TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC - FORM 10-K

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EX-31.2 - EX-31.2 - TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC	tgpl_20151231xex-312.htm
EX-31.1 - EX-31.1 - TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC	tgpl_20151231xex-311.htm
EX-32 - EX-32 - TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC	tgpl_20151231xex-32.htm

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)



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

For the fiscal year ended December 31, 2015



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

For the transition period from to

Commission file number 1-7584

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

(Exact Name of Registrant as Specified in Its Charter)



Delaware		74-1079400
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

2800 Post Oak Boulevard, Houston, Texas		77056
(Address of Principal Executive Offices)		(Zip Code)

713-215-2000

(Registrant’s Telephone Number, Including Area Code)

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

None

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

None

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

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

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

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

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

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



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

(Do not check if a smaller reporting company)

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

DOCUMENTS INCORPORATED BY REFERENCE

None

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

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TRANSCONTINTENTAL GAS PIPE LINE COMPANY, LLC

FORM 10-K

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		Page
	PART I
Item 1.	Business	3
Item 1A.	Risk Factors	8
Item 1B.	Unresolved Staff Comments	20
Item 2.	Properties	20
Item 3.	Legal Proceedings	21
Item 4.	Mine Safety Disclosures	21
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	21
Item 6.	Selected Financial Data (Omitted)	21
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 7A.	Quantitative and Qualitative Disclosure About Market Risk	25
Item 8.	Financial Statements and Supplementary Data	26
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosures	51
Item 9A.	Controls and Procedures	51
Item 9B.	Other Information	52
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance (Omitted)
Item 11.	Executive Compensation (Omitted)
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters (Omitted)
Item 13.	Certain Relationships and Related Transactions, and Director Independence (Omitted)
Item 14.	Principal Accountant Fees and Services	52
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	53

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DEFINITIONS

We use the following gas measurements in this report:

Bcf – means billion cubic feet.

Mdth – means thousand dekatherms.

Mdth/d – means thousand dekatherms per day.

MMdth – means million dekatherms.

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PART 1

Item 1. Business

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

Transco is indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). On February 2, 2015, WPZ was merged into Access Midstream Partners, L.P. (ACMP), another publicly traded limited partnership consolidated by Williams. ACMP was the surviving partnership and was subsequently renamed Williams Partners L.P. At December 31, 2015, Williams holds an approximate 60 percent interest in WPZ, comprised of an approximate 58 percent limited partner interest and all of the 2 percent general partner interest.

On September 28, 2015, Williams publicly announced in a press release that it had entered into an Agreement and Plan of Merger (Merger Agreement) with Energy Transfer Equity, L.P. (Energy Transfer) and certain of its affiliates. The Merger Agreement provides that, subject to the satisfaction of customary closing conditions, Williams will be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger) with ETC surviving the ETC Merger. Energy Transfer formed ETC as a limited partnership that will be treated as a corporation for U.S. federal income tax purposes. Immediately following the completion of the ETC Merger, ETC will contribute to Energy Transfer all of the assets and liabilities of Williams in exchange for the issuance by Energy Transfer to ETC of a number of Energy Transfer Class E common units equal to the number of ETC common shares issued to Williams stockholders in the ETC Merger (ETC Exchange). WPZ expects to retain its current name and remain a publicly traded limited partnership following the ETC Merger.

GENERAL

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

At December 31, 2015, our system had a mainline delivery capacity of approximately 6.4 MMdth of gas per day from production areas to our primary markets including delivery capacity from the mainline to locations on our Mobile Bay Lateral. Using our Leidy Line along with market-area storage and transportation capacity, we can deliver an additional 5.1 MMdth of gas per day for a system-wide delivery capacity total of approximately 11.5 MMdth of gas per day. The system is comprised of approximately 9,700 miles of mainline and branch transmission pipelines, 45 compressor stations, four underground storage fields and one liquefied natural gas (LNG) storage facility. Compression facilities at sea level rated capacity total approximately 1.8 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, 2015, our customers had stored in our facilities approximately 161 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.

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MARKETS AND TRANSPORTATION

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

Our major customers are public utilities and municipalities that provide service to residential, commercial, industrial and electric generation end users. Shippers on our pipeline system include public utilities, municipalities, intrastate pipelines, direct industrial users, electrical generators, gas marketers and producers. Our two largest customers in 2015 were National Grid and Public Service Enterprise Group, which accounted for approximately 8.1 percent and 6.9 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 2015 or are significant future pipeline projects for which we have customer commitments. In 2016, we expect to invest capital of approximately $1.1 billion in pipeline expansion projects.

Rockaway Delivery Lateral

The Rockaway Delivery Lateral Project involves the construction of a three-mile offshore lateral to National Grid’s distribution system in New York. In May 2014, we received approval from the FERC for the project. We placed the project into service during the second quarter of 2015, which enabled us to begin providing 647 Mdth/d of firm service to National Grid through the Rockaway Delivery Lateral.

Northeast Connector

The Northeast Connector Project involves an expansion of our existing natural gas transmission system from southeastern Pennsylvania to the Rockaway Delivery Lateral. In May 2014, we received approval from the FERC for the project. On December 1, 2014, we placed a portion of the project into service, which enabled us to begin providing 65 Mdth/d of additional firm transportation service from Station 195 in Pennsylvania to the Rockaway Delivery Lateral junction. We placed the remainder of the project into service during the second quarter of 2015. In total, the project increased capacity by 100 Mdth/d.

Mobile Bay South III

The Mobile Bay South III Project involves an expansion of the Mobile Bay line south from Station 85 in west central Alabama to delivery points along the line. In April 2014, we received approval from the FERC for the project. On April 1, 2015, the project was placed into service, which enabled us to begin providing 225 Mdth/d of additional firm transportation service through the Mobile Bay Lateral.

Virginia Southside

The Virginia Southside Project involves an expansion of our existing mainline natural gas transmission system together with a new lateral to provide incremental firm transportation capacity from the Zone 6 Station 210 Pooling Point in New Jersey to Dominion Virginia Power’s power station under construction in Brunswick County, Virginia, and to both our Cascade Creek interconnection with East Tennessee Natural Gas and our Pleasant Hill delivery point to Piedmont Natural Gas Company, Inc. in North Carolina. In November 2013, we received approval from the FERC for the project. On December 1, 2014, we placed a portion of the project into service, which enabled us to begin providing 250 Mdth/d of additional firm transportation service through the mainline portion of the project on an interim basis, until the in-service date of the project as a whole. We placed the remainder of the project into service during the third quarter of 2015. In total, the project increased capacity by 270 Mdth/d.

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Leidy Southeast

The Leidy Southeast Project involves an expansion of our existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line in Pennsylvania to the Station 85 Pooling Point in Choctaw County, Alabama. In December 2014, we received approval from the FERC for the project. On March 1, 2015, we began providing firm transportation service through the mainline portion of the project (from the Station 210 Pooling Point in New Jersey to the Station 85 Pooling Point in Alabama) on an interim basis, until the in-service date of the project as a whole. We placed 130 Mdth/d of full project capacity into service on December 1, 2015 and increased that amount to 290 Mdth/d on December 30, 2015. We placed the remainder of the project into service during January 2016. In total, the project increased capacity by 525 Mdth/d.

Rock Springs

The Rock Springs Expansion Project involves an expansion of our existing natural gas transmission system southbound from the Zone 6 Station 210 Pooling Point in New Jersey along with a new, eleven-mile lateral to Old Dominion Electric Cooperative's proposed Wildcat Point generation facility in Cecil County, Maryland. In March 2015, we received approval from FERC for the project. We plan to place the project into service during the third quarter of 2016. The project is expected to increase capacity by 192 Mdth/d.

Gulf Trace

The Gulf Trace Expansion Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 65 in St. Helena Parish, Louisiana westward to a new interconnection with Sabine Pass Liquefaction in Cameron Parish, Louisiana. In October 2015, we received approval from the FERC for the project. We plan to place the project into service during the first quarter of 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 1,200 Mdth/d.

Hillabee

The Hillabee Expansion Project involves an expansion of our existing natural gas transmission system from our Station 85 Pooling Point in Choctaw County, Alabama to a proposed new interconnection with Sabal Trail Transmission's system in Tallapoosa County, Alabama. The project will be constructed in phases, and all of the project expansion capacity will be leased to Sabal Trail Transmission. In February 2016, the FERC issued a certificate order for the initial phases of the project. We may seek rehearing of certain aspects of the FERC order. We plan to place the initial phases of the project into service during the second quarters of 2017 and 2020, assuming timely receipt of all necessary regulatory approvals, and together they are expected to increase capacity by 1,025 Mdth/d.

Dalton

The Dalton Expansion Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from the Zone 6 Station 210 Pooling Point in New Jersey to markets in northwest Georgia. We filed an application with the FERC in March 2015 for approval of the project. We plan to place the project into service in 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 448 Mdth/d.

Atlantic Sunrise

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

Garden State

The Garden State Expansion Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from our Zone 6 Station 210 Pooling Point in New Jersey to a new interconnection on our Trenton Woodbury Lateral in Burlington County, New Jersey. The project will be constructed in phases. We filed an application with the FERC in February 2015 for approval of the project. We plan to place the initial phase of the project into service during the fourth quarter of 2016 and the remaining portion of the project into

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service during the third quarter of 2017, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 180 Mdth/d.

