10-K

\

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)
þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2013
OR
¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIESEXCHANGE ACT OF 1934
	For the transition period from  to

Commission file number 1-32599

WILLIAMS PARTNERS L.P.

(Exact Name of Registrant as Specified in Its Charter)

Delaware	20-2485124
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)
One Williams Center, Tulsa, Oklahoma	74172-0172
(Address of Principal Executive Offices)	(Zip Code)

918-573-2000

(Registrant’s Telephone Number, Including Area Code)

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

Title of Each Class	Name of Each Exchange on Which Registered
Common Units	New York Stock Exchange

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

None

(Title of Class)

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

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 Filerequired 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 shorterperiod 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 becontained, 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 anyamendment 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. Seethe definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ	Accelerated filer ¨	Non-accelerated filer ¨	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

The aggregate market value of the registrant’s common units held by non-affiliates based on the closing sale price of such units as reported on the New York Stock Exchange, as of the last business day of the registrant’s most recently completed second quarter was approximately $6,919,922,129.

The registrant had 438,625,699 common units outstanding as of February 25, 2014.

DOCUMENTS INCORPORATED BY REFERENCE

None

WILLIAMS PARTNERS L.P.

FORM 10-K

TABLE OF CONTENTS

		Page
	PART I
Item 1.	Business	4
	Website Access to Reports and Other Information	4
	General	4
	Canada Dropdown	4
	Financial Information About Segments	4
	Business Segments	5
	Northeast G&P	5
	Atlantic-Gulf	6
	West	8
	NGL & Petchem Services	10
	Service Assets, Customers, and Contracts	11
	Regulatory Matters	13
	Environmental Matters	16
	Competition	16
	Employees	17
	Financial Information about Geographic Areas	17
Item 1A.	Risk Factors	18
Item 1B.	Unresolved Staff Comments	39
Item 2.	Properties	39
Item 3.	Legal Proceedings	39
Item 4.	Mine Safety Disclosures	40
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	41
Item 6.	Selected Financial Data	43
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	44
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	74
Item 8.	Financial Statements and Supplementary Data	75
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	117
Item 9A.	Controls and Procedures	117
Item 9B.	Other Information	120
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	120
Item 11.	Executive Compensation	128
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	131
Item 13.	Certain Relationships and Related Transactions, and Director Independence	134
Item 14.	Principal Accountant Fees and Services	138
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	138

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DEFINITIONS

The following is a listing of certain abbreviations, acronyms and other industry terminology used throughout this Annual Report.

Measurements:

Barrel: One barrel of petroleum products that equals 42 U.S. gallons

BPD: Barrels per day

Bcf : One billion cubic feet of natural gas

Bcf/d: One billion cubic feet of natural gas per day

British Thermal Unit (Btu): A unit of energy needed to raise the temperature of one pound of water by one degree

Fahrenheit

Dekatherms (Dth): A unit of energy equal to one million British thermal units

Mbbls/d: One thousand barrels per day

Mdth/d: One thousand dekatherms per day

MMcf/d: One million cubic feet per day

MMdth: One million dekatherms or approximately one trillion British thermal units

MMdth/d: One million dekatherms per day

TBtu: One trillion British thermal units

Consolidated Entities:

Constitution: Constitution Pipeline Company, LLC

Gulfstar One: Gulfstar One LLC

Northwest Pipeline: Northwest Pipeline, LLC

Transco: Transcontinental Gas Pipe Line Company, LLC

Partially Owned Entities: Entities in whichwe do not own a 100 percent ownership interest and which we account

for as an equity investment, including principally the following:

Aux Sable: Aux Sable Liquid Products LP

Caiman II: Caiman Energy II, LLC

Discovery: Discovery Producer Services LLC

Gulfstream: Gulfstream Natural Gas System, L.L.C.

Laurel Mountain: Laurel Mountain Midstream, LLC

OPPL: Overland Pass Pipeline Company LLC

Government and Regulatory:

EPA: Environmental Protection Agency

Exchange Act, the: Securities and Exchange Act of 1934, as amended

FERC: Federal Energy Regulatory Commission

IRS: Internal Revenue Service

SEC: Securities and Exchange Commission

Other:

B/B Splitter: Butylene/Butane splitter

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Caiman Acquisition: Our April 2012 purchase of 100 percent of Caiman Eastern Midstream, LLC located in the

Ohio River Valley area of the Marcellus Shale region

DAC: Debutanized aromatic concentrate

Fractionation: The process by which a mixed stream of natural gas liquids is separated into its constituent products,

such as ethane, propane, and butane

IDR: Incentive distribution right

Laser Acquisition: Our February 2012 purchase from Delphi Midstream Partners, LLC of 100 percent of certain

entities that operate in Susquehanna County, PA and southern New York

LNG: Liquefied natural gas; natural gas which has been liquefied at cryogenic temperatures

NGLs: Natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are

used as petrochemical feedstocks, heating fuels, and gasoline additives, among other applications

NGL margins:NGL revenues less Btu replacement cost, plant fuel, transportation, and fractionation

NYSE: New York Stock Exchange

Throughput: The volume of product transported or passing through a pipeline, plant, terminal, or other facility

Williams: The Williams Companies, Inc.

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PART I

Item 1.Business

Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or like terms refer to Williams Partners L.P. and its subsidiaries. Unless the context clearly indicates otherwise, references to “we,” “our,” and “us” include the operations of our Partially Owned Entities in which we own interests accounted for as equity investments that are not consolidated in our financial statements. When we refer to our Partially Owned Entities by name, we are referring exclusively to their businesses and operations.

WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION

We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other documents electronically with the SEC under the Exchange Act. These reports include, among other disclosures, information on any transactions we may engage in with our general partner and its affiliates and on fees and other amounts paid or accrued to our general partner and its affiliates. You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also obtain such reports from the SEC’s Internet website at www.sec.gov.

Our Internet website is www.williamslp.com. We make available free of charge through our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our Corporate Governance Guidelines, Code of Business Conduct and Ethics and the charter of the Audit Committee of our general partner’s Board of Directors are also available on our Internet website under the “Corporate Responsibility” tab. We will also provide, free of charge, a copy of any of our governance documents listed above upon written request to our general partner’s Corporate Secretary at Williams Partners L.P., One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.

GENERAL

We are a publicly traded Delaware limited partnership formed by Williams in 2005. We were formed to own, operate and acquire a diversified portfolio of complementary energy assets. We focus on natural gas transportation; gathering, treating, and processing; storage; NGL fractionation; olefins production; and oil transportation. As of December 31, 2013,Williams owns an approximate 62 percent limited partnership interest in us and all of our 2 percent general partner interest.

Williams is an energy infrastructure company that trades on the NYSE under the symbol “WMB.”

Our principal executive offices are located at One Williams Center, Tulsa, Oklahoma 74172. Our telephone number is 918-573-2000.

CANADA DROPDOWN

In February 2014, we agreed to acquire certain of Williams’ Canadian operations, including an oil sands offgas processing plant near Fort McMurray, Alberta, an NGL/olefin fractionation facility and B/B Splitter at Redwater, Alberta and the Boreal pipeline. The transaction is expected to close in February 2014. We expect to fund the transaction with $25 million of cash, the issuance of 25,577,521 Class D limited-partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. In lieu of cash distributions, the Class D units will receive quarterly distributions of additional paid-in-kind Class D units, all of which will be convertible to common units at a future date. The agreement also provides that we can issue additional Class D units to Williams on a quarterly basis through 2015 for up to a total of $200 million in cash for the purpose of funding certain facility expansions.

FINANCIAL INFORMATION ABOUT SEGMENTS

See Part II, Item 8 — Financial Statements and Supplementary Data.

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BUSINESS SEGMENTS

Operations of our businesses are located in North America. We manage our business and analyze our results of operations on a segment basis. Our operations are divided into four business segments:

• Northeast G&P — this segment includes our natural gas gathering and processing and NGL fractionation businesses in the Marcellus and Utica shale regions, as well as a 51 percent equity investment in Laurel Mountain and a 47.5 percent equity investment in Caiman II.

• Atlantic-Gulf — this segment includes our interstate natural gas pipeline, Transco, and significant natural gas gathering and processing and crude oil production handling and transportation in the Gulf Coast region, as well as a 50 percent equity investment in Gulfstream, a 41 percent interest in Constitution (a consolidated entity), and a 60 percent equity investment in Discovery.

• West — this segment includes our natural gas gathering, processing and treating operations in New Mexico, Colorado, and Wyoming and our interstate natural gas pipeline, Northwest Pipeline.

• NGL & Petchem Services — this segment includes our NGL and natural gas marketing business, an NGL fractionator and storage facilities near Conway, Kansas, a 50 percent equity investment in OPPL, and an 83.3 percent undivided interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf Coast region.

Detailed discussion of each of our business segments follows. For a discussion of our ongoing expansion projects, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Northeast G&P

This segment includes our natural gas gathering and processing and NGL fractionation business in the Marcellus and Utica shale regions in Pennsylvania, West Virginia, New York, and Ohio.

The following tables summarize our significant operated assets as of December 31, 2013:

	Natural Gas Gathering Assets
			Inlet
		Pipeline	Capacity	Ownership
	Location	Miles	(Bcf/d)	Interest	Supply Basins
Ohio Valley	West Virginia	174	0.8	100%	Appalachian
Susquehanna Supply Hub	Pennsylvania & New York	277	2.3	100%	Appalachian
Laurel Mountain (1)	Pennsylvania	2,044	0.7	51%	Appalachian

_________

(1) Statistics reflect 100 percent of the assets from the jointly owned investment that we operate; however, our financial statements report equity method income from this investment based on our equity ownership percentage.

