995				1,159,273				1,201,212
Operating Costs and Expenses:
Cost of natural gas sales			99,346				96,682				150,129
Cost of natural gas transportation			32,231				16,959				7,043
Operation and maintenance			239,643				249,625				232,390
Administrative and general			158,006				164,831				153,271
Depreciation and amortization			252,049				246,247				233,516
Taxes — other than income taxes			46,064				35,809				46,221
Other (income) expense, net			15,189				13,816				(14,882	)
Total operating costs and expenses			842,528				823,969				807,688
Operating Income			339,467				335,304				393,524
Other (Income) and Other Deductions:
Interest expense - affiliate			353				387				437
- other			94,620				93,993				95,802
Interest income  - affiliates			(2,231	)			(19,090	)			(21,967	)
- other			(882	)			(1,185	)			(631	)
Allowance for equity and borrowed funds used during construction (AFUDC)			(12,349	)			(11,982	)			(6,324	)
Equity in earnings of unconsolidated affiliates			(5,805	)			(5,757	)			(6,064	)
Miscellaneous other income, net			(5,375	)			(1,171	)			(5,908	)
Total other (income) and other deductions			68,331				55,195				55,345
Income before Income Taxes			271,136				280,109				338,179
(Benefit) Provision for Income Taxes			360				(248	)			(960,706	)
Net Income		$	270,776			$	280,357			$	1,298,885

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)

		December 31,
		2010				2009
ASSETS
Current Assets:
Cash		$	148			$	108
Receivables:
Trade less allowance of $406 ($413 in 2009)			96,699				98,794
Affiliates			4,921				5,132
Advances to affiliate			108,838				—
Other			13,735				18,354
Transportation and exchange gas receivables			2,417				7,250
Inventories:
Gas in storage, at LIFO			8,767				6,802
Gas in storage, at original cost			802				794
Gas available for customer nomination, at average cost			43,631				196
Materials and supplies, at lower of average cost or market			32,225				31,372
Regulatory assets			48,444				75,016
Other			13,132				11,792
Total current assets			373,759				255,610
Investments, at cost plus equity in undistributed earnings			43,753				45,488
Property, Plant and Equipment:
Natural gas transmission plant			7,674,366				7,354,805
Less - Accumulated depreciation and amortization			2,650,133				2,474,680
Total property, plant and equipment, net			5,024,233				4,880,125
Other Assets:
Regulatory assets			198,921				197,676
Other			59,223				42,884
Total other assets			258,144				240,560
		$	5,699,889			$	5,421,783

(continued)

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)

		December 31,
		2010				2009
LIABILITIES AND OWNER’S EQUITY
Current Liabilities:
Payables:
Trade		$	73,121			$	70,400
Affiliates			18,769				24,409
Cash overdrafts			19,526				18,380
Transportation and exchange gas payables			1,646				1,434
Accrued liabilities:
State income and other taxes			9,052				766
Interest			26,061				26,061
Regulatory liabilities			2,253				3,852
Employee benefits			—				32,599
Customer advances			24,976				35,637
Other			56,783				17,311
Reserve for rate refunds			—				564
Current maturities of long-term debt			299,932				—
Total current liabilities			532,119				231,413
Long-Term Debt			980,018				1,278,770
Other Long-Term Liabilities:
Asset retirement obligations			220,644				229,401
Regulatory liabilities			115,563				72,021
Accrued employee benefits			—				6,476
Other			6,785				9,145
Total other long-term liabilities			342,992				317,043
Contingent liabilities and commitments (Note 2)
Owner’s Equity:
Member’s capital			1,727,434				1,652,434
Loans to parent			—				(237,526	)
Retained earnings			2,117,153				2,180,367
Accumulated other comprehensive income (loss)			173				(718	)
Total owner’s equity			3,844,760				3,594,557
		$	5,699,889			$	5,421,783

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED STATEMENT OF OWNER’S EQUITY
(Thousands of Dollars)

		Years Ended December 31,
		2010				2009				2008
Common Stock:
Balance at beginning and end of period		$	—			$	—			$	—
Premium on Capital Stock and Other Paid-in Capital:
Balance at beginning of period			—				—				1,652,430
Conversion to LLC			—				—				(1,652,430	)
Balance at end of period			—				—				—
Owner’s capital:
Balance at beginning of period			1,652,434				1,652,430				—
Contribution			75,000				4				—
Conversion to LLC			—				—				1,652,430
Balance at end of period			1,727,434				1,652,434				1,652,430
Loans to Parent:
Balance at beginning of period			(237,526	)			(42,206	)			(30,690	)
Loans to parent, net			237,526				(195,320	)			(11,516	)
Balance at end of period			—				(237,526	)			(42,206	)
Retained Earnings:
Balance at beginning of period			2,180,367				2,045,010				966,125
Add (deduct):
Net income			270,776				280,357				1,298,885
Cash dividends and distributions			(333,990	)			(145,000	)			(220,000	)
Balance at end of period			2,117,153				2,180,367				2,045,010
Accumulated Other Comprehensive Income (Loss):
Balance at beginning of period			(718	)			(1,087	)			(399	)
Interest Rate Hedge:
Add (deduct):
Net gain (loss), net of tax of $169 in 2008			891				369				(259	)
Elimination of deferred income taxes			—				—				(429	)
Balance at end of period			173				(718	)			(1,087	)
Total Owner’s Equity		$	3,844,760			$	3,594,557			$	3,654,147