Virginia Southside II

The Virginia Southside II Expansion Project involves an expansion of our existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from the Zone 6 Station 210 Pooling Point in New Jersey and the Zone 5 Station 165 Pooling Point in Virginia to a proposed delivery point on a new lateral off of our Brunswick Lateral in Virginia. We filed an application with the FERC in March 2015 for approval of the project. We plan to place the project into service during the fourth quarter of 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 250 Mdth/d.

New York Bay

The New York Bay Expansion Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point and the Narrows meter station in Richmond County, New York. We filed an application with the FERC in July 2015 for approval of the project. We plan to place the project into service during the fourth quarter of 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 115 Mdth/d.

Gulf Connector

The Gulf Connector Expansion Project involves an expansion of our existing natural gas transmission system to provide incremental firm transportation capacity from Station 65 in Louisiana to delivery points in Wharton and San Patricio Counties, Texas. The project will be constructed in phases. We intend to file an application with the FERC in the third quarter of 2016. We plan to place the initial phase of the project into service during the second half of 2018 and the remaining phase in 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 475 Mdth/d.

RATE MATTERS

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

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

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

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the FERC did not adequately support its conclusions. On October 16, 2014, the FERC issued an order establishing a "paper hearing" and requesting briefs on certain questions raised by the D.C. Circuit's opinion. Parties to the proceeding filed initial and reply briefs on February 6, 2015 and March 6, 2015, respectively. We intend to continue to pursue approval of our proposed rate design. If we are unsuccessful, it is reasonably possible that refunds could be as much as $17.8 million at December 31, 2015.

REGULATION

FERC Regulation.

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

Environmental Matters.

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


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


•	Damage to facilities resulting from accidents during normal operations;


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


•	Blowouts, cratering and explosions.

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

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

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

Safety and Maintenance.

Our operations are subject to the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Improvement Act of 2002, and the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011 (Pipeline Safety

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Act), which regulate safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. The U.S. Department of Transportation (USDOT) administers federal pipeline safety laws.

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

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

Pipeline Integrity Regulations We have developed an Integrity Management Plan in compliance with the USDOT 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 Plan includes a baseline assessment plan that was completed in 2012 along with periodic reassessments to be completed within required timeframes. In meeting the integrity regulations, we have identified high consequence areas as defined by the rule. Ongoing periodic reassessments and initial assessments of any new high consequence areas will be completed within the timeframes required by the rule. We estimate that the cost to be incurred in 2016 associated with this program will be approximately $30 million. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

EMPLOYEES

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

TRANSACTIONS WITH AFFILIATES

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

Item 1A. Risk Factors

FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT FOR PURPOSES OF

THE “SAFE HARBOR” PROVISIONS OF

THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

The reports, filings, and other public announcements of Transcontinental Gas Pipe Line Company, LLC may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act). These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

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


•	The status, expected timing and expected outcome of the proposed ETC Merger;


•	Events which may occur subsequent to the proposed ETC Merger including events which directly impact our business;


•	Amounts and nature of future capital expenditures;


•	Expansion and growth of our business and operations;


•	Financial condition and liquidity;


•	Business strategy;


•	Cash flow from operations or results of operations;


•	Rate case filings;


•	Natural gas prices, supply and demand; and


•	Demand for our services.

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


•	The timing and likelihood of completion of the proposed ETC Merger, including the satisfaction of conditions to the completion of the proposed ETC Merger;


•	Energy Transfer's plans for us, following the completion of the proposed ETC Merger;


•	Disruption from the proposed ETC Merger making it more difficult to maintain business and operational relationships;


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


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


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


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


•	Development of alternative energy sources;


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


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


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


•	Changes in maintenance and construction costs;


•	Changes in the current geopolitical situation;


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


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


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


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


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

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

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

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

RISK FACTORS

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

Throughout these risk factors reference is made to Williams and the potential impact Williams may have on our business, financial condition and operating results. As noted above, Williams has entered into the Energy Transfer Merger Agreement with Energy Transfer and certain of its affiliates. Should the ETC Merger and the ETC Exchange each be consummated, references throughout these risk factors to Williams would instead refer to Energy Transfer or ETC, as applicable.

Risks Inherent to Our Industry and Business

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

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


•	fires, blowouts, cratering, and explosions;


•	uncontrolled releases of natural gas;


•	pollution and other environmental risks;


•	aging infrastructure and mechanical problems;


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


•	operator error; and


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

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

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

We provide some services pursuant to long-term, fixed-price contracts. It is possible that costs to perform services under such contracts will exceed the revenues we collect for our services. Although most of the services are priced at

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cost-based rates that are subject to adjustment in rate cases, under the FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” that may be above or below the FERC regulated cost-based rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs that could be produced by inflation or other factors relating to the specific facilities being used to perform the services.

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

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


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


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


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


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


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

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

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

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

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sources. We may not be able to successfully compete against current and future competitors and any failure to do so could have a material adverse effect on our business, cash flows and results of operations.

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

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

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

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

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

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

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

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

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

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

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

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

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

Our operations are subject to extensive federal, state and local laws and regulations governing environmental protection, endangered and threatened species, the discharge of materials into the environment and the security of chemical and industrial facilities. Substantial costs, liabilities, delays and other significant issues related to environmental laws and regulations are inherent in the gathering, transportation, and storage of natural gas as well as waste disposal practices and construction activities. New or amended environmental laws and regulations can also result in significant increases in capital costs we incur to comply with such laws and regulations.

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

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

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

In addition, climate change and the costs that may be associated with its impacts and with the regulation of emissions of greenhouse gases (GHG) have the potential to affect our business. Regulatory actions by the U.S. Environmental Protection Agency (EPA) or the passage of new climate change laws or regulations could result in increased costs to (i) operate and maintain our facilities, (ii) install new emissions controls on our facilities and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material

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adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Climate change and GHG regulation could also reduce demand for our services.

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

We rely on a limited number of customers for a significant portion of our revenues. Although some of these customers are subject to long-term contracts, we may be unable to negotiate extensions or replacements of these contracts on favorable terms, or at all. For the year ended December 31, 2015, our largest customer was National Grid, which accounted for approximately 8.1 percent of our operating revenues. The loss of all, or even a portion of, the revenues from contracted volumes supplied by our key customers, as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition, and cash flows, unless we are able to acquire comparable volumes from other sources.

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

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

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

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

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

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

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

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

Williams currently maintains excess liability insurance with limits of $820 million per occurrence and in the annual aggregate with a $2 million per occurrence deductible. This insurance covers Williams, its subsidiaries, and certain of its affiliates, including us, for legal and contractual liabilities arising out of bodily injury or property damage, including resulting loss of use to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability for full limits, with the first $135 million of insurance also providing gradual pollution liability coverage for natural gas and natural gas liquids operations.

Although we maintain property insurance on certain physical assets that we own, lease, or are responsible to insure, the policy may not cover the full replacement cost of all damaged assets or the entire amount of business interruption loss we may experience. In addition, certain perils may be excluded from coverage or sub-limited. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. We may elect to self- insure a portion of our risks. We do not insure our onshore underground pipelines for physical damage, except at certain locations such as river crossings and compressor stations. Offshore assets are covered for property damage when loss is due to a named windstorm event and coverage for loss caused by a named windstorm is significantly sub-limited and subject to a large deductible. All of our insurance is subject to deductibles.

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

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

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

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

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


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


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


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

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

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

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

The pendency of the proposed ETC Merger between Energy Transfer and Williams could adversely affect our business and operations.

The proposed ETC Merger between Energy Transfer and Williams may create a significant distraction for the management team and board of directors of Williams and require Williams to expend significant time and resources. As certain members of Williams’ management team also serve on our management team we may encounter the same management distraction and constraints. In connection with the proposed ETC Merger some of our customers or vendors may delay or defer decisions, which could negatively impact our revenues, earnings, cash flows and expenses regardless of whether the proposed ETC Merger is completed. Similarly, current and prospective employees of Williams and its affiliates that provide services to us may experience uncertainty about their future roles following the proposed ETC Merger, which may materially adversely affect Williams’ ability to attract and retain such key personnel during the pendency of the proposed ETC Merger. If Energy Transfer and Williams fail to complete the proposed ETC Merger, it may be difficult and expensive for Williams to recruit and hire replacements for departed employees. The proposed ETC Merger, its effects and related matters may also distract the Williams employees that provide services to us from day-to-day operations and require substantial commitments of time and resources. Moreover, the proposed ETC Merger may disrupt our business by causing uncertainty among our suppliers, customers and investors. In addition, due to operating covenants in the Merger Agreement, we may be unable, during the pendency of the proposed ETC Merger, to pursue certain strategic transactions, undertake certain significant capital projects, undertake certain significant financing transactions and otherwise pursue other actions that are not in the ordinary course of business. Such risks relating to vendors, customers, employees and those risks arising from operating covenants in the Merger Agreement will also apply to varying degrees our affiliates thereby have a corresponding impact on us.

Risks Related to Strategy and Financing

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

Our total outstanding long-term debt (including current portion) as of December 31, 2015, was $1,419.6 million.

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

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


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


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


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


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


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

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

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

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

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

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

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

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

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

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

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


•	payment of distributions and repayment of advances;


•	decisions on financings and our capital raising activities;


•	mergers or other business combinations; and


•	acquisition or disposition of assets.