	Natural Gas Processing Facilities
			NGL
		Inlet	Production
		Capacity	Capacity	Ownership
	Location	(Bcf/d)	(Mbbls/d)	Interest	Supply Basins
Fort Beeler	Marshall County, WV	0.5	62	100%	Appalachian

Laurel Mountain

We own a 51 percent equity interest in a joint venture, Laurel Mountain, that includes a gathering system that we operate in western Pennsylvania. Laurel Mountain has a long-term, dedicated, volumetric-based fee agreement, with exposure to natural gas prices, to gather the anchor customer’s production in the western Pennsylvania area of the

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Marcellus Shale.

Caiman II

We own a 47.5 percent equity interest in Caiman II. We, along with Caiman Energy, LLC and others are working to develop large-scale natural gas gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale, primarily in Ohio and northwest Pennsylvania. Caiman II is engaged in the construction of the Blue Racer Midstream project, a joint project between Caiman II and Dominion to serve oil and gas producers in the Utica Shale, primarily in Ohio and Northwest Pennsylvania. Caiman II owns a 48 percent interest in the Blue Racer Midstream project whose assets include nearly 600 miles of large-diameter gathering pipelines that span the Utica Shale, the Natrium complex in Marshall County, West Virginia, and a transmission pipeline connecting Natrium to the gathering system. The Natrium complex currently includes a 200 MMcf/d cryogenic processing plant and a 46,000 Bbls/d fractionator. Expansion plans include the addition of Natrium II, a second 200 MMcf/d processing plant, at Natrium by the end of the first quarter of 2014. Construction of an additional 200 MMcf/d processing plant is underway at the Berne complex in Monroe County, Ohio. Berne I is expected to come online in the third quarter of 2014.

Operating Statistics

	2013	2012	2011
Volumes: (1)
Gathering (Tbtu)	606	340	141
Plant inlet natural gas volumes (Tbtu)	105	55	n/a
NGL production volumes (Mbbls/d) (2)	9	7	n/a

__________

(1) Excludes volumes associated with Partially Owned Entities.

(2) Annual average Mbbls/d.

Atlantic-Gulf

This segment includes an interstate natural gas pipeline that extends from the Gulf of Mexico to the eastern seaboard, as well as natural gas gathering, processing and treating, production handling, and NGL fractionation assets within the onshore, offshore shelf, and deepwater areas in and around the Gulf Coast states of Texas, Louisiana, Mississippi, and Alabama.

Transco

Transco is an interstate natural gas transmission company that owns and operates a 9,700-mile natural gas pipeline system extending from Texas, Louisiana, Mississippi and the offshore 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 12 southeast and Atlantic seaboard states, including major metropolitan areas in Georgia, North Carolina, Washington, D.C., Maryland, New York, New Jersey and Pennsylvania.

At December 31, 2013, Transco’s system had a mainline delivery capacity of approximately 5.9 MMdth of natural gas per day from its production areas to its primary markets, including delivery capacity from the mainline to locations on its Mobile Bay Lateral. Using its Leidy Line along with market-area storage and transportation capacity, Transco can deliver an additional 4.3 MMdth of natural gas per day for a system-wide delivery capacity total of approximately 10.2 MMdth of natural gas per day. Transco’s system includes 45 compressor stations, four underground storage fields, and an LNG storage facility. Compression facilities at sea level-rated capacity total approximately 1.7 million horsepower.

Transco has natural gas storage capacity in four underground storage fields located on or near its pipeline system or market areas and operates two of these storage fields. Transco also has storage capacity in an LNG storage facility that we own and operate. The total usable gas storage capacity available to Transco and its customers in such underground

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storage fields and LNG storage facility and through storage service contracts is approximately 200 Bcf of natural gas. At December 31, 2013, our customers had stored in our facilities approximately 143 Bcf of natural gas. In addition, wholly owned subsidiaries of Transco operate and hold a 35 percent ownership interest in Pine Needle LNG Company, LLC, an LNG storage facility with 4 Bcf of storage capacity. Storage capacity permits Transco’s customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter demand periods.

Gulfstream

Gulfstream is an interstate natural gas pipeline system extending from the Mobile Bay area in Alabama to markets in Florida. We own, through a subsidiary, a 50 percent interest in Gulfstream. Spectra Energy Corporation, through its subsidiary, Spectra Energy Partners, LP, owns the other 50 percent interest. We share operating responsibilities for Gulfstream with Spectra Energy Corporation.

Discovery

We own a 60 percent equity interest in and operate the facilities of Discovery. Discovery’s assets include a 600

MMcf/d cryogenic natural gas processing plant near Larose, Louisiana, a 32 Mbbls/d NGL fractionator plant near Paradis, Louisiana, and an offshore natural gas gathering and transportation system in the Gulf of Mexico. Construction is in progress for the Keathley Canyon Connector, a deepwater lateral pipeline in the central deepwater Gulf of Mexico. The lateral pipeline is estimated to have the capacity to flow more than 400 MMcf/d and will accommodate the tie-in of other deepwater prospects.

Gathering & ProcessingAssets

The following tables summarize our significant operated assets as of December 31, 2013:

	Natural Gas Gathering Assets
			Inlet
		Pipeline	Capacity	Ownership
	Location	Miles	(Bcf/d)	Interest	Supply Basins
Canyon Chief & Blind Faith	Deepwater Gulf of Mexico	139	0.5	100%	Eastern Gulf of Mexico
Seahawk	Deepwater Gulf of Mexico	115	0.4	100%	Western Gulf of Mexico
Perdido Norte	Deepwater Gulf of Mexico	105	0.3	100%	Western Gulf of Mexico
Offshore shelf & other	Gulf of Mexico	46	0.2	100%	Eastern Gulf of Mexico
Offshore shelf & other	Gulf of Mexico	208	1.1	100%	Western Gulf of Mexico
Discovery (1)	Gulf of Mexico	358	0.6	60%	Central Gulf of Mexico

	Natural Gas Processing Facilities
			NGL
		Inlet	Production
		Capacity	Capacity	Ownership
	Location	(Bcf/d)	(Mbbls/d)	Interest	Supply Basins
Markham	Markham, TX	0.5	45	100%	Western Gulf of Mexico
Mobile Bay	Coden, AL	0.7	30	100%	Eastern Gulf of Mexico
Discovery (1)	Larose, LA	0.6	32	60%	Central Gulf of Mexico

_________

(1) Statistics reflect 100 percent of the assets from the jointly owned investment that we operate; however, our financial statements report equity method income from this investment based on our equity ownership percentage.

Crude Oil Transportation and Production Handling Assets

In addition to our natural gas assets, we own and operate four deepwater crude oil pipelines and own production platforms serving the deepwater in the Gulf of Mexico. Our offshore floating production platforms provide centralized

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services to deepwater producers such as compression, separation, production handling, water removal, and pipeline landings.

The following tables summarize our significant crude oil transportation pipelines and production handling platforms as of December 31, 2013:

	Crude Oil Pipelines
	Pipeline	Capacity	Ownership
	Miles	(Mbbls/d)	Interest	Supply Basins
Mountaineer & Blind Faith	155	150	100%	Eastern Gulf of Mexico
BANJO	57	90	100%	Western Gulf of Mexico
Alpine	96	85	100%	Western Gulf of Mexico
Perdido Norte	74	150	100%	Western Gulf of Mexico

	Production Handling Platforms
			Crude/NGL
		Gas Inlet	Handling
		Capacity	Capacity	Ownership
		(MMcf/d)	(Mbbls/d)	Interest	Supply Basins
Devils Tower		210	60	100%	Eastern Gulf of Mexico
Discovery Grand Isle 115 (1)		150	10	60%	Central Gulf of Mexico

_________

(1) Statistics reflect 100 percent of the assets from the jointly owned investment that we operate; however, our financial statements report equity method income from this investment based on our equity ownership percentage.

Operating Statistics

	2013	2012	2011
Volumes: (1)
Interstate natural gas pipeline throughput (Tbtu)	3,153	2,774	2,408
Gathering (Tbtu)	137	163	133
Plant inlet natural gas (Tbtu)	270	303	247
NGL production (Mbbls/d) (2)	34	42	30
NGL equity sales (Mbbls/d) (2)	7	9	9
Crude oil transportation (Mbbls/d) (2)	117	126	105

_____________

(1) Excludes volumes associated with Partially Owned Entities.

(2) Annual average Mbbls/d.

West

This segment includes an interstate natural gas pipeline, as well as natural gas gathering and processing assets in Colorado, New Mexico, and Wyoming.

Northwest Pipeline

Northwest Pipeline is an interstate natural gas transmission company that owns and operates a natural gas pipeline system extending from the San Juan basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon, and Washington to a point on the Canadian border near Sumas, Washington. Northwest Pipeline provides services for markets in Washington, Oregon, Idaho, Wyoming, Nevada, Utah, Colorado, New Mexico, California, and Arizona directly or indirectly through interconnections with other pipelines.

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At December 31, 2013, Northwest Pipeline’s system, having long-term firm transportation and storage redelivery agreements of approximately 3.9 MMdth/d, was composed of approximately 3,900 miles of mainline and lateral transmission pipelines and 41 transmission compressor stations having a combined sea level-rated capacity of approximately 472,000 horsepower.

Northwest Pipeline owns a one-third interest in the Jackson Prairie underground storage facility in Washington and contracts with a third party for storage service in the Clay basin underground field in Utah. Northwest Pipeline also owns and operates an LNG storage facility in Washington. These storage facilities have an aggregate working gas storage capacity of 14.2 MMdth of natural gas, which is substantially utilized for third-party natural gas. These natural gas storage facilities enable Northwest Pipeline to balance daily receipts and deliveries and provide storage services to certain customers.

Gas Gathering & Processing Assets

The following tables summarize our significant operated assets as of December 31, 2013:

	Natural Gas Gathering Assets
			Inlet
		Pipeline	Capacity	Ownership
	Location	Miles	(Bcf/d)	Interest	Supply Basins
Rocky Mountain	Wyoming	3,587	1.1	100%	Wamsutter & SW Wyoming
Four Corners	Colorado & New Mexico	3,841	1.8	100%	San Juan
Piceance	Colorado	328	1.4	(1)	Piceance

__________

(1) We own 60 percent of a gathering system in the Ryan Gulch area, which we operate, with 140 miles of pipeline and 200 MMcf/d of inlet capacity. We own and operate 100 percent of the balance of the Piceance gathering system.