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(Thousands of Dollars)

		Years Ended December 31,
		2010				2009				2008
Net Income		$	270,776			$	280,357			$	1,298,885
Equity interest in unrealized gain (loss) on interest rate hedge, net taxes of $169 in 2008			891				369				(259	)
Elimination of deferred income taxes			—				—				(429	)
Total Comprehensive Income		$	271,667			$	280,726			$	1,298,197

See accompanying notes.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)

		Years Ended December 31,
		2010				2009				2008
Cash flows from operating activities:
Net income		$	270,776			$	280,357			$	1,298,885
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			252,131				247,543				235,106
Deferred income taxes			—				—				(998,382	)
(Gain)/loss on sale of property, plant and equipment			—				(2	)			(11,905	)
Allowance for equity funds used during construction (Equity AFUDC)			(8,539	)			(7,835	)			(4,374	)
Changes in operating assets and liabilities:
Receivables - affiliates			1,702				(3,192	)			2,880
- other			6,714				(25,759	)			29,615
Transportation and exchange gas receivable			4,833				3,399				75
Inventories			(46,261	)			36,667				(32,771	)
Payables      - affiliates			(23,485	)			(7,461	)			(2,971	)
- other			15,888				(51,868	)			(111,154	)
Transportation and exchange gas payable			212				(1,417	)			(4,394	)
Accrued liabilities			405				(24,587	)			(57,096	)
Reserve for rate refunds			(564	)			(13,798	)			60,902
Other, net			42,661				28,812				(76,129	)
Net cash provided by operating activities			516,473				460,859				328,287
Cash flows from financing activities:
Additions to long-term debt			—				—				424,332
Retirement of long-term debt			—				—				(350,000	)
Debt issue costs			—				—				(2,100	)
Cash dividends and distributions			(333,791	)			(145,000	)			(220,000	)
Change in cash overdrafts			1,146				4,101				2,056
Capital contribution from parent			75,000				—				—
Net cash used in financing activities			(257,645	)			(140,899	)			(145,712	)

(continued)

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)

		Years Ended December 31,
		2010				2009				2008
Cash flows from investing activities:
Property, plant and equipment additions, net of equity AFUDC*			(376,502	)			(303,458	)			(205,717	)
Disposal of property, plant and equipment, net			6,969				(12,391	)			10,875
Advances to affiliates, net			126,999				189				27,666
Advances to others, net			229				282				270
Purchase of ARO trust investments			(46,952	)			(45,604	)			(31,056	)
Proceeds from sale of ARO trust investments			31,001				40,713				14,143
Other, net			(532	)			(11	)			1,553
Net cash used in investing activities			(258,788	)			(320,280	)			(182,266	)
Net increase (decrease) in cash			40				(320	)			309
Cash at beginning of period			108				428				119
Cash at end of period		$	148			$	108			$	428
*   Increase to property, plant and equipment		$	(352,674	)		$	(328,190	)		$	(203,575	)
Changes in related accounts payable and accrued liabilities			(23,828	)			24,732				(2,142	)
Property, plant and equipment additions, net of equity AFUDC		$	(376,502	)		$	(303,458	)		$	(205,717	)
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest (exclusive of amount capitalized)		$	89,342			$	89,150			$	99,073
Income taxes paid			31				21,457				79,002
Income tax refunds received			—				(455	)			(570	)
Supplemental disclosures of significant non-cash transactions:
Loans to parent reclassified to equity			—				(195,320	)			(11,516	)

See accompanying notes.

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.”

     At December 31, 2010, Transco is owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams), and Williams holds an approximate 75 percent interest in WPZ, comprised of an approximate 73 percent limited partner interest and all of WPZ’s 2 percent general partner interest.

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, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and the 11 southeast and Atlantic seaboard states mentioned above, including major metropolitan areas in Georgia, Washington D.C., 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 $36 million per year. At December 31, 2010, the remaining property, plant and equipment allocation was approximately $0.9 billion. Current FERC policy does not permit us to recover through rates amounts in excess of original cost.