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

Risks Related to Regulations That Affect Our Industry

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

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


•	transportation of natural gas in interstate commerce;


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


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


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


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


•	accounts and records;


•	depreciation and amortization policies;

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


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

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

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

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

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

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

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

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

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

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

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Risks Related to Weather, Other Natural Phenomena and Business Disruption

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

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

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

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

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

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

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

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

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

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Item 3. Legal Proceedings

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

Item 4. Mine Safety Disclosures

Not applicable.

PART II

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

At December 31, 2015, we are owned indirectly by Williams Partners L.P., and Williams holds an approximate 60 percent interest in Williams Partners, L.P., comprised of an approximate 58 percent limited partner interest and all of Williams Partners L.P.’s 2 percent general partner interest.

Distributions totaling $536 million were declared and paid by us to our parent during the year ended December 31, 2015. An additional distribution of $175 million was declared and paid by us to our parent in January 2016. Distributions totaling $411 million were declared and paid by us to our parent during the year ended December 31, 2014.

In the year ended December 31, 2015, our parent made contributions totaling $652 million to us to fund a portion of our expenditures for additions to property, plant and equipment. In January 2016, our parent made an additional $112 million contribution to us. In the year ended December 31, 2014, our parent made contributions to us totaling $267 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

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the effects of the types of transactions described above that result from regulatory accounting requirements. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Balance Sheet and included in the Consolidated Statement of Comprehensive Income for the period in which the discontinuance of regulatory accounting treatment occurs, unless otherwise required to be recorded under other provisions of U.S. generally accepted accounting principles. The aggregate amount of regulatory assets reflected in the Consolidated Balance Sheet is $343.3 million at December 31, 2015. The aggregate amount of regulatory liabilities reflected in the Consolidated Balance Sheet is $385.9 million at December 31, 2015. A summary of regulatory assets and liabilities is included in Note 9 of Notes to Consolidated Financial Statements.

Impairment of Long-lived Assets

We evaluate our long lived assets for impairment when events or changes in circumstances indicate, in our management's judgment, that the carrying value of such assets may not be recoverable. When an indicator of a potential 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.

In December 2010 we detected a leak in one of the seven underground natural gas storage caverns at our Eminence Storage Field in Covington County, Mississippi. Due to the leak at this cavern, damage to the well at an adjacent cavern, and operating problems at two other caverns constructed at about the same time, we determined that the four caverns should be retired, which was completed in 2014. In addition, further studies have indicated the need for capital improvements over the next several years of the remaining three caverns. As a result, we performed an assessment of our Eminence storage field for impairment as of December 31, 2015. The carrying value at that date was $86 million. These events have not affected the performance of our obligations under our service agreements with our customers. However, judgments and assumptions are inherent in our estimate of future cash flows used to evaluate Eminence. In our evaluation, our estimate of the undiscounted cash flows of Eminence exceeded its carrying value, and thus no impairment loss was recognized in 2015. If our estimates of revenues were to significantly decrease, it could result in an impairment of this asset.

Results of Operations

Analysis of Financial Results

This analysis discusses financial results of our operations for the years 2015 and 2014. 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.

2015 COMPARED TO 2014

Operating Income and Net Income Operating Income for 2015 was $587.2 million compared to $472.8 million for 2014. Net Income for 2015 was $575.5 million compared to $422.9 million for 2014. The increase in Operating Income of $114.4 million (24.2 percent) was primarily due to higher Natural gas transportation revenues, partly offset by an increase in Operating Costs and Expenses in 2015 compared to 2014, as discussed below. The increase in Net Income of $152.6 million (36.1 percent) was mostly attributable to the increase in Operating Income, and a favorable change in net expenses in Other (Income) and Other Expenses, as discussed below.

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

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Operating Revenues Natural gas sales increased $4.4 million (3.6 percent) to $125.8 million for 2015 when compared to 2014. The increase was due to higher cash-out sales. Cash-out sales are offset in our costs of natural gas sold and therefore had no impact on our operating income or results of operations.

Operating Revenues Natural gas transportation for 2015 was $1,318.7 million compared to $1,166.2 million for 2014. The $152.5 million (13.1 percent) increase was primarily due to higher transportation reservation revenues related to new incremental projects of $165.9 million, (primarily due to $65.6 million from our Leidy Southeast project placed in partial service in March 2015, $51.6 million from our Rockaway project placed in service in May 2015 and $28.3 million from our Virginia Southside project placed into partial service in December 2014 and fully placed in service in September 2015), higher transportation revenue of $3.5 million related to re-marketing of previously turned back capacity on Mobile Bay, partially offset by $10.0 million lower commodity revenues, $3.4 million lower FT backhaul revenues and $2.5 million lower revenues which recover electric power costs. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations.

Operating Revenues Natural gas storage for 2015 was $138.0 million compared to $140.3 million for 2014. The $2.3 million (1.6 percent) decrease was primarily due to lower commodity revenues in 2015.

Operating Revenues Other for 2015 was $10.1 million compared to $5.2 million for 2014. The $4.9 million (94.2 percent) increase was primarily due to higher Park and Loan volumes in 2015.

Operating Costs and Expenses Excluding the Cost of natural gas sales, which is directly offset in revenues, our operating expenses increased approximately $40.7 million (4.9 percent) from the comparable period in 2014. This increase was primarily attributable to:

•

A $16.8 million (6.2 percent) increase in Operation and maintenance costs primarily resulting from a $13.1 million increase in miscellaneous contractual services costs primarily due to general maintenance, hydrostatic and other testing on our pipeline and an $8.2 million increase resulting from higher employee labor and related benefit costs, partly offset by a $4.4 million decrease in other materials and supplies primarily due to higher general repairs and maintenance in 2014;


•	A $7.7 million (2.8 percent) increase in Depreciation and amortization costs primarily due to additional assets placed into service in 2015;


•	A $5.1 million (11.5 percent) increase in Taxes - other than income taxes primarily due to additional assets placed into service in 2015;

•

A $20.6 million (55.4 percent) increase in Other expense, net primarily due to an $8.0 million of expense to establish a regulatory liability associated with rate collections in excess of our pension funding obligation, a $6.2 million increase in reserve for litigations due to the absence of favorable adjustments recorded in 2014 for certain litigation and regulatory matters which have been settled, a $4.6 million increase in project development costs partly due to the capitalization in 2014 of $3.5 million of feasibility costs, and a $3.6 million unfavorable change in the deferral of ARO-related depreciation to a regulatory asset;


•	Partially offset by a $5.1 million (16.1 percent) decrease in Cost of natural gas transportation primarily resulting from a $2.7 million lower fuel costs and a $2.5 million lower electric power costs. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations.; and


•	A $4.3 million (2.3 percent) decrease in Administrative and general costs primarily resulting from a $12.9 million lower allocated corporate expenses, partly offset by a $6.6 million increase in labor and related costs.

Other (Income) and Other Deductions Other (income) and other expenses in 2015 had a favorable change of $38.3 million (76.6 percent) over 2014 primarily due to a $38.1 million increase in Allowance for equity and borrowed funds used during construction (AFUDC) due to increased spending on various expansion projects.

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Station 62 Incident

On October 8, 2015, an explosion and fire occurred at our Compressor Station No. 62 in Gibson, Louisiana. At the time of the incident, planned facility maintenance was being performed at the station and the facility was not operational. The incident was related to maintenance work being performed on the slug catcher at the station. Four contractors were fatally injured as a result of the incident.

We are cooperating with local, state and federal authorities, including the Louisiana State Police, Terrebonne Parish, the Louisiana Department of Environmental Quality, the U.S. Environmental Protection Agency (Region 6), the Occupational Safety and Health Administration, and the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration, and we are investigating to determine the cause of the incident. We have not received any formal enforcement actions from the agencies involved, but the agencies could issue penalties pertaining to final determinations. Any potential fines and penalties from these agencies would not be covered by our insurance policy. Both on-site and off-site air monitoring was conducted from shortly after the incident until approximately one week following the incident.

The incident did not cause any rupture of the gas pipeline or any damage to the building containing the compressor engines. In anticipation of the planned maintenance, our Southeast Louisiana Lateral was taken out of service on October 4, 2015, which affected approximately 200 MMcf/d of natural gas production. The lateral currently remains out of service while we assess the condition of facilities potentially impacted by the incident.

We have been served with a civil lawsuit in connection with the incident, which includes claims for wrongful death and personal injury. However, due to the ongoing investigation into the cause of the incident, our potential defenses to liability and limited information as to the nature and extent of the plaintiffs' damages, and the limited information available associated with any potential agency actions, we cannot reasonably estimate a range of potential loss related to these contingencies at this time.

Filing of Rate Case

On August 31, 2012, we filed a general rate case with the FERC for an overall increase in rates. In September 2012, the FERC issued an order accepting our filing subject to the outcome of a hearing. The rates for certain services that were proposed as overall rate decreases became effective October 1, 2012, and the increased rates became effective March 1, 2013. All issues in this proceeding have been resolved by a stipulation and agreement (Agreement) approved by the FERC. Pursuant to its terms, the Agreement became effective March 1, 2014 and refunds of approximately $118 million were issued on April 18, 2014.