	Natural Gas Processing Facilities
			NGL
		Inlet	Production
		Capacity	Capacity	Ownership
	Location	(Bcf/d)	(Mbbls/d)	Interest	Supply Basins
Opal	Opal, WY	1.5	70	100%	SW Wyoming
Echo Springs	Echo Springs, WY	0.7	58	100%	Wamsutter
Ignacio	Ignacio, CO	0.5	23	100%	San Juan
Kutz	Bloomfield, NM	0.2	12	100%	San Juan
Willow Creek	Rio Blanco County, CO	0.5	30	100%	Piceance
Parachute	Garfield County, CO	1.3	7	100%	Piceance

In addition, we own and operate natural gas treating facilities in New Mexico and Colorado, which bring natural gas to specifications allowable by major interstate pipelines. At our Milagro treating facility we use gas-driven turbines that have the capacity to produce 60 mega-watts per day of electricity which we primarily sell into the local electrical grid.

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Operating Statistics

	2013	2012	2011
Interstate natural gas pipeline throughput (Tbtu)	717	658	638
Gathering volumes (Tbtu)	988	1,111	1,103
Plant inlet natural gas volumes (Tbtu)	1,174	1,281	1,345
NGL production volumes (Mbbls/d) (1)	100	160	159
NGL equity sales volumes (Mbbls/d) (1)	33	68	68

__________

(1) Annual average Mbbls/d.

NGL & Petchem Services

Gulf Olefins

We have an 83.3 percent undivided interest and operatorship of the olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf region. Our olefins business also operates an ethylene storage hub at Mont Belvieu using leased third-party underground storage caverns.

Our olefins production facility has a total production capacity of 1.35 billion pounds of ethylene and 90 million pounds of propylene per year. Our feedstocks for the cracker are ethane and propane; as a result, these assets are primarily exposed to the price spread between ethane and propane, and ethylene and propylene, respectively. Ethane and propane are available for purchase from third parties and from affiliates. We own ethane and propane pipeline systems in Louisiana that provide feedstock transportation to the Geismar plant and other third-party crackers. We also own a pipeline that has the capacity to supply 12 Mbbls/d of ethane from Discovery’s Paradis fractionator to the Geismar plant.

On June 13, 2013, an explosion and fire occurred at our Geismar olefins plant. The incident (Geismar Incident) rendered the facility temporarily inoperable and resulted in significant human, financial, and operational effects. Repairs are underway and an expansion is planned to increase the facility’s ethylene production capacity by 600 million pounds per year. Following the repair and plant expansion, the Geismar plant is expected to be operational in June 2014. (See Management’s Discussion and Analysis of Financial Condition and Results of Operations - Overview.)

Our refinery grade propylene splitter has a production capacity of approximately 500 million pounds per year of propylene. At our propylene splitter, we purchase refinery grade propylene and fractionate it into polymer grade propylene and propane; as a result this asset is exposed to the price spread between those commodities.

As a merchant producer of ethylene and propylene, our product sales are to customers for use in making plastics and other downstream petrochemical products destined for both domestic and export markets.

Marketing Services

We market NGL products to a wide range of users in the energy and petrochemical industries. The NGL marketing business transports and markets our equity NGLs from the production at our processing plants, and also markets NGLs on behalf of third-party NGL producers, including some of our fee-based processing customers, and the NGL volumes owned by Discovery. The NGL marketing business bears the risk of price changes in these NGL volumes while they are being transported to final sales delivery points. In order to meet sales contract obligations, we may purchase products in the spot market for resale. Other than a long-term agreement to sell our equity NGLs transported on OPPL to ONEOK Hydrocarbon L.P., the majority of sales are based on supply contracts of one year or less in duration. Sales to ONEOK Hydrocarbon L.P., accounted for 10 percent, 14 percent, and 17 percent of our consolidated revenues in 2013, 2012, and 2011, respectively.

In certain situations to facilitate our gas gathering and processing activities, we buy natural gas from our producer customers for resale.

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We also market olefin products to a wide range of users in the energy and petrochemical industries. In order to meet sales contract obligations, we may purchase olefin products for resale.

Other NGL & Petchem Operations

We own interests in and/or operate NGL fractionation and storage assets. These assets include a 50 percent interest in an NGL fractionation facility near Conway, Kansas, with capacity of slightly more than 100 Mbbls/d and a 31.5 percent interest in another fractionation facility in Baton Rouge, Louisiana, with a capacity of 60 Mbbls/d. We also own approximately 20 million barrels of NGL storage capacity in central Kansas near Conway.

We own approximately 170 miles of pipelines in the Houston Ship Channel area which transport a variety of products including ethane, propane, ammonia, tertiary butyl alcohol, and other industrial products used in the petrochemical industry. We also own a tunnel crossing pipeline under the Houston Ship Channel which contains multiple pipelines which are leased to third parties.

We also own a 14.6 percent equity interest in Aux Sable and its Channahon, Illinois, gas processing and NGL fractionation facility near Chicago. The facility is capable of processing up to 2.1 Bcf/d of natural gas from the Alliance Pipeline system and fractionating approximately 102 Mbbls/d of extracted liquids into NGL products. Additionally, Aux Sable owns an 80 MMcf/d gas conditioning plant and a 12-inch, 83-mile gas pipeline infrastructure in North Dakota that provides additional NGLs to Channahon from the Bakken Shale in the Williston basin.

We also operate and own a 50 percent ownership interest in OPPL. OPPL is capable of transporting 255 Mbbls/d and includes approximately 1,096 miles of NGL pipeline extending from Opal, Wyoming, to the Mid-Continent NGL market center near Conway, Kansas, along with extensions into the Piceance and Denver-Julesberg basins in Colorado. In 2013, a pipeline connection and capacity expansions were installed to accommodate volumes coming from the Bakken Shale in the Williston basin in North Dakota. Our equity NGL volumes from our two Wyoming plants and our Willow Creek facility in Colorado are dedicated for transport on OPPL under a long-term transportation agreement.

Operating Statistics

	2013	2012	2011
Geismar ethylene sales (millions of pounds)	467	1,058	1,038

Service Assets, Customers, and Contracts

Interstate Natural Gas Pipeline Assets

Our interstate natural gas pipelines are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce are subject to regulation. The rates are established through the FERC’s ratemaking process.

Our interstate natural gas pipelines transport and store natural gas for a broad mix of customers, including local natural gas distribution companies, municipal utilities, direct industrial users, electric power generators, and natural gas marketers and producers. We have firm transportation and storage contracts that are generally long-term contracts with various expiration dates and account for the major portion of our regulated businesses. Additionally, we offer storage services and interruptible firm transportation services under short-term agreements.

Gathering, Processing and Treating Assets

Our gathering systems receive natural gas from producers’ oil and natural gas wells and gather these volumes to gas processing, treating or redelivery facilities. Typically, natural gas, in its raw form, is not acceptable for transportation in major interstate natural gas pipelines or for commercial use as a fuel. Our treating facilities remove water vapor,

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carbon dioxide and other contaminants and collect condensate, but do not extract NGLs. We are generally paid a fee based on the volume of natural gas gathered and/or treated, generally measured in the Btu heating value.

In addition, natural gas contains various amounts of NGLs, which generally have a higher value when separated from the natural gas stream. Our processing plants extract the NGLs in addition to removing water vapor, carbon dioxide and other contaminants. NGL products include:

• Ethane, primarily used in the petrochemical industry as a feedstock for ethylene production, one of the basic building blocks for plastics;

• Propane, used for heating, fuel and as a petrochemical feedstock in the production of ethylene and propylene, another building block for petrochemical-based products such as carpets, packing materials and molded plastic parts;

• Normal butane, isobutane and natural gasoline, primarily used by the refining industry as blending stocks for motor gasoline or as a petrochemical feedstock.

Our gas processing services generate revenues primarily from the following three types of contracts:

• Fee-based: We are paid a fee based on the volume of natural gas processed, generally measured in the Btu heating value. Our customers are entitled to the NGLs produced in connection with this type of processing agreement. Beginning in 2013, a portion of our fee-based processing revenues includes a share of the margins on the NGLs produced. For the year ended December 31, 2013, 72 percent of the NGL production volumes were under fee-based contracts.

• Keep-whole: Under keep-whole contracts, we (1) process natural gas produced by customers, (2) retain some or all of the extracted NGLs as compensation for our services, (3) replace the Btu content of the retained NGLs that were extracted during processing with natural gas purchases, also known as shrink replacement gas, and (4) deliver an equivalent Btu content of natural gas for customers at the plant outlet. NGLs we retain in connection with this type of processing agreement are referred to as our equity NGL production. Under these agreements, we have commodity price exposure on the difference between NGL and natural gas prices. For the year ended December 31, 2013, 26 percent of the NGL production volumes were under keep-whole contracts.

• Percent-of-Liquids: Under percent-of-liquids processing contracts, we (1) process natural gas produced by customers, (2) deliver to customers an agreed-upon percentage of the extracted NGLs, (3) retain a portion of the extracted NGLs as compensation for our services, and (4) deliver natural gas to customers at the plant outlet. Under this type of contract, we are not required to replace the Btu content of the retained NGLs that were extracted during processing, and are therefore only exposed to NGL price movements. NGLs we retain in connection with this type of processing agreement are also referred to as our equity NGL production. For the year ended December 31, 2013, 2 percent of the NGL production volumes were under percent-of-liquids contracts.

Our gathering and processing agreements have terms ranging from month-to-month to the life of the producing lease. Generally, our gathering and processing agreements are long-term agreements.