     Prior to Williams’ restructuring in February 2010, we were a participant in Williams’ cash management program whereby we made advances to and received advances from Williams. The advances were represented by demand notes. The interest rate on these intercompany demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter. In accordance with Williams’ restructuring of its business, our participation in the Williams’ cash management program terminated on February 28, 2010. On January 31, 2010, our Management Committee authorized a cash distribution which included the amount of our outstanding advances and associated interest receivable which was paid February 16, 2010. Accordingly, the note advance balance and related interest outstanding on December 31, 2009 were reflected as a reduction of our owner’s equity as the advances were not available to us as working capital.

     Subsequent to Williams’ restructuring, we became a participant in WPZ’s cash management program on March 1, 2010. 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.

     Through an agency agreement, Williams Gas Marketing, Inc. (WGM), our affiliate, manages our remaining jurisdictional merchant gas sales, which excludes our cash out sales in settlement of gas imbalances. The long-term purchase agreements managed by WGM remain in our name, as do the corresponding sales of such purchased gas. Therefore, we continue to record natural gas sales revenues and the related accounts receivable and cost of natural gas sales and the related accounts payable for the jurisdictional merchant sales that are managed by WGM. WGM receives all margins associated with jurisdictional merchant gas sales business and assumes all market and credit risk associated with our jurisdictional merchant gas sales. Consequently, our merchant gas sales service has no impact on our operating income or results of operations.

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, 2010 and December 31, 2009 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 $8.4 million, $1.4 million, and $5.9 million in 2010, 2009 and 2008, respectively. In addition, distributions totaling $3.7 million were received by Williams Gas Pipeline Company, LLC (WGP) during the first nine months of 2009 in which it owned the equity method investments.

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 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 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. 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 using the straight-line method at FERC prescribed rates, including negative salvage (cost of removal) for transmission facilities, production and gathering facilities and LNG storage facilities. Depreciation of general plant is provided on a group basis at straight-line rates. Included in our depreciation rates is a negative salvage component that we currently collect in rates. Depreciation rates used for major regulated gas plant facilities at December 31, 2010, 2009 and 2008 are as follows:

Category of Property
Gathering facilities			0.01% - 0.91	%
Storage facilities			0.40% - 3.30	%
Onshore transmission facilities			0.69% - 5.00	%
Offshore transmission facilities			0.01% - 1.00	%

     We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO). Measurements of asset retirement obligations 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. We had no impairments during the years ended December 31, 2010, 2009 and 2008.

     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.

Accounting for Repair and Maintenance Costs

     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.

Allowance for Funds 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 $3.8 million, $4.2 million and $2.0 million, for 2010, 2009 and 2008, respectively. The allowance for equity funds was $8.5 million, $7.8 million, and $4.4 million, for 2010, 2009 and 2008, respectively.

Accounting for Income Taxes

     Williams and its wholly-owned subsidiaries file a consolidated federal income tax return. It is Williams’ policy to charge or credit its taxable subsidiaries with an amount equivalent to their federal income tax expense or benefit computed as if each subsidiary had filed a separate return. Prior to Williams’ restructuring of its business on February 17, 2010, we were an indirectly wholly-owned subsidiary of Williams. We converted from a corporation to a limited liability company on December 31, 2008.

     We use the assets and liability method of accounting for income taxes, as required by the ASC Income Taxes (Topic 740), which requires, among other things, provisions for all temporary differences between the financial basis and the tax basis in our assets and liabilities and adjustments to the existing deferred tax balances for changes in tax rates. Following our conversion from a corporation to a limited liability company on December 31, 2008, we are no longer subject to income tax, except for the Texas Gross Margin tax. (See Note 6 of Notes to the Consolidated Financial Statements.)

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, 2010 and 2009. 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 decrease by $2.2 million at December 31, 2010 and $1.1 million at December 31, 2009. 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.

Reserves for Inventory Obsolescence

     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, 2010 and at December 31, 2009.

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.

     Certain reclassifications from non-operating income to operating income, related to oil and gas royalties of $1.7 million for 2009 have been made to the 2009 period to conform to the 2010 presentation.

2. CONTINGENT LIABILITIES AND COMMITMENTS

Rate Matters

     On March 1, 2001, we submitted to the FERC a general rate filing (Docket No. RP01-245) to recover increased costs. On September 16, 2010, the FERC issued an order resolving the one remaining issue in this proceeding. The rates were effective from September 1, 2001 to March 1, 2007.

     On August 31, 2006, we submitted to the FERC a general rate filing (Docket No. RP06-569) 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. Two parties have requested rehearing of the FERC’s order. If the FERC were to reverse their opinion on rehearing, we believe any refunds would not be material to our results of operations.