Effects of Inflation

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

CAPITAL RESOURCES AND LIQUIDITY

Method of Financing

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

We may raise capital through private debt offerings, as well as offerings registered pursuant to offering-specific registration statements. Interest rates, market conditions, and industry conditions will affect amounts raised, if any, in the capital markets. On January 22, 2016, we completed a private placement of $1 billion in aggregate principal amount

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of 7.85 percent senior unsecured notes due 2026. We intend to use the net proceeds from the offering to repay indebtedness, including our $200 million of 6.4 percent notes due upon their maturity on April 15, 2016, and to fund capital expenditures.

We, along with WPZ and Northwest Pipeline LLC, are co-borrowers under a $3.5 billion unsecured credit facility. Total letter of credit capacity available to WPZ under the credit facility is $1.125 billion. We may borrow up to $500 million under the credit facility to the extent not otherwise utilized by WPZ and Northwest Pipeline LLC. See Note 3 of Notes to Consolidated Financial Statements for further discussion of the credit facility.

We are a participant in WPZ's cash management program, and we make advances to and receive advances from WPZ. At December 31, 2015, our advances to WPZ totaled approximately $64.6 million. These advances are represented by demand notes. The decrease in 2015 of these advances primarily resulted from the use of funds for capital expenditures. In April 2014, we utilized repayment of a portion of these advances in order to pay rate refunds to our customers under the Agreement in Docket No. RP12-993. The net proceeds of the January 2016 financing were advanced to WPZ.

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

Capital Expenditures

We categorize our capital expenditures as either maintenance capital expenditures or expansion capital expenditures. Maintenance capital expenditures are those expenditures required to maintain the existing operating capacity and service capability of our assets, including replacement of system components and equipment that are worn, obsolete, completing their useful life, or necessary to remain in compliance with environmental laws and regulations. Expansion capital expenditures improve the service capability of existing assets, extend useful lives, increase transmission or storage capacities from existing levels, reduce costs or enhance revenues. We anticipate 2016 capital expenditures will be approximately $1.3 billion. Of this total, approximately $1.2 billion is considered nondiscretionary due to legal, regulatory, and/or contractual requirements, primarily due to expansion projects.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

At December 31, 2015, 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, 2015. The table presents principal cash flows and weighted-average interest rates by expected maturity dates.



December 31, 2015	Expected Maturity Date
	2016			2017			2018			2019
	(Dollars in millions)
Long-term debt:
Fixed rate	$	200		$	—		$	250		$	—
Interest rate	5.57		%	5.53		%	5.47		%	5.40		%

December 31, 2015	Expected Maturity Date
	2020			Thereafter			Total			Fair Value
	(Dollars in millions)
Long-term debt:
Fixed rate	$	—		$	983		$	1,433		$	1,244
Interest rate	5.40		%	5.06		%

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Item 8. Financial Statements and Supplementary Data



		Page

Report of Independent Registered Public Accounting Firm		27

Consolidated Statement of Comprehensive Income		28

Consolidated Balance Sheet		29

Consolidated Statement of Owner’s Equity		31

Consolidated Statement of Cash Flows		32

Notes to Consolidated Financial Statements		34

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Management Committee of Transcontinental Gas Pipe Line Company, LLC

We have audited the accompanying consolidated balance sheet of Transcontinental Gas Pipe Line Company, LLC as of December 31, 2015 and 2014, and the related consolidated statements of comprehensive income, owner’s equity, and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Transcontinental Gas Pipe Line Company, LLC at December 31, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

/S/ ERNST & YOUNG LLP

Houston, Texas

February 24, 2016

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Thousands of Dollars)



	Years Ended December 31,
	2015			2014			2013
Operating Revenues:
Natural gas sales	$	125,774		$	121,397		$	113,488
Natural gas transportation	1,318,656			1,166,244			1,094,807
Natural gas storage	137,983			140,344			143,047
Other	10,106			5,152			4,990
Total operating revenues	1,592,519			1,433,137			1,356,332

Operating Costs and Expenses:
Cost of natural gas sales	125,774			121,397			113,488
Cost of natural gas transportation	26,501			31,629			24,936
Operation and maintenance	288,386			271,603			264,631
Administrative and general	179,489			183,760			182,352
Depreciation and amortization	277,850			270,181			265,273
Taxes — other than income taxes	49,567			44,521			43,898
Other expense, net	57,800			37,208			32,606
Total operating costs and expenses	1,005,367			960,299			927,184

Operating Income	587,152			472,838			429,148

Other (Income) and Other Expenses:
Interest expense - affiliate	64			70			190
- other	82,774			84,917			84,000
Interest income - affiliate	(28		)	(49		)	(45		)
- other	(1,933		)	(1,782		)	(2,068		)
Allowance for equity and borrowed funds used during construction (AFUDC)	(63,072		)	(25,046		)	(18,595		)
Equity in earnings of unconsolidated affiliates	(5,593		)	(5,783		)	(5,678		)
Miscellaneous other (income) expenses, net	(517		)	(2,373		)	(2,682		)
Total other (income) and other expenses	11,695			49,954			55,122

Net Income	575,457			422,884			374,026

Other comprehensive income:
Equity interest in unrealized gain on interest rate hedges (includes $316, $344, and $330 for the years ended December 31, 2015, 2014, and 2013, respectively, of accumulated other comprehensive income reclassification for equity interest in realized losses on interest rate hedges)	84			143			464

Comprehensive Income	$	575,541		$	423,027		$	374,490

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)



	December 31,
	2015		2014
ASSETS

Current Assets:
Cash	$	—	$	173
Receivables:
Trade, less allowance of $13 ($0 in 2014)	134,834		127,141
Affiliates	1,084		654
Advances to affiliate	64,608		306,910
Other	15,422		3,594
Transportation and exchange gas receivables	2,427		3,485
Inventories:
Gas in storage, at original cost	780		715
Gas in storage, LIFO	—		497
Gas available for customer nomination, at average cost	19,838		28,464
Material and supplies, at lower of average cost or market	36,223		37,023
Regulatory assets	79,575		77,810
Other	15,297		14,683
Total current assets	370,088		601,149

Investments, at cost plus equity in undistributed earnings	45,078		47,050

Property, Plant and Equipment:
Natural gas transmission plant	10,863,944		9,645,382
Less-Accumulated depreciation and amortization	3,471,775		3,257,844
Total property, plant and equipment, net	7,392,169		6,387,538

Other Assets:
Regulatory assets	263,730		239,080
Other	73,814		65,263
Total other assets	337,544		304,343

Total assets	$	8,144,879	$	7,340,080

(continued)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED BALANCE SHEET

(Thousands of Dollars)



	December 31,
	2015			2014
LIABILITIES AND OWNER’S EQUITY

Current Liabilities:
Payables:
Trade	$	194,081		$	237,873
Affiliates	38,243			37,688
Cash overdrafts	28,969			30,867
Transportation and exchange gas payables	1,355			4,701
Accrued liabilities:
Property and other taxes	12,661			13,723
Interest	19,894			19,894
Regulatory liabilities	3,536			7,054
Customer advances	20,999			9,205
Asset retirement obligations	23,192			16,444
Other	28,948			37,785
Total current liabilities	371,878			415,234

Long-Term Debt	1,419,574			1,418,692

Other Long-Term Liabilities:
Asset retirement obligations	299,834			280,031
Regulatory liabilities	382,325			326,083
Advances for construction costs	97,790			30,456
Transportation prepayments	12,806			—
Other	4,819			5,272
Total other long-term liabilities	797,574			641,842

Contingent Liabilities and Commitments (Note 2)

Owner’s Equity:
Member’s capital	3,176,499			2,524,499
Retained earnings	2,379,385			2,339,928
Accumulated other comprehensive loss	(31		)	(115		)
Total owner’s equity	5,555,853			4,864,312

Total liabilities and owner’s equity	$	8,144,879		$	7,340,080

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED STATEMENT OF OWNER’S EQUITY

(Thousands of Dollars)



	Years Ended December 31,
	2015			2014			2013
Member's Capital:
Balance at beginning of period	$	2,524,499		$	2,257,499		$	1,993,412
Cash contributions from parent	652,000			267,000			264,000
Non-cash contributions from parent	—			—			87
Balance at end of period	3,176,499			2,524,499			2,257,499
Retained Earnings:
Balance at beginning of period	2,339,928			2,328,044			2,204,018
Net income	575,457			422,884			374,026
Cash distributions to parent	(536,000		)	(411,000		)	(250,000		)
Balance at end of period	2,379,385			2,339,928			2,328,044
Accumulated Other Comprehensive Income (Loss):
Balance at beginning of period	(115		)	(258		)	(722		)
Equity interest in unrealized gain (loss) on interest rate hedge	84			143			464
Balance at end of period	(31		)	(115		)	(258		)

Total Owner's Equity	$	5,555,853		$	4,864,312		$	4,585,285

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED STATEMENT OF CASH FLOWS

(Thousands of Dollars)