Demand for gas gathering and processing services is dependent on producers’ drilling activities, which is impacted by the strength of the economy, natural gas prices, and the resulting demand for natural gas by manufacturing and industrial companies and consumers. Our gas gathering and processing customers are generally natural gas producers who have proved and/or producing natural gas fields in the areas surrounding our infrastructure. During 2013, our facilities gathered and processed gas for approximately 220 customers. Our top five gathering and processing customers accounted for approximately 50 percent of our gathering and processing revenue.

Demand for our equity NGLs is affected by economic conditions and the resulting demand from industries using these commodities to produce petrochemical-based products such as plastics, carpets, packing materials and blending stocks for motor gasoline and the demand from consumers using these commodities for heating and fuel. NGL products

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are currently the preferred feedstock for ethylene and propylene production, which has been shifting away from the more expensive crude-based feedstocks.

Key variables for our business will continue to be:

• Retaining and attracting customers by continuing to provide reliable services;

• Revenue growth associated with additional infrastructure either completed or currently under construction;

• Disciplined growth in our core service areas and new step-out areas;

• Producer drilling activities impacting natural gas supplies supporting our gathering and processing volumes;

• Prices impacting our commodity-based activities.

Crude Oil Transportation and Production Handling Assets

Our crude oil transportation revenues are typically volumetric-based fee arrangements. However, a portion of our marketing revenues are recognized from purchase and sale arrangements whereby the oil that we transport is purchased and sold as a function of the same index-based price. Revenue sources have historically included a combination of fixed-fee, volumetric-based fee and cost reimbursement arrangements. Fixed fees associated with the resident production at our Devils Tower facility are recognized on a units-of-production basis.

Significant Service Revenues

Revenues by service that exceeded 10 percent of consolidated revenue include:

	2013	2012	2011
Service:	(Millions)
Regulated natural gas transportation and storage	1,713	1,609	1,569
Gathering & processing	932	844	703

REGULATORY MATTERS

Gas Pipeline and Midstream Gathering

FERC

Our gas pipeline interstate transmission and storage activities are subject to FERC regulation under the Natural Gas Act of 1938 (NGA) and under the Natural Gas Policy Act of 1978, and, as such, its rates and charges for the transportation of natural gas in interstate commerce, its accounting, and the extension, enlargement or abandonment of its jurisdictional facilities, among other things, are subject to regulation. Each gas pipeline company holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities and properties for which certificates are required under the NGA. FERC Standards of Conduct govern how our interstate pipelines communicate and do business with gas marketing employees. Among other things, the Standards of Conduct require that interstate pipelines not operate their systems to preferentially benefit gas marketing functions.

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FERC regulation requires all terms and conditions of service, including the rates charged, to be filed with and approved by the FERC before any changes can go into effect. Each of our interstate natural gas pipeline companies establishes its rates primarily through the FERC’s ratemaking process. Key determinants in the ratemaking process are:

• Costs of providing service, including depreciation expense;

• Allowed rate of return, including the equity component of the capital structure and related income taxes;

• 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 previously collected may be subject to refund.

We also own interests in and operate two offshore transmission pipelines that are regulated by the FERC because they are deemed to transport gas in interstate commerce. Black Marlin Pipeline Company provides transportation service for offshore Texas production in the High Island area and redelivers that gas to intrastate pipeline interconnects near Texas City. Discovery provides transportation service for offshore Louisiana production from the South Timbalier, Grand Isle, Ewing Bank, and Green Canyon (deepwater) areas to an onshore processing facility and downstream interconnect points with major interstate pipelines. In addition, we own a 50 percent interest in, and operate OPPL, which is an interstate natural gas liquids pipeline regulated by the FERC pursuant to the Interstate Commerce Act. OPPL provides transportation service pursuant to tariffs filed with the FERC.

Pipeline Safety

Our gas pipelines are subject to the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Improvement Act of 2002, and the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011 (Pipeline Safety Act), which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. The United States 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.

Federal pipeline safety regulations contain an exemption that applies to gathering lines in certain rural locations. A substantial portion of our gathering lines qualify for that exemption and are currently not regulated under federal law. However, USDOT is completing a congressionally-mandated review of the adequacy of the existing federal and state regulations for gathering lines and has indicated that it may apply additional safety standards to rural gas gathering lines in the future.

States are preempted by federal law from regulating pipeline safety for interstate pipelines but most are certified by USDOT to assume responsibility for enforcing intrastate pipeline safety regulations and inspecting intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, they vary considerably in their authority and capacity to address pipeline safety.

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

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integrity management requirements. USDOT is considering these and other provisions in the Pipeline Safety Act and has sought public comment on changes to the standards in its pipeline safety regulations.

Pipeline integrity regulations

We have developed an enterprise wide Gas Integrity Management Plan that we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for gas transmission pipelines that could affect high consequence areas in the event of pipeline failure. The integrity management program includes a baseline assessment plan along with periodic reassessments to be completed within required time frames. In meeting the integrity regulations, we have identified high consequence areas and developed baseline assessment plans. We completed the assessments within the required time frames, with one exception which was reported to PHMSA. Ongoing periodic reassessments and initial assessments of any new high consequence areas are expected to be completed within the time frames required by the rule. We estimate that the cost to be incurred in 2014 associated with this program to be approximately $43 million, most of which we expect to be capital expenditures. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through Northwest Pipeline’s and Transco’s rates.

We developed a Liquid Integrity Management Plan that we believe meets the PHMSA final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires liquid pipeline operators to develop an integrity management program for liquid transmission pipelines that could affect high consequence areas (whether onshore or offshore) in the event of pipeline failure. The integrity management program includes a baseline assessment plan along with periodic reassessments to be completed within required time frames. In meeting the integrity regulations we utilized government defined high consequence areas and developed baseline assessment plans. We completed assessments within the required time frames. We estimate that the cost to complete the remediation associated with the 2013 assessments will be approximately $100,000, most of which we expect to be included in 2014 operating expenses. Ongoing periodic reassessments and initial assessments of any new high consequence areas are expected to be completed within the time frames required by the rule. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business.

State Gathering Regulation

Our onshore midstream gathering operations are subject to regulation by states in which we operate. Of the states where our midstream business gathers gas, currently only Texas actively regulates gathering activities. Texas regulates gathering primarily through complaint mechanisms under which the state commission may resolve disputes involving an individual gathering arrangement.

OCSLA

Our offshore midstream gathering is subject to the Outer Continental Shelf Lands Act (OCSLA). Although offshore gathering facilities are not subject to the NGA, offshore transmission pipelines are subject to the NGA, and in recent years the FERC has taken a broad view of offshore transmission, finding many shallow-water pipelines to be jurisdictional transmission. Most offshore gathering facilities are subject to the OCSLA, which provides in part that outer continental shelf pipelines “must provide open and nondiscriminatory access to both owner and nonowner shippers.”

Olefins

Our olefins assets are regulated by the Louisiana Department of Environmental Quality, the Texas Railroad Commission, and various other state and federal entities regarding our liquids pipelines.

Our olefins assets are also subject to the liquid pipeline safety and integrity regulations previously discussed above since both Louisiana and Texas have adopted the integrity management regulations defined by PHMSA.

See Note 14 – Contingent Liabilities and Commitments of our Notes to Consolidated Financial Statements for further details on our regulatory matters.

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ENVIRONMENTAL MATTERS

Our operations are subject to federal environmental laws and regulations as well as the state, local, and tribal 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, processing or treating facilities, transportation facilities and storage tanks;

• Damage to facilities resulting from accidents during normal operations;

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

• Blowouts, cratering and explosions.

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

We believe compliance with current environmental laws and regulations will not have a material adverse effect on our capital expenditures, earnings or 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, tribal 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 expectations” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental” and “Environmental Matters” in Note 14 – Contingent Liabilities and Commitments of our Notes to Consolidated Financial Statements.

COMPETITION

Interstate Natural Gas Pipelines

The natural gas industry has undergone significant change over the past two decades. 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. More recently large reserves of shale gas have been discovered, in many cases much closer to major market centers. As a result, pipeline capacity is being used more efficiently and competition among pipeline suppliers to connect growing supply to market has increased.

Local distribution company (LDC) and electric industry restructuring by states have affected pipeline markets. Pipeline operators are increasingly challenged to accommodate the flexibility demanded by customers and allowed under tariffs. The state plans have, in some cases, discouraged LDCs from signing long-term contracts for new capacity.

States have developed new plans that require utilities to encourage energy saving measures and diversify their energy supplies to include renewable sources. This has lowered the growth of residential gas demand. However, due to relatively low prices of natural gas, demand for electric power generation has increased.

These factors have increased the risk that customers will reduce their contractual commitments for pipeline capacity from traditional producing areas. Future utilization of pipeline capacity will depend on these factors and others impacting both U.S. and global demand for natural gas.

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Gathering and Processing

Our gathering and processing business competes with other midstream companies, interstate and intrastate pipelines, producers and independent gatherers and processors. We primarily compete with five to ten companies across all basins in which we provide services. Numerous factors impact any given customer’s choice of a gathering or processing services provider, including rate, location, term, reliability, timeliness of services to be provided, pressure obligations and contract structure.

Olefins Production

Ethylene and propylene markets, and therefore our olefins business, compete in a worldwide marketplace. Due to our NGL feedstock position at Geismar, we expect to benefit from the lower cost position in North America versus other crude based feedstocks worldwide. The majority of North American olefins producers have significant downstream petrochemical manufacturing for plastics and other products. As such, they buy or sell ethylene and propylene as required. We operate as a merchant seller of olefins with no downstream manufacturing, and therefore can be either a supplier or a competitor at any given time to these other companies. We compete on the basis of service, price and availability of the products we produce.

For additional information regarding competition for our services or otherwise affecting our business, please refer to “Risk Factors - The long-term financial condition of our natural gas transportation and midstream businesses is dependent on the continued availability of natural gas supplies in the supply basins that we access and demand for those supplies in our traditional markets, “-Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results,” and “- We may not be able to replace, extend, or add additional customer contracts or contracted volumes on favorable terms, or at all, which could affect our financial condition, the amount of cash available to pay distributions, and our ability to grow.” 