Environmental Matters

     Since 1989, 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 $7 million to $9 million (including both expense and capital expenditures), measured on an undiscounted basis, and will be spent over the next four to six 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, 2010, we had a balance of approximately $3.8 million for the expense portion of these estimated costs recorded in current liabilities ($0.8 million) and other long-term liabilities ($3.0 million) in the accompanying Consolidated Balance Sheet. At December 31, 2009, we had

a balance of approximately $4.7 million for the expense portion of these estimated costs recorded in current liabilities ($0.8 million) and other long-term liabilities ($3.9 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 $7 million to $9 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 $7 million to $9 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.

     We are also subject to the Federal Clean Air Act (Act) and to the Federal Clean Air Act Amendments of 1990 (1990 Amendments), which added significantly to the existing requirements established by the Act. Pursuant to requirements of the 1990 Amendments and EPA rules designed to mitigate the migration of ground-level ozone (NOx), we are planning installation of air pollution controls on existing sources at certain facilities in order to reduce NOx emissions. For many of these facilities, we are developing more cost effective and innovative compressor engine control designs.

     In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. Within two years, the EPA was expected to designate new eight-hour ozone non-attainment areas. 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. The EPA currently anticipates finalization of the new ground-level ozone standard in the third quarter of 2011. Designation of new eight-hour ozone non-attainment areas are expected to result in additional federal and state regulatory actions that will likely impact our operations and increase the cost of additions to property, plant and equipment. We are unable at this time 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. The emission control additions required to comply with the hazardous air pollutant regulations are estimated to include costs in the range of $25 million to $30 million through 2013, the compliance date.

     Furthermore, the EPA promulgated the Greenhouse Gas (GHG) Mandatory Reporting Rule on October 30, 2009, which requires facilities that emit 25,000 metric tons or more carbon

dioxide (CO₂) equivalent per year from stationary fossil-fuel combustion sources to report GHG emissions to the EPA annually beginning March 31, 2011 for calendar year 2010. On November 30, 2010, the EPA issued additional regulations that expand the scope of the Mandatory Reporting Rule to include fugitive and vented greenhouse gas emissions effective January 1, 2011. Facilities that emit 25,000 metric tons or more CO₂ equivalent per year from stationary fossil-fuel combustion and fugitive/vented sources combined will be required to report GHG combustion and fugitive/vented emissions to the EPA annually beginning March 31, 2012 for calendar year 2011. Compliance with this reporting obligation is estimated to cost $7 million to $9 million over the next four to five years.

     In February 2010, the EPA promulgated a final rule establishing a new one-hour nitrogen dioxide (NO₂) NAAQS. The effective date of the new NO₂ standard was April 12, 2010. This new standard is subject to numerous challenges in the federal court. We are unable at this time to estimate the cost of additions that may be required to meet this new 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, these estimated costs of environmental assessment and remediation, less amounts collected, have been recorded as regulatory assets in Current Assets, in the accompanying Consolidated Balance Sheet. We had no environmental related regulatory assets at December 31, 2010. At December 31, 2009, we had recorded approximately $0.6 million of environmental related regulatory assets.

     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 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. In July 2009, the EPA requested additional information pertaining to these compressor stations; in August 2009, we submitted the requested information. In August, 2010, the EPA requested, and we provided, similar information for a compressor station in Maryland.

Safety Matters

     Pipeline Integrity Regulations We have developed an Integrity Management Plan that we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for transmission pipelines that could affect high consequence areas in the event of pipeline failure. The Integrity Management Program includes a baseline assessment plan along with periodic reassessments to be completed within required timeframes. In meeting the integrity regulations, we have identified high consequence areas and developed our baseline assessment plan. We are on schedule to complete the required assessments within required timeframes. Currently, we estimate that the cost to complete the required initial assessments over the period of 2011 through 2012 and associated remediation will be primarily capital in nature and range between $80 million and $110 million. Ongoing periodic reassessments and initial assessments of any new high consequence areas will be completed within the timeframes required by the rule. 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.

     Appomattox, Virginia Pipeline Rupture On September 14, 2008, we experienced a rupture of our 30-inch diameter mainline B pipeline near Appomattox, Virginia. The rupture resulted in an explosion and fire which caused several minor injuries and property damage to several nearby residences. On September 25, 2008, PHMSA issued a Corrective Action Order (CAO) which required that we operate three of our mainlines in a portion of Virginia at reduced operating pressure and prescribed various remedial actions. After completion of some of the remedial actions PHMSA approved our requests to restore the affected pipelines to normal operating pressure. By letter dated April 29, 2010, PHMSA confirmed that the remaining remedial actions should be completed by December 31, 2010. This deadline was subsequently extended by PHMSA to September 30, 2011. In 2009, PHMSA proposed, and we paid, a $1.0 million civil penalty related to this matter.