	Years Ended December 31,
	2015			2014			2013
Cash flows from operating activities:
Net income	$	575,457		$	422,884		$	374,026
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	277,850			269,395			263,949
Allowance for equity funds used during construction (equity AFUDC)	(48,435		)	(18,701		)	(13,299		)
Changes in operating assets and liabilities:
Receivables — affiliates	(430		)	1,947			55
— trade and other	(19,521		)	17,437			(21,772		)
Transportation and exchange gas receivable	1,058			3,272			(3,881		)
Regulatory assets - current	(1,765		)	(40,290		)	28,536
Regulatory assets - non-current	(24,650		)	17,532			21,910
Inventories	9,858			(19,167		)	232
Payables — affiliates	2,676			9,420			(3,738		)
— trade	(2,077		)	32,618			(26,463		)
Accrued liabilities	(10,015		)	(39,450		)	28,322
Asset retirement obligations - non-current	19,022			30,840			13,105
Asset retirement obligation - removal costs	(3,097		)	(12,824		)	(26,919		)
Reserve for rate refunds	—			(98,217		)	98,217
Other, net	45,007			7,954			10,731
Net cash provided by operating activities	820,938			584,650			743,011

Cash flows from financing activities:
Cash distributions to parent	(536,000		)	(411,000		)	(250,000		)
Cash contributions from parent	652,000			267,000			264,000
Other, net	—			22,329			(3,034		)
Net cash provided by (used in) financing activities	116,000			(121,671		)	10,966

(continued)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

CONSOLIDATED STATEMENT OF CASH FLOWS

(Thousands of Dollars)



	Years Ended December 31,
	2015			2014			2013
Cash flows from investing activities:
Property, plant and equipment additions, net of equity AFUDC*	$	(1,270,860	)	$	(724,163	)	$	(557,366	)
Contributions and advances for construction costs	85,901			57,817			30,450
Disposal of property, plant and equipment, net	(12,358		)	(7,532		)	(3,621		)
Advances to affiliate, net	242,302			219,470			(214,215		)
Return of capital from unconsolidated affiliates	2,015			2,333			1,438
Purchase of ARO Trust investments	(64,087		)	(52,038		)	(58,242		)
Proceeds from sale of ARO Trust investments	43,284			38,691			45,607
Proceeds from insurance	35,132			—			—
Other, net	1,560			2,503			1,900
Net cash used in investing activities	(937,111		)	(462,919		)	(754,049		)

Increase (decrease) in cash	(173		)	60			(72		)
Cash at beginning of period	173			113			185
Cash at end of period	$	—		$	173		$	113

____________________________
* Increase to property, plant and equipment, net of equity AFUDC	$	(1,222,292	)	$	(807,232	)	$	(572,956	)
Changes in related accounts payable and accrued liabilities	(48,568		)	83,069			15,590
Property, plant and equipment additions, net of equity AFUDC	$	(1,270,860	)	$	(724,163	)	$	(557,366	)

Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest (exclusive of amount capitalized)	$	66,489		$	77,304		$	76,803
Income taxes	1,161			864			116

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure and Control

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

Transco is indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). On February 2, 2015, WPZ was merged into Access Midstream Partners, L.P. (ACMP), another publicly traded limited partnership consolidated by Williams. ACMP was the surviving partnership and was subsequently renamed Williams Partners, L.P. At December 31, 2015, Williams holds an approximate 60 percent interest in WPZ, comprised of an approximate 58 percent limited partner interest and all of the 2 percent general partner interest.

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

Related Party Transaction

A member of Williams' Board of Directors, who was elected in 2013, is also the current chairman, president, and chief executive officer of Public Service Enterprise Group, an energy services company that is a customer of ours. This board member does not have any material interest in any transactions between the energy services company and us and he had no role in any such transactions. (See Note 7.)

Nature of Operations

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

Regulatory Accounting

We are regulated by the Federal Energy Regulatory Commission (FERC). The Accounting Standards Codification (ASC) Regulated Operations (Topic 980), provides that rate-regulated public utilities account for and report regulatory assets and liabilities consistent with the economic effect of the way in which regulators establish rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Accounting for businesses that are regulated and apply the provisions of Topic 980 can differ from the accounting requirements for non-regulated businesses. Transactions

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that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset retirement obligations, and other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, our management has determined that it is appropriate to apply the accounting prescribed by Topic 980 and, accordingly, the accompanying consolidated financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements.

Basis of Presentation

Williams’ acquisition of Transco Energy Company and its subsidiaries, including us, in 1995 was accounted for using the purchase method of accounting. Accordingly, an allocation of the purchase price was assigned to our assets and liabilities based on their estimated fair values. The purchase price allocation to us primarily consisted of a $1.5 billion allocation to property, plant and equipment and adjustments to deferred taxes based upon the book basis of the net assets recorded as a result of the acquisition. The amount allocated to property, plant and equipment is being depreciated on a straight-line basis over 40 years, the estimated useful lives of these assets at the date of acquisition, at approximately $35 million per year. At December 31, 2015, the remaining property, plant and equipment allocation was approximately $0.7 billion. Current FERC policy does not permit us to recover through rates amounts in excess of original cost.

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, 2015 and December 31, 2014 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 $7.6 million, $9.1 million, and $11.5 million in 2015, 2014 and 2013, respectively. Included in the distributions are $2.0 million, $2.3 million and $1.4 million return of capital in 2015, 2014 and 2013, respectively.

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.

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

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

Environmental Matters

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

Property, Plant and Equipment

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

We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission facilities, production and gathering facilities and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2015, 2014 and 2013 are as follows:



Category of Property		2015-2013

Gathering facilities		1.35% - 2.50%
Storage facilities		2.10% - 2.25%
Onshore transmission facilities		2.61% - 5.00%
Offshore transmission facilities		1.20% - 1.20%

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

Impairment of Long-lived Assets

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

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

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

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize.

Allowance for Funds Used During Construction

Allowance for funds used during construction (AFUDC) represents the estimated cost of borrowed and equity funds applicable to utility plant in process of construction and are included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. The FERC has prescribed a formula to be used in computing separate allowances for borrowed and equity AFUDC. The allowance for borrowed funds used during construction was $14.6 million, $6.3 million and $5.3 million, for 2015, 2014 and 2013, respectively. The allowance for equity funds was $48.4 million, $18.7 million, and $13.3 million, for 2015, 2014 and 2013, respectively.

Income Taxes

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

Accounts Receivable and Allowance for Doubtful Receivables

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

Gas Imbalances

In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems which may deliver different quantities of gas on behalf of us than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables which are recovered or repaid in cash or through the receipt or delivery of gas in the future and are recorded in the accompanying Consolidated Balance Sheet. Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. Our tariff includes a method whereby most transportation imbalances are settled on a monthly basis. Each month a portion of the imbalances are not identified to specific parties and remain unsettled. These are generally identified to specific parties and settled in subsequent periods. We believe that amounts that remain unidentified to specific parties and unsettled at year end are valid balances that will be settled with no material adverse effect upon our financial position, results of

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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, 2015 and 2014. 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. At December 31, 2015, Gas in Storage, at LIFO, was zero. If Gas in Storage, at LIFO, was valued at current replacement costs, the amount at December 31, 2014 would increase by $0.1 million. The basis for determining current cost at the end of each year is the December monthly average gas price delivered to pipelines in Texas and Louisiana. We utilize the average cost method of accounting for gas available for customer nomination. Liquefied natural gas in storage is valued at original cost.

Materials and Supplies Inventory

All inventories are stated at lower of average cost or market. We perform an annual review of Materials and Supplies inventories, including a quarterly analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 2015 and 2014.

Contingent Liabilities

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

Pension and Other Postretirement Benefits

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

Cash Flows from Operating Activities and Cash Equivalents

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

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Accounting Standards Issued But Not Yet Adopted

In January 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-01 “Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01). ASU 2016-01 addresses certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. The new standard is effective for interim and annual periods beginning after December 15, 2017. Early adoption is only permitted for certain applications. We are evaluating the impact of the new standard on our consolidated financial statements and our timing for adoption.

In July 2015, the FASB issued ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11). ASU 2015-11 simplifies the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first out or the retail inventory method. Under the new standard, in scope inventory should be measured at the lower of cost and net realizable value. The new standard is effective for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We measure inventory at the lower of cost or market; upon adoption, we will measure inventory at the lower of cost and net realizable value. We do not expect the new standard will have a material impact on the value of inventory reported in our consolidated financial statements.

In February 2015, the FASB issued ASU 2015-02 “Amendments to the Consolidation Analysis” (ASU 2015-02). ASU 2015-02 alters the models used to determine consolidation conclusions for certain entities, including limited partnerships, and may require additional disclosures. The standard is effective for financial statements issued for interim and annual reporting periods beginning after December 15, 2015, with either retrospective or modified retrospective presentation allowed. We do not expect the new standard will have a significant impact on our consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09 establishing ASC Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016. We continue to evaluate both the impact of this new standard on our consolidated financial statements and the transition method we will utilize for adoption.

2. CONTINGENT LIABILITIES AND COMMITMENTS

Rate Matters

The one issue reserved for litigation or further settlement relates to our proposal to change the design of the rates for service under one of our storage rate schedules, which was implemented subject to refund on March 1, 2007. A hearing on that issue was held before a FERC Administrative Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision in which he determined that our proposed incremental rate design is unjust and unreasonable. On January 21, 2010, the FERC reversed the ALJ’s initial decision, and approved our proposed incremental rate design. Certain parties sought rehearing of the FERC’s order and, on April 2, 2012, the FERC denied the rehearing request. On June 1, 2012, one of the parties filed an appeal in the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit). On February 21, 2014, the D.C. Circuit issued an opinion that vacated and remanded the FERC's order because the FERC did not adequately support its conclusions. On October 16, 2014, the FERC issued an order establishing a "paper hearing" and requesting briefs on certain questions raised by the D.C. Circuit's opinion. Parties to the proceeding filed initial and reply briefs on February 6, 2015 and March 6, 2015. We intend to continue to pursue approval of our proposed rate design. If we are unsuccessful, it is reasonably possible that refunds could be as much as $17.8 million at December 31, 2015.