EMPLOYEES

We do not have any employees. We are managed and operated by the directors and officers of our general partner. At February 1, 2014, our general partner or its affiliates employed approximately 4,909 full-time employees, a substantial portion of which support our operations and provide services to us. Additionally, our general partner and its affiliates provide general and administrative services to us. For further information, please read “Directors, Executive Officers and Corporate Governance” and “Certain Relationships and Related Transactions, and Director Independence — Reimbursement of Expenses of our General Partner.”

FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS

As of December 31, 2013, we have no revenue or segment profit/loss attributable to international activities.

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Item 1A. Risk Factors

FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT FOR

PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES

LITIGATION REFORM ACT OF 1995

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

All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “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:

• 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;

• The levels of cash distributions to unitholders;

• Natural gas, natural gas liquids and olefins prices, supply and demand;

• 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. Limited partner units are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the risk factors discussed below in addition to the other information in this report. If any of the following risks were actually to occur, our business, results of operations and financial condition could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and unitholders could lose all or part of their investment. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

• Whether we have sufficient cash from operations to enable us to pay current and expected levels of cash distributions, if any following establishment of cash reserves and payment of fees and expenses, including payments to our general partner;

• 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);

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• 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;

• Ability to acquire new businesses and assets and successfully integrate those operations and assets into our existing businesses, as well as successfully expand our facilities;

• 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;

• The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;

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

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

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

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

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

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

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RISK FACTORS

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

Prices for NGLs, olefins, natural gas, oil and other commodities, are volatile and this volatility could adversely affect our financial results, cash flows, access to capital and ability to maintain our existing businesses.

Our revenues, operating results, future rate of growth and the value of certain components of our businesses depend primarily upon the prices of NGLs, olefins, natural gas, oil, or other commodities, and the differences between prices of these commodities. Price volatility can impact both the amount we receive for our products and services and the volume of products and services we sell. Prices affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Price volatility can also have an adverse effect on our business, results of operations, financial condition, cash flows and our ability to make cash distributions to unitholders.

The markets for NGLs, olefins, natural gas, oil and other commodities are likely to continue to be volatile. Wide fluctuations in prices might result from one or more factors beyond our control, including:

• Worldwide and domestic supplies of and demand for natural gas, NGLs, olefins, oil, and related commodities;

• Turmoil in the Middle East and other producing regions;

• The activities of the Organization of Petroleum Exporting Countries;

• The level of consumer demand;

• The price and availability of other types of fuels or feedstocks;

• The availability of pipeline capacity;

• Supply disruptions, including plant outages and transportation disruptions;

• The price and quantity of foreign imports of natural gas and oil;

• Domestic and foreign governmental regulations and taxes;

• The credit of participants in the markets where products are bought and sold.

The long-term financial condition of our natural gas transportation and midstream businesses is dependent on the continued availability of natural gas supplies in the supply basins that we access and demand for those supplies in our traditional markets.

Our ability to maintain and expand our natural gas transportation and midstream businesses 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 and gathering systems will naturally decline over time. The amount of natural gas reserves underlying these existing wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. In addition, low prices for natural gas, regulatory limitations, or the lack of available capital could adversely affect the development and production of additional natural gas reserves, the installation of gathering, storage, and pipeline transportation facilities and the 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. A failure to obtain access to sufficient natural gas supplies will adversely impact our ability to maximize the capacities of our gathering, transportation and processing facilities.

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Demand for our services is dependent on the demand for gas in the markets we serve. Alternative fuel sources such as electricity, coal, fuel oils or nuclear energy could reduce demand for natural gas in our markets and have an adverse effect on our business.

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

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

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

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

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

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

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

If realized, any of these risks could have an adverse impact on our results of operations, including the possible impairment of our assets, and could also have an adverse impact on our financial position, cash flows and our ability to make cash distributions to unitholders.

We do not own all of the interests in the Partially Owned Entities, which could adversely affect our ability to operate and control these assets in a manner beneficial to us.

Because we do not control the Partially Owned Entities, we may have limited flexibility to control the operation of or cash distributions received from these entities. The Partially Owned Entities’ organizational documents require distribution of their available cash to their members on a quarterly basis; however, in each case, available cash is reduced, in part, by reserves appropriate for operating the businesses. At December 31, 2013, our investments in the Partially Owned Entities accounted for approximately 10 percent of our total consolidated assets. Conflicts of interest may arise in the future between us, on the one hand, and our Partially Owned Entities, on the other hand, with regard to our Partially Owned Entities’ governance, business, and operations. If a conflict of interest arises between us and a Partially Owned Entity, other owners may control the Partially Owned Entity’s actions with respect to such matter

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(subject to certain limitations), which could be detrimental to our business. Any future disagreements with the other co-owners of these assets could adversely affect our ability to respond to changing economic or industry conditions, which could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions to unitholders.

We may not have sufficient cash from operations to enable us to pay cash distributions or to maintain current or expected levels of cash distributions following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

We may not have sufficient cash each quarter to pay cash distributions or maintain current or expected levels of cash distributions. The actual amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

• The amount of cash that our subsidiaries and the Partially Owned Entities distribute to us;

• The amount of cash we generate from our operations, our working capital needs, our level of capital expenditures, and our ability to borrow;

• The restrictions contained in our indentures and credit facility and our debt service requirements;

• The cost of acquisitions, if any.

Unitholders should be aware that the amount of cash we have available for distribution depends primarily on our cash flow, including cash reserves and working capital or other borrowings, and not solely on profitability, which will be affected by noncash items. As a result, we may make cash distributions during periods when we record losses, and we may not make cash distributions during periods when we record net income. A failure to pay distributions or to pay distributions at expected levels could result in a loss of investor confidence, reputational damage and a decrease in the value of our unit price.

Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

We have numerous competitors in all aspects of our businesses, and additional competitors may enter our markets. Some of our competitors are large oil, natural gas and petrochemical companies that have greater access to supplies of natural gas and NGLs than we do. In addition, current or potential competitors may make strategic acquisitions or have greater financial resources than we do, which could affect our ability to make strategic investments or acquisitions. Our competitors may be able to respond more quickly to new laws or regulations or emerging technologies or to devote greater resources to the construction, expansion or refurbishment of their facilities than we can. 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. Failure to successfully compete against current and future competitors could have a material adverse effect on our business, results of operations, financial condition, cash flows and our ability to make cash distributions to unitholders.

We may not be able to replace, extend, or add additional customer contracts or contracted volumes on favorable terms, or at all, which could affect our financial condition, the amount of cash available to pay distributions, and our ability to grow.

We rely on a limited number of customers and producers for a significant portion of our revenues and supply of natural gas and NGLs. Although many of our customers and suppliers are subject to long-term contracts, if we are unable to replace or extend such contracts or add additional customers, each on favorable terms, if at all, our financial condition, growth plans, and the amount of cash available to pay distributions could be adversely affected. Our ability to replace, extend, or add additional customer or supplier contracts on favorable terms, or at all is subject to a number of factors, some of which are beyond our control, including:

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• The level of existing and new competition in our businesses or from alternative fuel sources, such as electricity, coal, fuel oils, or nuclear energy;

• Natural gas, NGL, and olefins prices, demand, availability and margins in our markets. Higher prices for energy commodities related to our businesses could result in a decline in the demand for those commodities and, therefore, in customer contracts or throughput on our pipeline systems. Also, lower energy commodity prices could result in a decline in the production of energy commodities resulting in reduced customer contracts, supply contracts, and throughput on our pipeline systems;

• General economic, financial markets and industry conditions;

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

• Our 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.

Our operations are subject to operational hazards and unforeseen interruptions.

There are operational risks associated with the gathering, transporting, storage, processing and treating of natural gas, the fractionation, transportation and storage of NGLs, processing of olefins, and crude oil transportation and production handling, including:

• Aging infrastructure and mechanical problems;

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

• Uncontrolled releases of natural gas (including sour gas), NGLs, brine or industrial chemicals;

• Collapse or failure of storage caverns;

• Operator error;

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

• Pollution and other environmental risks;

• Fires, explosions, craterings and blowouts;

• Truck and rail loading and unloading;

• Operating in a marine environment.

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 facilities 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 have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance.

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 $610 million per occurrence and in the annual aggregate with a $2 million per occurrence deductible. This insurance

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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 NGL 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 be 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, but 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), and we are an insured of OIL, an energy industry mutual insurance company, which provides coverage for damage to our property. As an insured of OIL, we are allocated a portion of shared losses and premiums in proportion to our assets. As an insured member of OIL, Williams shares in the losses among other OIL members even if its property is not damaged, and as a result, we may share in any such losses incurred by Williams.

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

The time required to return our Geismar olefins plant to operation following the explosion and fire at the facility on June 13, 2013, and the extent and timing of costs and insurance recoveries related to the incident could be materially different than we anticipate and could cause our financial results and levels of distributions to be materially different than we project.

Our projections of financial results and expected levels of distributions are based on numerous assumptions and estimates, including but not limited to the time required to return our Geismar, Louisiana olefins plant to operation and complete the expansion project at the facility following the explosion and fire at the plant on June 13, 2013, and the extent and timing of costs and insurance recoveries related to the incident. Our financial results and levels of distributions could be materially different than we project if our assumptions and estimates related to the incident are materially different than actual outcomes.

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

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

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

Given the volatile nature of the commodities we transport, process, store and sell, 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 produce, process, transport or distribute natural gas, NGLs or other commodities. 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

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or remediation costs, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows and on our ability to make cash distributions to unitholders.

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, practices 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.

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

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

• Transportation and sale for resale of natural gas in interstate commerce;

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

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

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

• Accounts and records;

• Depreciation and amortization policies;

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

• 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 the rates of the gas pipelines, can affect our business in many ways, including decreasing tariff rates and revenues, decreasing volumes in our pipelines, increasing our costs and otherwise altering the profitability of our pipeline business.

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 expectations.