Other Matters

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

Summary

     Litigation, arbitration, regulatory matters, environmental matters and safety matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements will not have a material adverse effect upon our future liquidity or financial position.

Other Commitments

     Commitments for construction and gas purchases We have commitments for construction and acquisition of property, plant and equipment of approximately $103 million at December 31, 2010. We have commitments for gas purchases of approximately $36 million at December 31, 2010. See Note 1 of Notes to Consolidated Financial Statements for our discussion of our agency agreement with WGM.

3. DEBT, FINANCING ARRANGEMENTS AND LEASES

Long-Term Debt

     At December 31, 2010 and 2009, long-term debt issues were outstanding as follows (in thousands):

		2010				2009
Debentures:
7.08% due 2026		$	7,500			$	7,500
7.25% due 2026			200,000				200,000
Total debentures			207,500				207,500
Notes:
7% due 2011			300,000				300,000
8.875% due 2012			325,000				325,000
6.4% due 2016			200,000				200,000
6.05% due 2018			250,000				250,000
Total notes			1,075,000				1,075,000
Total long-term debt issues			1,282,500				1,282,500
Unamortized debt premium and discount			(2,482	)			(3,730	)
Current maturities			(300,000	)			—
Total long-term debt, less current maturities		$	980,018			$	1,278,770

     Aggregate minimum maturities (face value) applicable to long-term debt outstanding at December 31, 2010, for the next five years, are as follows (in thousands):

2011:		7% Notes				$	300,000
2012:		8.875% Notes				$	325,000

     There are no maturities applicable to long-term debt outstanding for the years 2013, 2014 and 2015.

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

Restrictive Debt Covenants

     At December 31, 2010, 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.

Revolving Credit and Letter of Credit Facility

     Prior to Williams’ restructuring of its business, we participated in Williams’ unsecured $1.5 billion revolving credit facility (Credit Facility) with a maturity date of May 1, 2012. As part of the restructuring, we were removed as borrowers under the Credit Facility and on February 17, 2010, we entered into a new $1.75 billion three-year senior unsecured revolving credit facility (New Credit Facility) with WPZ and Northwest Pipeline GP (Northwest), as co-borrowers, and

Citibank N.A., as administrative agent, and certain other lenders named therein. The full amount of the New Credit Facility is available to WPZ, and may be increased by up to an additional $250 million. We may borrow up to $400 million under the New Credit Facility to the extent not otherwise utilized by WPZ and Northwest. At December 31, 2010, the full $400 million under the New Credit Facility was available.

     Interest on borrowings under the New Credit Facility is payable at rates per annum equal to, at the option of the borrower: (1) a fluctuating base rate equal to Citibank, N.A.’s adjusted base rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. The adjusted base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) Citibank N.A.’s publicly announced base rate, and (iii) one-month LIBOR plus 1.0 percent. WPZ pays a commitment fee (currently 0.5 percent) based on the unused portion of the New Credit Facility. The application margin and the commitment fee are determined by reference to a pricing schedule based on a borrower’s senior unsecured debt ratings.

     The New Credit Facility contains various covenants that limit, among other things, the borrower’s and its respective subsidiaries’ ability to incur indebtedness, grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, and allow any material change in the nature of their business.

     Under the New Credit Facility, WPZ is required to maintain a ratio of debt to Earnings Before Income Taxes, Interest, Depreciation and Amortization (EBITDA) (each as defined in the New Credit Facility, with EBITDA measured on a rolling four-quarter basis) of no greater than 5.00 to 1.00 for itself and its consolidated subsidiaries. For us and our consolidated subsidiaries, the ratio of debt to capitalization (defined as net worth plus debt) is not permitted to be greater than 55 percent. Each of the above ratios is tested at the end of each fiscal quarter (with the first full year measured on an annualized basis). At December 31, 2010, we are in compliance with these covenants.

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

Lease Obligations

     On October 23, 2003, we entered into a lease agreement for space in the Williams Tower in Houston, Texas (Williams Tower). The lease term ran through March 31, 2014.

     On January 6, 2011, we entered into an amendment to our current lease agreement that extends the lease through March 31, 2021 and added additional space effective April 2011, which was previously subleased from an affiliate.

     The future minimum lease payments under our various operating leases, including the Williams Tower leases are as follows (in thousands):

		Operating Leases
		Williams Tower				Other Leases				Total
2011		$	7,678			$	179			$	7,857
2012			7,978				131				8,109
2013			7,972				119				8,091
2014			8,087				122				8,209
2015			8,126				—				8,126
Thereafter			42,661				—				42,661
Total net minimum obligations		$	82,502			$	551			$	83,053

     Our lease expense was $9.3 million in 2010, $9.8 million in 2009, and $9.1 million in 2008.