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Environmental Matters

We have had studies underway for many years to test some of our facilities for the presence of toxic and hazardous substances such as polychlorinated biphenyls (PCBs) and mercury to determine to what extent, if any, remediation may be necessary. We have also similarly evaluated past on-site disposal of hydrocarbons at a number of our facilities. We have worked closely with and 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 $4 million to $6 million (including both expense and capital expenditures), measured on an undiscounted basis, and will substantially be spent over the next three to four 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, 2015, we had a balance of approximately $2.9 million for the expense portion of these estimated costs recorded in current liabilities ($1.4 million) and other long-term liabilities ($1.5 million) in the accompanying Consolidated Balance Sheet. At December 31, 2014, we had a balance of approximately $2.7 million for the expense portion of these estimated costs recorded in current liabilities ($0.8 million) and other long-term liabilities ($1.9 million) in the accompanying Consolidated Balance Sheet.

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 $4 million to $6 million range discussed above. Liability under the Comprehensive Environmental Response, Compensation and Liability Act and applicable state law can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.

In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. In May 2012, the EPA completed designation of new eight-hour ozone non-attainment areas. Several of our facilities are located in 2008 ozone non-attainment areas. To date, no federal actions have been proposed to mandate additional emission controls at these facilities. Pursuant to pending state regulatory actions associated with implementation of the 2008 ozone standard, we anticipate that some facilities may be subject to increased controls within five years. As a result, the cost of additions to property, plant, and equipment is expected to increase. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet the proposed regulations.

In December 2014, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels and subsequently finalized a rule on October 1, 2015. We are monitoring the rule's implementation as the reduction will trigger additional federal and state regulatory actions that may impact our operations. As a result, the cost of additions to property, plant and equipment is expected to increase. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet new regulations.

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

We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. As a result, as estimated costs of environmental assessment and remediation are incurred, they are recorded as regulatory

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assets in the Consolidated Balance Sheet until collected through rates. At December 31, 2015, we had a balance of approximately $1.6 million of uncollected environmental related regulatory assets recorded in current assets ($1.2 million) and other assets ($0.4 million) in the accompanying Consolidated Balance Sheet. At December 31, 2014, we had a balance of approximately $1.7 million of uncollected environmental related regulatory assets recorded in current assets ($1.2 million) and other assets ($0.5 million) in the accompanying Consolidated Balance Sheet.

Other Matters

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

Summary

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

Other Commitments

Commitments for construction We have commitments for construction and acquisition of property, plant and equipment of approximately $417 million at December 31, 2015.

3. DEBT, FINANCING ARRANGEMENTS AND LEASES

Long-Term Debt

At December 31, 2015 and 2014, long-term debt issues were outstanding as follows (in thousands):



	2015			2014
Debentures:
7.08% due 2026	$	7,500		$	7,500
7.25% due 2026	200,000			200,000
Total debentures	207,500			207,500

Notes:
6.4% due 2016	200,000			200,000
6.05% due 2018	250,000			250,000
5.4% due 2041	375,000			375,000
4.45% due 2042	400,000			400,000
Total notes	1,225,000			1,225,000

Total long-term debt issues	1,432,500			1,432,500
Unamortized debt issuance costs	(9,069		)	(9,803		)
Unamortized debt premium and discount, net	(3,857		)	(4,005		)

Total long-term debt	$	1,419,574		$	1,418,692

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Aggregate minimum maturities (face value) applicable to long-term debt outstanding at December 31, 2015, for the next five years, are as follows (in thousands):



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

There are no maturities applicable to long-term debt outstanding for the years 2017, 2019, and 2020.

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

Restrictive Debt Covenants

At December 31, 2015, 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.

Issuance

On January 22, 2016, we issued $1 billion of 7.85 percent senior unsecured notes due 2026 to investors in a private debt placement. We intend to use the net proceeds to repay debt and to fund capital expenditures. Accordingly, the $200 million of 6.4 percent notes due 2016 are classified as non-current in the accompanying Consolidated Balance Sheet.

Credit Facility

On February 2, 2015, we along with WPZ, Northwest, the lenders named therein and an administrative agent entered into the Second Amended and Restated Credit Agreement with aggregate commitments available of $3.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. The maturity date of the facility is February 2, 2020. However, the co-borrowers may request up to two extensions of the maturity date each for an additional one year period to allow a maturity date as late as February 2, 2022, under certain circumstances. The agreement allows for swing line loans up to aggregate amount of $150 million, subject to available capacity under the credit facility, and letters of credit commitments available to WPZ of $1.125 billion. We are able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers. At December 31, 2015, no letters of credit have been issued and $1.31 billion of loans to WPZ are outstanding under the credit facility. On December 18, 2015, we along with WPZ, Northwest, the lenders named therein and an administrative agent entered into the Amendment No. 1 to Second Amended & Restated Credit Agreement modifying the thresholds specified in the covenant related to the maximum ratio of WPZ's consolidated indebtedness to consolidated EBITDA.

Under the credit facility, WPZ is required to maintain a ratio of debt to EBITDA (each as defined in the credit facility) that must be no greater than 5.75 to 1.0 for the quarters ending December 31, 2015, March 31, 2016 and June 30, 2016. The ratio must be no greater than 5.5 to 1.0 for the quarters ending September 30, 2016 and December 31, 2016. The ratio must be no greater than 5.0 to 1.0 for the quarter ending March 31, 2017 and each subsequent fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the ratio must be no greater than 5.50 to 1.0. For us, the ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent. Measured as of December 31, 2015, we are in compliance with this financial covenant.

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

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

Other than swingline loans, each time funds are borrowed, the borrower must choose whether such borrowing will be an alternate base rate borrowing or a Eurodollar borrowing. If such borrowing is an alternate base rate borrowing, interest is calculated on the basis of the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 1/2 of 1 percent and (c) a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus 1 percent, plus, in the case of each of (a), (b) and (c), an applicable margin. If the borrowing is a Eurodollar borrowing, interest is calculated on the basis of LIBOR for the relevant period plus an applicable margin. Interest on swingline loans is calculated as the sum of the alternate base rate plus an applicable margin. The borrower is required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower's senior unsecured long-term debt ratings.

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WPZ participates in a commercial paper program and WPZ management considers amounts outstanding under this program to be a reduction of available capacity under the credit facility. On February 2, 2015, WPZ amended and restated the commercial paper program for the WPZ/ACMP merger and to allow a maximum outstanding of $3 billion. At December 31, 2015, WPZ had $499 million in outstanding commercial paper.

Accounting Standards Issued and Adopted

In April 2015, the FASB issued ASU 2015-03 “Interest - Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03). ASU 2015-03 simplifies the presentation of debt issuance costs by requiring such costs be presented as a deduction from the corresponding debt liability. Subsequently, in August 2015, the FASB issued ASU 2015-15 “Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangement-Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting” (ASU 2015-15). In ASU 2015-15 the FASB stated that the guidance in ASU 2015-03 did not address the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, and entities are permitted to defer and present debt issuance costs related to line-of-credit arrangements as assets The standards are effective for financial statements issued for interim and annual reporting periods beginning after December 15, 2015, and require retrospective presentation. Early adoption is permitted. We elected to early adopt these standards for the periods presented. Accordingly, $9.1 million and $9.8 million of debt issuance costs as of December 31, 2015 and 2014, respectively, are now reflected as a direct reduction of debt in our Consolidated Balance Sheet.

Lease Obligations

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



2016	$	13,552
2017	13,485
2018	13,480
2019	11,074
2020	11,093
Thereafter	5,037
Total net minimum obligations	$	67,721

Our lease expense was $10.7 million in 2015, $11.1 million in 2014, and $11.4 million in 2013.

4. ARO TRUST

Available-for-Sale Investments

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

Effective March 1, 2013, the annual funding obligation is approximately $36.4 million, with deposits made monthly.

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



	December 31, 2015				December 31, 2014
	Amortized Cost Basis		Fair Value		Amortized Cost Basis		Fair Value
Cash and Money Market Funds	$	3.2	$	3.2	$	2.1	$	2.1
U.S. Equity Funds	19.2		22.9		15.0		19.0
International Equity Funds	16.1		15.0		8.0		8.2
Municipal Bond Funds	25.1		25.6		17.7		18.2
Total	$	63.6	$	66.7	$	42.8	$	47.5

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5. FAIR VALUE MEASUREMENTS

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash, short-term financial assets (advances to affiliate) that have variable interest rates, accounts receivable and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.



							Fair Value Measurements Using
	Carrying Amount			Fair Value			Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
							(Millions)
Assets (liabilities) at December 31, 2015:
Measured on a recurring basis:
ARO Trust investments	$	66.7		$	66.7		$	66.7	$	—		$	—

Additional disclosures:
Notes receivable	1.1			1.1			—		1.1			—
Long-term debt	(1,419.6		)	(1,244.1		)	—		(1,244.1		)	—

Assets (liabilities) at December 31, 2014:
Measured on a recurring basis:
ARO Trust investments	$	47.5		$	47.5		$	47.5	$	—		$	—

Additional disclosures:
Notes receivable	3.8			3.8			—		3.8			—
Long-term debt	(1,418.7		)	(1,506.4		)	—		(1,506.4		)	—

Fair Value of Methods

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

ARO Trust investments - We deposit a portion of our collected rates, pursuant to the terms of the Docket No. RP12-993 rate case settlement, into the ARO Trust which is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market, are classified as available-for-sale and are reported in Other Assets-Other in the Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 4 for more information regarding the ARO Trust.