Our operations are subject to extensive federal, state, tribal and local laws and regulations governing environmental protection, endangered and threatened species, the discharge of materials into the environment and the security of

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chemical and industrial facilities. Substantial costs, liabilities, delays and other significant issues related to environmental laws and regulations are inherent in the gathering, transportation, storage, processing and treating of natural gas, fractionation, transportation and storage of NGLs, processing of olefins, and crude oil transportation and production handling as well as waste disposal practices. Failure to comply with these 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 and gathering systems pass 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 regulations and the costs associated with the regulation of emissions of greenhouse gases (GHGs) have the potential to affect our business. Regulatory actions by the EPA or the passage of new climate change laws or regulations could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage our GHG compliance program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Climate change and GHG regulation could also reduce demand for our services.

If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas and NGLs or to treat natural gas, our revenues and cash available to pay distributions could be adversely affected.

We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our customers. Because we do not own these third-party pipelines or other facilities, their continuing operation is not within our control. If these pipelines or 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 or NGL products to end use markets or to receive deliveries of mixed NGLs, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnect or in operations on third-party pipelines or facilities that would cause a material reduction in volumes transported on our pipelines or our gathering systems or processed, fractionated, treated or stored at our facilities could have a material adverse effect on our business, results of operations, financial condition, cash flows and our ability to make cash distributions to unitholders.

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.

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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 pipelines and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.

Certain inquiries, investigations and court proceedings are ongoing. Adverse effects may continue as a result of the uncertainty of 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 results of operations or increase our operating costs in other ways. Current legal proceedings or other matters, including environmental matters, suits, regulatory appeals and similar matters might result in adverse decisions against us which, among other outcomes, could result in the imposition of substantial penalties and fines and could damage our reputation. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.

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

Certain of our gas pipeline 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.

Our gas pipelines 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 our pipelines collect for their services. Although most of the services are priced at cost-based rates that are subject to adjustment in rate cases, under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” that may be above or below 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.

Our operating results for certain components of our business might fluctuate on a seasonal basis.

Revenues from certain components of our business can have seasonal characteristics. In many parts of the country, demand for natural gas and other fuels peaks during the winter. As a result, our overall operating results in the future might fluctuate substantially on a seasonal basis. Demand for natural gas and other fuels could vary significantly from our expectations depending on the nature and location of our facilities and pipeline systems and the terms of our natural gas transportation arrangements relative to demand created by unusual weather patterns.

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

We do not own all of the land on which our pipelines 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 pipelines and gathering systems on land owned by third parties and governmental agencies for a specific period of time. In addition, some of our facilities cross Native American lands pursuant to rights-of-way of limited term. We may not have the right of eminent domain over land owned by Native American tribes. Our loss of 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, and financial condition, cash flows and our ability to make cash distributions to unitholders.

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

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Our businesses may be negatively impacted by adverse economic conditions or future disruptions in 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. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures. In addition, financial markets have recently been affected by concerns over U.S. fiscal policy, including uncertainty regarding federal spending and tax policy, as well as the U.S. federal government’s debt ceiling and the federal deficit. These concerns, as well as actions taken by the U.S. federal government in response to these concerns, could significantly and adversely impact the global and U.S. economies and financial markets, which could negatively impact us in the manners described above.

As a publicly traded partnership, these developments could significantly impair our ability to make acquisitions or finance growth projects. We distribute all of our available cash to our unitholders on a quarterly basis. We typically rely upon external financing sources, including the issuance of debt and equity securities and bank borrowings, to fund acquisitions or expansion capital expenditures. Any limitations on our access to external capital, including limitations caused by illiquidity or volatility in the capital markets, may impair our ability to complete future acquisitions and construction projects on favorable terms, if at all. As a result, we may be at a competitive disadvantage as compared to businesses that reinvest all of their available cash to expand ongoing operations, particularly under adverse economic conditions.

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

A downgrade of our credit ratings might increase our cost of borrowing and could require us to provide collateral to our counterparties, negatively impacting our available liquidity. In addition our ability to access capital markets could be limited by a downgrade of our credit ratings as well as by economic, market or other disruptions.

Credit rating agencies perform independent analysis when assigning credit ratings. This 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.

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

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

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 as of December 31, 2013, was $9,057 million.

The agreements governing our indebtedness contain covenants that restrict our and our material subsidiaries’ ability to incur certain liens to support indebtedness and our ability to merge or consolidate or sell all or substantially all of

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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, the ability of our subsidiaries to incur additional debt, and our and our material subsidiaries’ ability to enter into certain affiliate transactions and certain restrictive agreements and to change the nature of our business. Certain of our debt agreements also contain, and those we enter into in the future may contain, financial covenants and other limitations with which we will need to comply. Williams’ debt agreements contain similar covenants with respect to Williams and its subsidiaries, including us.

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

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

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

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

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

Our failure to comply with the covenants in the documents governing our indebtedness could result in events of default, which could render such indebtedness due and payable. We may not have sufficient liquidity to repay our indebtedness in such circumstances. In addition, cross-default or cross-acceleration provisions in our debt agreements 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 — Management’s Discussion and Analysis of Financial Condition and Liquidity.”

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

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

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

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We expect that a significant percentage of employees will become eligible for retirement over the next three years. In certain areas of our business, institutional knowledge resides with employees who have many years of service. As these employees reach retirement age or their services are no longer available to Williams, 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 our 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 hedging activities might not be effective and could increase the volatility of our results.

In an effort to manage our financial exposure related to commodity price and market fluctuations, we have entered, and may in the future enter, into contracts to hedge certain risks associated with our assets and operations. In these hedging activities, we have used, and may in the future use, fixed-price, forward, physical purchase and sales contracts, futures, financial swaps and option contracts traded in the over-the-counter markets or on exchanges. Nevertheless, no single hedging arrangement can adequately address all risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist. While we attempt to manage counterparty credit risk within guidelines established by our credit policy, we may not be able to successfully manage all credit risk and as such, future cash flows and results of operations could be impacted by counterparty default.

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted. The Dodd-Frank Act provides for statutory and regulatory requirements for derivative transactions, including oil and gas hedging transactions. Among other things, the Dodd-Frank Act provides for the creation of position limits for certain derivatives transactions, as well as requiring certain transactions to be transacted on exchanges for which cash collateral will be required. These new rules and regulations could increase the cost of derivative contracts or reduce the availability of derivatives. Although we believe the derivative contracts that we enter into should not be impacted by position limits and should to a large extent be exempt from the requirement to trade these transactions on exchanges and to clear these transactions through a central clearing house or to post collateral, the impact upon our businesses will depend on the outcome of the implementing regulations that are continuing to be adopted by the Commodities Futures Trading Commission.

A number of our financial derivative transactions used for hedging purposes are currently executed on exchanges and cleared through clearing houses that already require the posting of margins based on initial and variation requirements. Final rules promulgated under the Dodd-Frank Act may require us to post additional cash or new margin to the clearing house or to our counterparties in connection with our hedging transactions. Posting such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures or other partnership purposes. A requirement to post cash collateral could therefore reduce our ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

Our investments and projects located outside of the United States expose us to risks related to the laws of other countries, and the taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments. These risks might delay or reduce our realization of value from our international projects.

We currently own and might acquire and/or dispose of material energy-related investments and projects outside the United States. The economic, political and legal conditions and regulatory environment in the countries in which we have interests or in which we might pursue acquisition or investment opportunities present risks that are different from or greater than those in the United States. These risks include, among others, delays in construction and interruption of business, as well as risks of renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, including with respect to the prices we realize for the commodities we produce and sell. The uncertainty of the legal environment in certain foreign countries in which we develop or acquire projects or make investments

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could make it more difficult to obtain nonrecourse project financing or other financing on suitable terms, could adversely affect the ability of certain customers to honor their obligations with respect to such projects or investments and could impair our ability to enforce our rights under agreements relating to such projects or investments.

Operations and investments in foreign countries also can present currency exchange rate and convertibility, inflation and repatriation risk. In certain situations under which we develop or acquire projects or make investments, economic and monetary conditions and other factors could affect our ability to convert to U.S. dollars our earnings denominated in foreign currencies. In addition, risk from fluctuations in currency exchange rates can arise when our foreign subsidiaries expend or borrow funds in one type of currency, but receive revenue in another. In such cases, an adverse change in exchange rates can reduce our ability to meet expenses, including debt service obligations. We may or may not put contracts in place designed to mitigate our foreign currency exchange risks. We have some exposures that are not hedged and which could result in losses or volatility in our results of operations.

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

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

Risks Inherent in an Investment in Us

Williams controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner has limited fiduciary duties, and it and its affiliates may have conflicts of interest with us and our unitholders, and our general partner and its affiliates may favor their interests to the detriment of our unitholders.

Williams owns and controls our general partner and appoints all of the directors of our general partner. All of the executive officers and certain directors of our general partner are officers and/or directors of Williams and certain of its affiliates and these persons will also owe fiduciary duties to those entities. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us, the directors and officers of our general partner also have a fiduciary duty to manage our general partner in a manner beneficial to Williams. Therefore, conflicts of interest may arise between Williams and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following factors:

• Neither our partnership agreement nor any other agreement requires Williams or its affiliates to pursue a business strategy that favors us. Williams’ directors and officers have a fiduciary duty to make decisions in the best interests of the owners of Williams, which may be contrary to the best interests of us and our unitholders;

• Our general partner is allowed to take into account the interests of parties other than us, such as Williams and its affiliates, in resolving conflicts of interest;

• As of December 31, 2013, Williams owns common units representing an approximate 62 percent limited partner interest in us. If a vote of limited partners is required in which Williams is entitled to vote, Williams will be able to vote its units in accordance with its own interests, which may be contrary to our interests or the interests of our unitholders;

• All of the executive officers and certain of the directors of our general partner will devote significant time to our business and/or the business of Williams, and will be compensated by Williams for the services rendered to them;

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• Our general partner determines the amount and timing of our cash reserves, asset purchases and sales, capital expenditures, borrowings and issuances of additional partnership securities, each of which can affect the amount of cash that is distributed to our unitholders;

• Our general partner determines the amount and timing of any capital expenditures and, based on the applicable facts and circumstances and, in some instances, with the concurrence of the conflicts committee of its board of directors, whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure or investment capital expenditure, neither of which reduces operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner with respect to its incentive distribution rights;

• In some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions even if the purpose or effect of the borrowing is to make incentive distributions to itself as general partner;

• Our general partner determines which costs incurred by it and its affiliates are reimbursable by us, controls the enforcement of obligations owed to us by it and its affiliates and decides whether to retain separate counsel, accountants or others to perform services for us;

• Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

• Our general partner has limited liability regarding our contractual and other obligations and in some circumstances is required to be indemnified by us;

• Pursuant to our partnership agreement, our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80 percent of our outstanding common units.

Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to such unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. The limitation and definition of these duties is permitted by the Delaware law governing limited partnerships. In addition, our partnership agreement restricts the remedies available to holders of our limited partner units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:

• Permits our general partner to make a number of decisions in its individual capacity as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;

• Provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;

• Generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us, as determined by our general partner in good faith. In determining whether

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a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

• Provides that our general partner, its affiliates and their respective officers and directors will not be liable for monetary damages to us or our limited partners or assignees for any acts or omissions unless there has been a final and nonappealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that such conduct was criminal;

• Provides that in resolving conflicts of interest, it will be presumed that in making its decision our general partner or the conflicts committee of its board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Common unitholders are bound by the provisions in our partnership agreement, including the provisions discussed above.

Affiliates of our general partner, including Williams, are not limited in their ability to compete with us and may exclude us from opportunities with which they are involved. In addition, all of the executive officers and certain of the directors of our general partner are also officers and/or directors of Williams, and these persons will also owe fiduciary duties to Williams.

While our relationship with Williams and its affiliates is a significant attribute, it is also a source of potential conflicts. For example, Williams and its affiliates are in the natural gas business and are not restricted from competing with us. Williams and its affiliates may acquire, construct or dispose of natural gas industry assets in the future, some or all of which may compete with our assets, without any obligation to offer us the opportunity to purchase or construct such assets. In addition, all of the executive officers and certain of the directors of our general partner are also officers and/or directors of Williams and certain of its affiliates and will owe fiduciary duties to those entities as well as our unitholders and us.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which the common units will trade.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, will be chosen entirely by Williams and not by the unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Cost reimbursements due to our general partner and its affiliates will reduce cash available to pay distributions to unitholders.

We will reimburse our general partner and its affiliates, including Williams, for various general and administrative services they provide for our benefit, including costs for rendering administrative staff and support services to us, and overhead allocated to us. Our general partner determines the amount of these reimbursements in its sole discretion. Payments for these services will be substantial and will reduce the amount of cash available for distributions to unitholders. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

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Even if unitholders are dissatisfied, they have little ability to remove our general partner without its consent.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by Williams. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The vote of the holders of at least 66 2/3 percent of all outstanding limited partner units is required to remove our general partner. As of December 31, 2013, our general partner and its affiliates own approximately 64 percent of our outstanding limited partner units and, as a result, our public unitholders cannot remove our general partner without its consent.

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.

The control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement effectively permits a change of control without unitholder consent.

We may issue additional common units without unitholder approval, which would dilute unitholder ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank, or classes of securities which ultimately convert into common units, will have the following effects:

• Our unitholders’ proportionate ownership interest in us will decrease;

• The amount of cash available to pay distributions on each unit may decrease;

• The ratio of taxable income to distributions may decrease;

• The relative voting strength of each previously outstanding unit may be diminished;

• The market price of the common units may decline.

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The existence and eventual sale of common units or securities convertible into common units, whether held by Williams or issued in our acquisitions and eligible for future sale may adversely affect the price of our common units.

Williams holds 279,472,244 common units, representing approximately 64 percent of our common units outstanding. Williams may, from time to time, sell all or a portion of its common units. We have also issued additional common units in connection with our acquisitions and we may also issue additional common units to other unaffiliated third parties in connection with future acquisitions. Sales of substantial amounts of common units by Williams or third parties, or the anticipation of such sales, could lower the market price of our common units and may make it more difficult for us to sell our equity securities in the future at a time and at a price that we deem appropriate.

Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.

Pursuant to our partnership agreement, if at any time our general partner and its affiliates own more than 80 percent of the common units, our general partner will have the right, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. Our general partner may assign this right to any of its affiliates or to us. As a result, nonaffiliated unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Such unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered under the Exchange Act, we would no longer be subject to the reporting requirements of such Act.

Our partnership agreement restricts the voting rights of unitholders owning 20 percent or more of our common units.

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees, transferees of their transferees (provided that our general partner has notified such secondary transferees that the voting limitation shall not apply to them), and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be voted on any matter. The partnership agreement also contains provisions limiting the ability of unitholders to call meetings, to acquire information about our operations and to influence the manner or direction of management.

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

• We were conducting business in a state but had not complied with that particular state’s partnership statute; or

• Your rights to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to

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you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are nonrecourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

Tax Risks

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by states and localities. If the IRS were to treat us as a corporation for U.S. federal income tax purposes or if we were to become subject to a material amount of entity-level taxation for state or local tax purposes, then our cash available for distribution to unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for U.S. federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which currently has a top marginal rate of 35 percent, and would likely pay state and local income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available to pay distributions to unitholders would be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distributions to unitholders would be reduced. Therefore, if we were treated as a corporation for U.S. federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, there would be a material reduction in the anticipated cash flow and after-tax return to unitholders, likely causing a substantial reduction in the value of the common units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

The U.S. federal income tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect certain publicly traded partnerships. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes, We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

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We prorate our items of income, gain, loss and deduction between transferors and transferees of the common units each month based upon the ownership of the common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of the common units each month based upon the ownership of the common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The use of this proration method may not be permitted under existing United States Department of the Treasury (Treasury) regulations, and although the Treasury issued proposed regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

An IRS contest of the U.S. federal income tax positions we take may adversely impact the market for the common units, and the costs of any contest will reduce our cash available for distribution to our unitholders and our general partner.

We have not requested any ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from our counsel’s conclusions or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or the U.S. federal income tax positions we take. Any contest with the IRS may materially and adversely impact the market for the common units and the price at which they trade. In addition, the costs of any contest with the IRS will result in a reduction in cash available to pay distributions to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner.

Unitholders will be required to pay taxes on their share of our income even if unitholders do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, unitholders will be required to pay U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

The tax gain or loss on the disposition of the common units could be different than expected.

If a unitholder sells its common units, it will recognize gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and its tax basis in those common units. Prior distributions to a unitholder in excess of the total net taxable income that was allocated to a unitholder for a common unit, which decreased its tax basis in that common unit, will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than its tax basis in that common unit, even if the price the unitholder receives is less than the original cost. A substantial portion of the amount realized, regardless of whether such amount represents gain, may be taxed as ordinary income to the unitholder due to potential recapture items, including depreciation recapture. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, if a unitholder sells its common units, the unitholder may incur a U.S. federal income tax liability in excess of the amount of cash it received from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as individual retirement accounts (IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to the unitholders who are organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, may be taxable to them as “unrelated business taxable income.” Distributions to non-U.S. persons will be reduced by withholding taxes

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at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay U.S. federal income tax on their share of our taxable income.

We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, we have adopted depreciation and amortization positions that may not conform with all aspects of applicable Treasury regulations. Our counsel is unable to opine as to the validity of such filing positions. A successful IRS challenge to those positions could adversely affect the amount of U.S. federal income tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to unitholder tax returns.

Unitholders will likely be subject to state and local taxes and return filing requirements as a result of investing in our common units.

In addition to U.S. federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if the unitholder does not live in any of those jurisdictions. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign countries that impose a personal income tax or an entity level tax. It is the unitholder’s responsibility to file all U.S. federal, state and local tax returns. Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our common units.

The sale or exchange of 50 percent or more of the total interest in our capital and profits within a 12-month period will result in a termination of our partnership for U.S. federal income tax purposes.

We will be considered to have terminated our partnership for U.S. federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a 12-month period. Our termination would, among other things, result in the closing of our taxable year for all partners, which would result in us filing two tax returns for one fiscal year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than 12 months of our taxable income or loss being includable in the unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for U.S. federal income tax purposes, but instead, we would be treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to its partners for the tax years in the fiscal year during which the termination occurs.

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional common units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our partners. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, our allocation of the Code Section 743(b) adjustment attributable to our tangible and intangible assets, and our allocations of income, gain, loss and deduction between our general partner and certain of our partners.

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A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to the unitholder’s tax returns.

A unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, items of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder whose common units are loaned to a short seller to effect a short sale of common units. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

Item 1B.Unresolved Staff Comments

None.

Item 2.Properties

Please read “Business” for a description of the location and general character of our principal physical properties. We generally own our facilities, although a substantial portion of our pipeline and gathering facilities are constructed and maintained pursuant to rights-of-way, easements, permits, licenses or consents on and across properties owned by others.

Item 3.Legal Proceedings

Environmental

Certain reportable legal proceedings involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment are described below. While it is not possible for us to predict the final outcome of the proceedings which are still pending, we do not anticipate a material effect on our consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings.

In September 2007, the EPA requested, and our Transco subsidiary later provided, information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPA’s investigation of Transco’s compliance with the Clean Air Act. On March 28, 2008, the EPA issued notices of violation alleging violations of Clean Air Act requirements at these compressor stations. Transco met with the EPA in May 2008 and submitted a response denying the allegations in June 2008. In May 2011, Transco provided additional information to the EPA pertaining to these compressor stations in response to a request they had made in February 2011. In August 2010, the EPA requested, and Transco provided, similar information for a compressor station in Maryland. Since 2011 we have not received any additional requests for information related to these facilities.