4. FAIR VALUE MEASUREMENTS

     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 ASC Topic 980, Regulated Operations, both realized and unrealized gains and losses of the ARO Trust are recorded as regulatory assets or liabilities.

     The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:

•

Level 1 – Quoted prices in active markets for identical assets or liabilities that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 consists of financial instruments in our ARO Trust totaling $40.4 million and $22.0 million at December 31, 2010 and 2009, respectively. These financial instruments include the following (in millions):

		December 31,
		2010				2009
Money market funds		$	1.6			$	0.2
U.S. equity funds			17.4				10.5
International equity funds			6.0				3.0
Municipal bond funds			15.4				8.3
Total		$	40.4			$	22.0

•

Level 2 – Inputs are other than quoted prices in active markets included in Level 1, that are either directly or indirectly observable. These inputs are either directly observable in

			the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. We do not have any Level 2 measurements.
	•		Level 3 – Includes inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. We do not have any Level 3 measurements.

     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 in or out of Level 1 and Level 2 occurred during the periods ended December 31, 2010 and 2009.

5. BENEFIT PLANS

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

Pension and Other Postretirement Benefit Plans

     Williams has noncontributory defined benefit pension plans that provide pension benefits for its eligible employees. Pension expense charged to us by Williams was $16.7 million, $20.3 million and $5.2 million for 2010, 2009, and 2008, 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 $4.5 million for 2010 and other postretirement benefit expense of $3.3 million and $3.6 million for 2009 and 2008, respectively.

     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 revenues or expense and collected or refunded through future rate adjustments. The amounts of postretirement benefits costs deferred as a regulatory liability at December 31, 2010 and 2009 are $14.0 million and $4.7 million, respectively, and are expected to be refunded through future rates. The amounts of postretirement benefits costs deferred as regulatory assets at December 31, 2010 and 2009 are $6.8 million and $7.9 million, respectively, and are currently being recovered over a ten year period beginning March 1, 2007.

Defined Contribution Plan

     Williams charged us compensation expense of $6.7 million in 2010 and 2009, and $6.3 million in 2008 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 nonmanagement directors. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets achieved.

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

     Total stock-based compensation expense, included in administrative and general expenses, for the years ended December 31, 2010, 2009 and 2008 was $3.1 million, $3.2 million and $2.4 million, respectively, excluding amounts allocated from WGP and Williams.

Business Restructuring

     In connection with Williams’ restructuring, all of our employees were transferred to another Williams’ affiliate effective as of February 16, 2010. This affiliate provides the personnel to perform the services previously conducted by our employees and charges us for these services according to a new service agreement. (See Note 8.)

6. INCOME TAXES

     Following is a summary of the provision (benefit) for income taxes for 2010, 2009 and 2008 (in thousands):

		2010				2009				2008
Current:
Federal		$	—			$	—			$	36,286
State			360				(248	)			1,390
			360				(248	)			37,676
Deferred:
Federal			—				—				(867,400	)
State			—				—				(130,982	)
			—				—				(998,382	)
Provision (benefit) for income taxes		$	360			$	(248	)		$	(960,706	)

     Following is a reconciliation of the provision (benefit) for income taxes at the federal statutory rate to the provision (benefit) for income taxes (in thousands):

		2010				2009				2008
Provision at statutory rate		$	94,898			$	98,038			$	118,362
Increases (decreases) in taxes resulting from:											—
Income from operations not taxed as a LLC			(94,898	)			(98,038	)			—
State income taxes (net of federal benefit)			360				(248	)			7,703
Conversion from corporation to LLC			—				—				(1,086,771	)
Provision (benefit) for income taxes		$	360			$	(248	)		$	(960,706	)

     Following our conversion on December 31, 2008 to a single member limited liability company, for which an election was made to be treated as a disregarded entity, we are no longer subject to income tax, except for the Texas Gross Margin tax. Subsequent to the conversion, all deferred income taxes were eliminated.

     In 2010, the state income taxes reflect a current provision for the Texas Gross Margin tax.

     We have no deferred income tax liabilities or deferred tax assets at December 31, 2010, or 2009.

     Total interest and penalties recognized as a component of income tax expense were insignificant in 2010, 2009, and 2008.

7. FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

     The carrying amount and estimated fair values of our financial instruments as of December 31, 2010 and 2009 are as follows (in thousands):

		Carrying Amount								Fair Value
		2010				2009				2010				2009
Financial assets:
Cash		$	148			$	108			$	148			$	108
Short-term financial assets			108,838				—				108,838				—
ARO Trust Investments			40,413				21,977				40,413				21,977
Long-term financial assets			144				373				144				373
Financial liabilities:
Long-term debt, including current portion			1,279,950				1,278,770				1,432,866				1,417,300

     For cash and short-term financial assets (third-party notes receivable and 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. For long-term financial assets (long-term receivables), the carrying amount is a reasonable estimate of fair value because the interest rate is a variable rate.

     The fair value of our publicly traded long-term debt is valued using year-end traded bond market prices. At December 31, 2010 and 2009, 100 percent of long-term debt was publicly traded. As a participant in WPZ’s cash management program, we make advances to and receive advances from WPZ. Advances are stated at the historical carrying amounts. At December 31, 2010, the advances due us by WPZ totaled $108.8 million and are reflected in current assets. Prior to Williams’ restructuring in February 2010, we were a participant in Williams’ cash management program whereby we made advances to and received advances from Williams. At December 31, 2009, the advances due us by Williams totaled $186.1 million and are reflected as a reduction of owner’s equity. Advances to affiliates are due on demand. However, in accordance with the restructuring of Williams’ business in February 2010, our Management Committee authorized a distribution which included an amount equivalent to our advance balance and related interest outstanding. Accordingly, our advance balance and related interest receivable at December 31, 2009 were reflected as a reduction of owner’s equity as the advances were not be available to us as working capital.

8. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES

Major Customers

     In 2010, operating revenues received from Public Service Enterprise Group, National Grid, and Piedmont Natural Gas Company, our three major customers, were $130.0 million, $115.1 million, and $85.6 million, respectively. In 2009, operating revenues received from National Grid, Public Service Enterprise Group, and Piedmont Natural Gas Company, our three major customers, were $120.3 million, $111.4 million, and $78.4 million, respectively. In 2008, operating revenues received from Public Service Enterprise Group, National Grid and Piedmont

Natural Gas Company, our three major customers, were $132.3 million, $120.4 million, and $81.8 million, respectively.

Affiliates

     Prior to Williams’ restructuring in February 2010, we were a participant in Williams’ cash management program, whereby we made advances to and received advances from Williams. The interest rate on these intercompany demand notes was based upon the weighted average cost of William’s debt outstanding at the end of each quarter. In accordance with Williams’ restructuring of its business, our participation in the Williams’ cash management program terminated on February 28, 2010. We received interest income from advances to Williams of $2.2 million, $19.1 million, and $22.0 million during 2010, 2009 and 2008, respectively.

     Subsequent to Williams’ restructuring in February 2010, we became a participant in WPZ’s cash management program, and we make advances to and receive advances from WPZ. At December 31, 2010, the advances due us by WPZ totaled approximately $108.8 million. 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. At December 31, 2010, the interest rate was 0.06 percent. The interest income from these advances to WPZ was minimal during 2010.

     Included in our operating revenues for 2010, 2009 and 2008 are revenues received from affiliates of $23.4 million, $21.9 million, and $35.8 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.

     Through an agency agreement with us, WGM manages our jurisdictional merchant gas sales. The agency fees billed by WGM for 2008 through 2010 were not significant.

     Included in our cost of sales for 2010, 2009 and 2008 is purchased gas cost from affiliates, excluding the agency fees discussed above, of $4.8 million, $5.2 million, and $14.3 million, respectively. All gas purchases are made at market or contract prices.

     We have long-term gas purchase contracts containing variable prices that are currently in the range of estimated market prices. Our estimated purchase commitments under such gas purchase contracts are not material to our total gas purchases. Furthermore, through the agency agreement with us, WGM has assumed management of our merchant sales service and, as our agent, is at risk for any above-spot-market gas costs that it may incur.

     Williams has a policy of charging subsidiary companies for management services provided by the parent company and other affiliated companies. Included in our administrative and general expenses for 2010, 2009 and 2008 were $54.7 million, $53.3 million, and $46.5 million, respectively, for such corporate expenses charged by Williams and other affiliated companies. Management considers the cost of these services to be reasonable.

     Pursuant to an operating agreement, we serve as contract operator on certain Williams Field Services (WFS) facilities. Transco recorded reductions in operating expenses for services provided to and reimbursed by WFS of $8.7 million, $9.1 million, and $7.8 million in 2010, 2009 and 2008 respectively, under terms of the operating agreement. Pursuant to construction agreements, Transco received pre-payments from WFS of $8.1 million for the modification of

the North Markham lateral and tie-in to WFS, and $5.4 million for construction of the Lower Demunds meter station.