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

Long-term debt - The disclosed fair value of our long-term debt is determined by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments.

Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the year ended December 31, 2015 or 2014.

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6. BENEFIT PLANS

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

Pension and Other Postretirement Benefit Plans

Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible employees. Pension cost charged to us by Williams was $13.5 million, $11.9 million and $22.3 million for 2015, 2014, and 2013, respectively.

Williams makes annual cash contributions to the pension plans, based on annual actuarial estimates, which Transco recovers through rates that are set through periodic general rate filings. Effective with the RP12-993 Settlement, any amounts of annual contributions that exceed an upper threshold or fall below a lower threshold are recorded as adjustments to income and collected or refunded through future rate adjustments. The amount of deferred pension collections recorded as a regulatory liability at December 31, 2015 is $8.0 million. There were no deferred pension collections recorded as a regulatory liability or a regulatory asset at December 31, 2014.

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 $11.9 million, $13.7 million, and $4.2 million for 2015, 2014 and 2013, 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 expense and collected or refunded through future rate adjustments. The amount of other postretirement benefits costs deferred as a regulatory liability at December 31, 2015 and 2014 are $51.0 million and $39.1 million, respectively. These amounts are comprised of amounts being deferred for future rate treatment of $37.4 million and $23.0 million at December 31, 2015 and 2014, respectively, and amounts of $13.6 million and $16.1 million being amortized over a period of approximately 8 years per Docket No. RP12-993 at December 31, 2015 and 2014, respectively. Effective March 1, 2013, the residual regulatory asset balance from the prior rate filing was netted against the accumulated regulatory liability.

Defined Contribution Plan

Williams charged us compensation expense of $6.6 million in 2015, $6.4 million in 2014 and $6.0 million in 2013 for Williams’ company matching contributions to this plan.

Employee Stock-Based Compensation Plan Information

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

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

Total stock-based compensation expense for the years ended December 31, 2015, 2014 and 2013 was $4.0 million, $3.0 million and $3.0 million, respectively, excluding amounts allocated from WPZ and Williams.

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7. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES

Major Customers

Operating revenues received from two of our major customers in 2015, 2014 and 2013 are as follows (in millions):



	2015		2014		2013
National Grid	$	129.6	$	91.2	$	88.5
Public Service Enterprise Group	110.2		115.3		130.7

Affiliates

We are a participant in WPZ’s cash management program, and we make advances to and receive advances from WPZ. At December 31, 2015 and 2014, our advances to WPZ totaled approximately $64.6 million and $306.9 million, respectively. These advances are represented by demand notes and are classified as Current Assets in the accompanying Consolidated Balance Sheet. Advances are stated at the historical carrying amounts. Interest income is recognized when chargeable and collectability is reasonably assured. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on WPZ’s excess cash at the end of each month. At December 31, 2015, the interest rate was 0.12 percent.

Included in Operating Revenues in the accompanying Consolidated Statement of Comprehensive Income for 2015, 2014 and 2013 are revenues received from affiliates of $4.6 million, $8.3 million, and $16.3 million, respectively. The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.

Included in Cost of natural gas sales in the accompanying Consolidated Statement of Comprehensive Income for 2015, 2014 and 2013 is purchased gas cost from affiliates of $6.0 million, $10.5 million, and $6.9 million, respectively. All gas purchases are made at market or contract prices.

We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams and its affiliates for all direct and indirect expenses incurred or payments made (including salary, bonus, incentive compensation and benefits) in connection with these services. Employees of Williams also provide general, administrative and management services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. We were billed $327.1 million, $310.1 million, and $310.3 million during 2015, 2014 and 2013, respectively, for these services. Such expenses are primarily included in Administrative and general and Operation and maintenance expenses in the accompanying Consolidated Statement of Comprehensive Income.

We provide services to certain of our affiliates. We recorded reductions in operating expenses for services provided to and reimbursed by our affiliates of $5.7 million, $6.6 million, and $7.1 million in 2015, 2014 and 2013, respectively. In 2013, we received $3.6 million of reimbursements from Williams Field Services Group, LLC (WFS), related to a capital project. Pursuant to construction agreements, we received pre-payments from WFS of $5.0 million during 2014 associated with capital projects. In 2015, we acquired certain assets from WFS for $1.9 million.

We made equity distributions of $536 million, $411 million and $250 million during 2015, 2014 and 2013, respectively. In January 2016, an additional distribution of $175 million was declared and paid.

During 2015, 2014 and 2013, our parent made contributions totaling $652 million, $267 million and $264 million, respectively, to us to fund a portion of our expenditures for additions to property, plant and equipment. In January 2016, our parent made an additional $112 million contribution.

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8. ASSET RETIREMENT OBLIGATIONS

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

During 2015 and 2014, our overall asset retirement obligation changed as follows (in thousands):



	2015			2014
Beginning balance	$	296,475		$	273,987
Accretion	25,178			17,962
New obligations	256			1,346
Changes in estimates of existing obligations (1)	3,691			23,031
Property dispositions/obligations settled	(2,574		)	(19,851		)
Ending balance	$	323,026		$	296,475

(1)

Changes in estimates of existing obligations are primarily due to the annual review process, which considers various factors including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining life of assets. The changes in estimates of existing obligations reflect an increase of $4 million and $23 million for 2015 and 2014, respectively, due to revisions in the estimated remaining life of assets, inflation rates, discount rates, and current estimates for removal costs.

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

9. REGULATORY ASSETS AND LIABILITIES

The regulatory assets and regulatory liabilities resulting from our application of the provisions of ASC Topic 980, Regulated Operations, included in the accompanying Consolidated Balance Sheet at December 31, 2015 and December 31, 2014 are as follows (in millions):



Regulatory Assets	2015		2014
Grossed-up deferred taxes on equity funds used during construction	$	75.8	$	78.4
Asset retirement obligations	113.5		115.9
Asset retirement costs - Eminence	58.8		63.2
Deferred taxes	5.9		7.0
Deferred cash out	43.9		12.9
Deferred gas costs	—		8.7
Fuel cost	43.8		29.2
Other	1.6		1.6
Total Regulatory Assets	$	343.3	$	316.9

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Regulatory Liabilities	2015		2014
Negative salvage	$	318.3	$	283.8
Sentinel meter station depreciation	6.0		5.8
Postretirement benefits other than pension	51.0		39.1
Electric power cost	0.8		4.4
Pension - deferred collections	8.0		—
Other	1.8		—
Total Regulatory Liabilities	$	385.9	$	333.1

The significant regulatory assets and liabilities include:

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

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

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

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

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.

Deferred gas costs: This amount arises from the movement of gas volumes between gas inventory accounts that have different valuations. These amounts are expected to be recovered/refunded in subsequent periods.

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.

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

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

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

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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.

Pension - deferred collections: We recover the actuarially determined pension cash contributions through rates that are set through periodic general rate filings. Effective with the RP12-993 Settlement, any amounts of annual contributions that exceed an upper threshold or fall below a lower threshold are recorded as adjustments to income and collected or refunded through future rate adjustments.

10. OTHER

During 2014, we capitalized $3.5 million of project feasibility costs associated with the various projects, which had been expensed in prior periods in Other expense, net, upon determining that the projects were probable of development.

We detected a leak in an underground cavern at our Eminence Storage Field in Mississippi on December 28, 2010. During 2014 and 2013, we recorded $0.8 million and $4.3 million, respectively, of charges to Operation and maintenance expenses primarily related to costs to ensure the safety of the surrounding area.

Due to the abandonment and retirement of four of the seven caverns at our Eminence Storage Field in 2013 and the expected recovery of such costs in our rates, we reclassified $92 million of costs related to the Eminence ARO from Total property, plant and equipment, net to Regulatory assets (Eminence abandonment regulatory asset). Included in Other expense, net, for the year 2013, consistent with the stipulation and agreement in our Docket No. RP12-993 general rate case proceeding, was a charge of $11.5 million, related to the estimated portion of the Eminence abandonment regulatory asset that will not be recovered in rates; which was reduced by $2.9 million in 2014 upon completion of the abandonment. We also recognized income during 2013 of $16.1 million, related to insurance recoveries associated with this event.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC

QUARTERLY FINANCIAL DATA (UNAUDITED)

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



2015	First (1)			Second (2)			Third (3)			Fourth (4)
Operating revenues	$	380,023		$	390,921		$	414,568		$	407,007
Operating expenses	246,205			243,859			257,480			257,823
Operating income	133,818			147,062			157,088			149,184
Interest expense	20,807			20,656			20,675			20,700
Other (income) and deductions, net	(15,807		)	(16,391		)	(19,094		)	(19,851		)
Net income	128,818			142,797			155,507			148,335
Equity interest in unrealized gain (loss) on interest rate hedge	(53		)	50			(167		)	254
Comprehensive income	$	128,765		$	142,847		$	155,340		$	148,589



2014	First			Second			Third			Fourth (5)
Operating revenues	$	365,662		$	338,454		$	352,799		$	376,222
Operating expenses	235,980			218,711			240,481			265,127
Operating income	129,682			119,743			112,318			111,095
Interest expense	21,959			21,197			20,954			20,877
Other (income) and deductions, net	(4,057		)	(6,943		)	(11,378		)	(12,655		)
Net income	111,780			105,489			102,742			102,873
Equity interest in unrealized gain (loss) on interest rate hedge	38			(41		)	159			(13		)
Comprehensive income	$	111,818		$	105,448		$	102,901		$	102,860


(1)	Includes a $3.0 million increase to operating expenses to establish a regulatory liability associated with rate collections in excess of our pension funding obligation.


(2)	Includes a $1.0 million increase to operating expenses to establish a regulatory liability associated with rate collections in excess of our pension funding obligation.


(3)	Includes a $2.0 million increase to operating expenses to establish a regulatory liability associated with rate collections in excess of our pension funding obligation.


(4)	Includes a $2.0 million increase to operating expenses to establish a regulatory liability associated with rate collections in excess of our pension funding obligation.


(5)	Includes a $3.1 million increase to operating expenses related to a measurement adjustment and a $2.9 million decrease to operating expenses related to Eminence abandonment costs reduction.

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

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

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

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

There have been no changes during the fourth quarter of 2015 that have materially affected, or are reasonably likely to materially affect, our Internal Control over Financial Reporting.

Management’s Annual Report on Internal Control over Financial Reporting

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

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

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Under the supervision and with the participation of our management, including our Senior Vice President – Atlantic-Gulf and our Vice President and Chief Accounting Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2015, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we concluded that, as of December 31, 2015, 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 us to provide only management’s report in this annual report.

Item 9B. Other information

None.

PART III

Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K, the information required by Items 10, 11, 12, and 13, is omitted.

Items 14. Principal Accounting Fees and Services

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



	2015		2014
Audit fees	$	1,460	$	1,499
Audit-related fees	—		—
Tax fees	—		—
All other fees	78		—
Total fees	$	1,538	$	1,499

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

As a wholly owned subsidiary of WPZ, we do not have a separate audit committee. The policies and procedures for pre-approving audit and non-audit services of the Audit Committee of the Board of Directors of WPZ’s general partner have been set forth in WPZ’s 2015 annual report on Form 10-K, which is available on the SEC’s website at http://www.sec.gov and on http://investor.williams.com.

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PART IV

Item 15. Exhibits and Financial Statement Schedules



	Page Reference to 2015 10-K
A. 1 and 2. Transcontinental Gas Pipe Line Company, LLC financials

Index

Covered by Report of Independent Registered Public Accounting Firm:

Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2015, 2014 and 2013	28

Consolidated Balance Sheet as of December 31, 2015 and 2014	29

Consolidated Statement of Owner’s Equity for the Years Ended December 31, 2015, 2014 and 2013	31

Consolidated Statement of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013	32

Notes to Consolidated Financial Statements	34

Not covered by Report of Independent Registered Public Accounting Firm:

Quarterly Financial Data (Unaudited)	50

The following schedules are omitted because of the absence of the conditions under which they are required: I, II, III, IV, and V.

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3. Exhibits:



Exhibit Number		Description

2		Certificate of Conversion dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 2.1 to our annual report on Form 10-K (File No. 001-07584) and incorporated herein by reference).

3.1		Certificate of Formation dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 3.1 to our annual report on Form 10-K (File No. 001-07584) and incorporated herein by reference).

3.2		Amended and Restated Operating Agreement of Transcontinental Gas Pipe Line Company, LLC dated February 17, 2010 (filed on October 28, 2010 as Exhibit 3.2 to our quarterly report on Form 10-Q (File No. 001-07584) and incorporated herein by reference).

4.1		Senior Indenture dated July 15, 1996 between Transco and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to our registration statement Form S-3 (File No. 333-02155) and incorporated herein by reference).

4.2		Indenture dated April 11, 2006 between Transco and JP Morgan Chase Bank, N.A., as Trustee (filed on April 11, 2006 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).

4.3		Indenture, dated as of May 22, 2008 between Transco and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).

4.4		Indenture, dated as of August 12, 2011 between Transco and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on August 12, 2011 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).

4.5		Indenture, dated as of July 13, 2012, between Transco and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on July 16, 2012 as Exhibit 4.1 to our current report Form 8-K (File No. 001-07584) and incorporated herein by reference).

4.6		Indenture, dated as of January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on January 22, 2016 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).

10.1		Administrative Services Agreement, dated as of February 17, 2010, by and between Transco Pipeline Services LLC and Transco (filed on February 22, 2010 as Exhibit 10.3 to Williams Partners L.P.’s, Form 8-K (File No. 001-32599) and incorporated herein by reference).

10.2		Assignment Agreement dated February 13, 2013 by and between Transco Pipeline Services LLC and Williams WPC-I, LLC, effective January 1, 2013 (filed on February 27, 2013 as Exhibit 10.2 to our annual report on Form 10-K and incorporated herein by reference).

10.3		Second Amended and Restated Credit Agreement dated as of February 2, 2015, between Williams Partners L.P. (formerly known as Access Midstream Partners, L.P.), Northwest Pipeline LLC, Transcontinental Gas Pipeline Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on February 3, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

10.4		Amendment No. 1 to Second Amended & Restated Credit Agreement dated December 18, 2015, between Williams Partners L.P., Northwest Pipeline LLC, Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on December 23, 2015 as Exhibit 10.1 to our Form 8-K (File No. 001-07584) and incorporated herein by reference).

10.5		Registration Rights Agreement, dated January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC and the initial purchasers listed therein (filed on January 22, 2016 as Exhibit 10.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference)

Table of Contents



31.1*		Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32 **		Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.



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

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase.



* Filed herewith. ** Furnished herewith.

Table of Contents

SIGNATURES

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



TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC (Registrant)

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

Date: February 24, 2016

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



Signature		Title
/s/ Rory L. Miller		Management Committee Member and Senior Vice President – Atlantic-Gulf (Principal Executive Officer)
Rory L. Miller

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

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

/s/ Frank J. Ferazzi		Management Committee Member and Vice President
Frank J. Ferazzi		Management Committee Member and Vice President

Date: February 24, 2016

Table of Contents

INDEX OF EXHIBITS



Exhibit Number		Description

2		Certificate of Conversion dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 2.1 to our annual report on Form 10-K (File No. 001-07584) and incorporated herein by reference).

3.1		Certificate of Formation dated December 22, 2008 and effective December 31, 2008 (filed on February 24, 2011 as Exhibit 3.1 to our annual report on Form 10-K (File No. 001-07584) and incorporated herein by reference).

3.2		Amended and Restated Operating Agreement of Transcontinental Gas Pipe Line Company, LLC dated February 17, 2010 (filed on October 28, 2010 as Exhibit 3.2 to our quarterly report on Form 10-Q (File No. 001-07584) and incorporated herein by reference).

4.1		Senior Indenture dated July 15, 1996 between Transco and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to our registration statement Form S-3 (File No. 333-02155) and incorporated herein by reference).

4.2		Indenture dated April 11, 2006 between Transco and JP Morgan Chase Bank, N.A., as Trustee (filed on April 11, 2006 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).

4.3		Indenture, dated as of May 22, 2008 between Transco and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).

4.4		Indenture, dated as of August 12, 2011 between Transco and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on August 12, 2011 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).

4.5		Indenture, dated as of July 13, 2012, between Transco and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on July 16, 2012 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).

4.6		Indenture, dated as of January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on January 22, 2016 as Exhibit 4.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).

10.1		Administrative Services Agreement, dated as of February 17, 2010, by and between Transco Pipeline Services LLC and Transco (filed on February 22, 2010 as Exhibit 10.3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

10.2		Assignment Agreement dated February 13, 2013 by and between Transco Pipeline Services LLC and Williams WPC-I, LLC, effective January 1, 2013 (filed on February 27, 2013 as Exhibit 10.2 to our annual report on Form 10-K and incorporated herein by reference).

10.3		Second Amended and Restated Credit Agreement dated as of February 2, 2015, between Williams Partners L.P. (formerly known as Access Midstream Partners, L.P.), Northwest Pipeline LLC, Transcontinental Gas Pipeline Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on February 3, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

10.4		Amendment No. 1 to Second Amended & Restated Credit Agreement dated December 18, 2015, between Williams Partners L.P., Northwest Pipeline LLC, Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on December 23, 2015 as Exhibit 10.1 to our Form 8-K (File No. 001-07584) and incorporated herein by reference).

10.5		Registration Rights Agreement, dated January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC and the initial purchasers listed therein (filed on January 22, 2016 as Exhibit 10.1 to our current report on Form 8-K (File No. 001-07584) and incorporated herein by reference)

Table of Contents



31.1*		Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32 **		Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.



101.INS*		XBRL Instance Document.

101.I SCH *		XBRL Taxonomy Extension Schema.

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase.

101.DEF*		XBRL Taxonomy Extension Definition Linkbase.

101.LAB*		XBRL Taxonomy Extension Label Linkbase.

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase.



* Filed herewith. ** Furnished herewith.

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC - FORM 10-K - February 24, 2016

Attached files

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC Reports