     We made equity distributions of $334 million, $145 million and $55 million during 2010, 2009 and the fourth quarter of 2008, respectively. We declared and paid cash dividends of $165 million during the first three quarters of 2008.

     In October 2010, Williams Partners Operating, LLC made a $75 million contribution to us to fund a portion of our expenditures for additions to property, plant and equipment.

     As part of Williams’ restructuring of its business, effective as of February 16, 2010, all of our former employees were transferred to our affiliate, Transco Pipeline Services LLC (TPS), a Delaware limited liability company. On February 17, 2010, we entered into an administrative services agreement pursuant to which TPS will provide personnel, facilities, goods and equipment not otherwise provided by us that are necessary to operate our business. In return, we will reimburse TPS for all direct and indirect expenses it incurs or payments it makes (including salary, bonus, incentive compensation and benefits) in connection with these services.

9. ASSET RETIREMENT OBLIGATIONS

     We record an asset and a liability equal to the present value of each expected future ARO. The ARO asset is depreciated in a manner consistent with the expected 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 rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and is offset by a regulatory asset. The regulatory asset is being recovered through our rates, and is being amortized to expense consistent with the amounts collected in rates.

     The asset retirement obligation at December 31, 2010 and 2009 was $251.6 million and $229.4 million, respectively. During 2010 and 2009, our overall asset retirement obligation changed as follows (in thousands):

		2010				2009
Beginning balance		$	229,401			$	229,360
Accretion			16,542				16,148
New obligations			53				317
Changes in estimates of existing obligations (1)			15,747				(6,592	)
Property dispositions			(10,099	)			(9,832	)
Ending balance		$	251,644			$	229,401

     At December 31, 2010, we had a balance of $31.0 million related to ARO recorded in Current Accrued Liabilities-Other. At December 31, 2009, the current portion of our ARO liability was not material.

     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.

     We are entitled to collect in rates the amounts necessary to fund our ARO. All funds received for such retirements shall be deposited into an external trust account dedicated to funding our ARO. On June 30, 2008, we deposited the initial funding of $11.2 million, which included an adjustment for the total spending on ARO requirements as of May 31, 2008. We have an annual funding obligation of approximately $16.7 million, with installments to be deposited monthly.

10. 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, 2010 and December 31, 2009 are as follows (in millions):

Regulatory Assets		2010				2009
Grossed-up deferred taxes on equity funds used during construction		$	87.8			$	89.9
Asset retirement obligations			101.3				95.9
Deferred taxes			11.3				12.4
Postretirement benefits other than pension			6.8				7.9
Fuel cost			33.2				66.0
Electric power cost			6.9				—
Other			0.1				0.6
Total Regulatory Assets		$	247.4			$	272.7
Regulatory Liabilities		2010				2009
Negative salvage		$	100.0			$	66.7
Deferred cash out			1.8				2.2
Electric power cost			—				1.6
Postretirement benefits other than pension			14.0				4.7
Other			2.0				0.7
Total Regulatory Liabilities		$	117.8			$	75.9

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. 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: We record an asset and a liability equal to the present value of each expected future ARO. The ARO asset is depreciated in a manner consistent with the expected 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 rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and is offset by a regulatory asset. The regulatory asset is being recovered through our rates, and is being amortized to expense consistent with the amounts collected in rates.

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 differences between the annual actuarially determined cost and amounts currently being recovered in rates are recorded as regulatory assets or liabilities and collected or refunded through future rate adjustments. These amounts are not included in the rate base.

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 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.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

QUARTERLY FINANCIAL DATA (UNAUDITED)

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

2010		First (1)				Second (2)				Third				Fourth (3)
Operating revenues		$	301,049			$	276,681			$	305,063			$	299,202
Operating expenses			206,414				198,897				217,791				219,426
Operating income			94,635				77,784				87,272				79,776
Interest expense			23,547				23,733				23,751				23,942
Other (income) and deductions, net			(5,035	)			(4,726	)			(10,119	)			(6,762	)
Income before income taxes			76,123				58,777				73,640				62,596
Provision (benefit) for income taxes			129				105				169				(43	)
Net income		$	75,994			$	58,672			$	73,471			$	62,639

2009		First (4)				Second (5)				Third (6)				Fourth (7)
Operating revenues		$	290,179			$	313,254			$	273,554			$	282,286
Operating expenses			195,716				229,212				198,947				200,094
Operating income			94,463				84,042				74,607				82,192
Interest expense			23,489				23,549				23,633				23,709
Other (income) and deductions, net			(9,440	)			(9,713	)			(11,121	)			(8,911	)
Income before income taxes			80,414				70,206				62,095				67,394
Provision (benefit) for income taxes			—				—				—				(248	)
Net income		$	80,414			$	70,206			$	62,095			$	67,642