On February 12, 2013, the NMED issued a Notice of Violation to Four Corners related to the alleged modification of turbine units and a separator tank and alleged failure to conduct performance tests on certain facilities at the La Jara Compressor Station. Four Corners has been in discussions with the NMED since 2012 regarding the separator tank and other permitting issues. On January 9, 2014, the NMED withdrew the Notice of Violation and advised that no further action is required.

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Other

The additional information called for by this item is provided in Note 14 – Contingent Liabilities and Commitments of the Notes to Consolidated Financial Statements included under Part II, Item 8. Financial Statements of this report, which information is incorporated by reference into this item.

Item 4.Mine Safety Disclosures

Not applicable.

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PART II

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

Market Information, Holders, and Distributions

Our common units are listed on the NYSE under the symbol “WPZ.” At the close of business on February 18, 2014, there were 438,625,699 common units outstanding, held by approximately 111,357 record holders and holders in street name, including common units held by an affiliate of Williams. In addition, our general partner holds all of our 2 percent general partner interest and incentive distribution rights.

The following table sets forth, for the periods indicated, the high and low sales prices for our common units, as reported on the NYSE Composite Transactions Tape, and quarterly cash distributions paid to our unitholders.

	High	Low	Cash Distribution per Unit (1)
2013
First Quarter	$54.50	$48.06	$0.8475
Second Quarter	54.66	45.37	0.8625
Third Quarter	53.74	47.93	0.8775
Fourth Quarter	53.98	48.46	0.8925
2012
First Quarter	$65.39	$55.02	$0.7775
Second Quarter	58.26	48.28	0.7925
Third Quarter	55.90	50.50	0.8075
Fourth Quarter	55.48	45.01	0.8275

________

(1) Represents cash distributions attributable to the quarter and declared and paid within 45 days after quarter end. We paid cash distributions to our general partner with respect to its general partner interest and incentive distribution rights that totaled $475 million and $413 million for the 2013 and 2012 periods, respectively.

Distributions of Available Cash

Within 45 days after the end of each quarter we will distribute all of our available cash, as defined in our partnership agreement, to common unitholders of record on the applicable record date. Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter:

• Less the amount of cash reserves established by our general partner to:

• Provide for the proper conduct of our business (including reserves for future capital expenditures and for our anticipated credit needs);

• Comply with applicable law, any of our debt instruments or other agreements; or

• Provide funds for distribution to our unitholders and to our general partner for any one or more of the next four quarters;

• Plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made. Working capital borrowings are borrowings used solely for working capital purposes or to pay distributions made pursuant to a credit facility or other arrangement to the extent such borrowings are required to be reduced to a relatively small amount each year for an economically meaningful period of time.

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We will make distributions of available cash from operating surplus for any quarter in the following manner:

• First, 98 percent to all common unitholders, pro rata, and 2 percent to our general partner, until each outstanding unit has received the minimum quarterly distribution for that quarter;

• Thereafter, cash in excess of the minimum quarterly distributions is distributed to the common unitholders and the general partner based on the incentive percentages below.

Our general partner is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:

	Total Quarterly Distribution	Marginal Percentage Interest in Distributions
	Target Amount	Unitholders	General Partner
Minimum Quarterly Distribution	$0.35	98%	2%
First Target Distribution	up to $0.4025	98%	2%
Second Target Distribution	above $0.4025 up to $0.4375	85%	15%
Third Target Distribution	above $0.4375 up to $0.5250	75%	25%
Thereafter	above $0.5250	50%	50%

If the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal:

• Any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished;

• Our general partner will have the right to convert its general partner interest and, if any, its incentive distribution rights into common units or to receive cash in exchange for those interests.

In lieu of cash distributions, the Class D units that we plan to issue in connection with our previously discussed agreement to acquire certain Canadian operations from Williams will receive quarterly distributions of additional paid-in-kind Class D units. The Class D units will be convertible to common units at a future date.

The preceding discussion is based on the assumption that our general partner maintains its 2 percent general partner interest and that we do not issue additional classes of equity securities. In addition, our general partner agreed to temporarily waive a portion of incentive distributions in connection with certain assets acquired in 2012 and to support our cash distribution metrics as our large platform of growth projects moves toward completion. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Management’s Discussion and Analysis of Financial Condition and Liquidity.”

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Item 6.Selected Financial Data

The following financial data at December 31, 2013 and 2012 and for each of the three years in the period ended December 31, 2013, should be read in conjunction with Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, Financial Statements and Supplementary Data of this Form 10-K. All other financial data has been prepared from our accounting records.

	2013		2012		2011		2010		2009
	(Millions, except per-unit amounts)
Revenues	$	6,685	$	7,320	$	7,714	$	6,459	$	5,149
Net income	1,070		1,232		1,511		1,188		1,063
Net income attributable to controlling interests	1,067		1,232		1,511		1,172		1,036
Net income per common unit (1)	1.45		1.89		3.69		2.66		2.88
Total assets at December 31 (1)	22,358		19,709		14,672		13,666		12,732
Commercial paper and long-term debt due within one year at December 31 (3)	225		—		324		458		15
Long-term debt at December 31 (1)(2)	9,057		8,437		6,913		6,365		2,981
Total equity at December 31 (1)	10,559		8,897		5,433		5,248		8,287
Cash distributions declared per unit	3.480		3.140		2.900		2.653		2.540

____________

(1) The change in 2012 reflects assets acquired, as well as debt and equity issuances related to the Caiman and Laser Acquisitions.

(2) The increase in 2010 reflects borrowings entered into related to an acquisition of certain businesses from Williams.

(3) The increase in 2013 reflects borrowings under our commercial paper program initiated in 2013.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas, NGLs, and olefins through our gas pipeline and midstream businesses.

Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets. Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have limited near-term impact on revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.

The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers. These services include natural gas gathering, processing and treating, NGL fractionation and transportation, crude oil production handling and transportation, olefin production, marketing services for NGL, oil and natural gas, as well as storage facilities.

Our reportable segments are Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services.

• Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus and Utica shale regions, as well as a 51 percent equity investment in Laurel Mountain and a 47.5 percent equity investment in Caiman II.

• Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transco, and significant natural gas gathering and processing and crude oil production handling and transportation in the Gulf Coast region, as well as a 50 percent equity investment in Gulfstream, a 60 percent equity investment in Discovery, and a 41 percent interest in Constitution (a consolidated entity).

• West is comprised of our gathering, processing and treating operations in New Mexico, Colorado, and Wyoming and our interstate natural gas pipeline, Northwest Pipeline.

• NGL & Petchem Services is comprised of our NGL and natural gas marketing business, an NGL fractionator and storage facilities near Conway, Kansas, a 50 percent equity investment in OPPL, and an 83.3 percent interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and various petrochemical and feedstock pipelines in the Gulf Coast region.

As of December 31, 2013, Williams holds an approximate 64 percent interest in us, comprised of an approximate 62 percent limited partner interest and all of our 2 percent general partner interest and IDRs.

Unless indicated otherwise, the following discussion and analysis of critical accounting estimates, results of operations, and financial condition and liquidity should be read in conjunction with the consolidated financial statements and notes thereto included in Part II, Item 8 of this document.

Canada Dropdown

In February 2014, we agreed to acquire certain of Williams’ Canadian operations, including an oil sands offgas processing plant near Fort McMurray, Alberta, an NGL/olefin fractionation facility and butylene/butane splitter facility at Redwater, Alberta and the Boreal pipeline. The transaction is expected to close in February 2014. We expect to fund the transaction with $25 million of cash, the issuance of 25,577,521 Class D limited-partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. In lieu of cash distributions, the Class D units will receive quarterly distributions of additional paid-in-kind Class D units, all of which

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will be convertible to common units at a future date. The agreement also provides that we can issue additional Class D units to Williams on a quarterly basis through 2015 for up to a total of $200 million in cash for the purpose of funding certain facility expansions.

Distributions

In January 2014, our general partner’s Board of Directors approved a quarterly distribution to unitholders of $0.8925 per unit, an increase of approximately 2 percent over the prior quarter and 8 percent over the same period in the prior year. We expect to increase limited partner per-unit cash distributions by approximately 6 percent in 2014 and 2015.

Overview

Our results for the year ended December 31, 2013, were unfavorable compared to the prior year primarily due to lower NGL margins driven by reduced ethane recoveries and decreases in average NGL per-unit sales prices, as well as lower olefin margins associated with lost production resulting from the Geismar Incident. These unfavorable impacts were partially offset by growth in fee revenues, primarily from Northeast G&P. See additional discussion in Results of Operations.

Abundant and low-cost natural gas reserves in the United States continue to drive strong demand for midstream and pipeline infrastructure. We believe that we have successfully positioned our energy infrastructure businesses for significant future growth.

Geismar Incident

On June 13, 2013, an explosion and fire occurred at our Geismar olefins plant. The fire was extinguished on the day of the incident. The incident (Geismar Incident) rendered the facility temporarily inoperable and resulted in significant human, financial, and operational effects. This facility is part of our NGL & Petchem Services segment.

We have substantial insurance coverage for repair and replacement costs, lost production and additional expenses related to the incident as follows:

• Property damage and business interruption coverage with a combined per-occurrence limit of $500 million and retentions (deductibles) of $10 million per occurrence for property damage and a 60-day waiting period per occurrence for business interruption;

• General liability coverage with per-occurrence and aggregate annual limits of $610 million and retentions (deductibles) of $2 million per occurrence;

• Workers’ compensation coverage with statutory limits and retentions (deductibles) of $1 million total per occurrence.

We are cooperating with the Chemical Safety Board and the EPA regarding their investigations of the Geismar Incident. While certain negotiations pertaining to various citations and assessments remain ongoing with the Occupational Safety and Heath Administration (OSHA), they have released the incident area back to us, and we are in the process of repairing the damage incurred. We have expensed $13 million of costs in 2013 under our insurance deductibles in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income. Recoveries under our business interruption policy will be recognized upon resolution of any contingencies with the insurer associated with the claim. During the fourth quarter of 2013, we incurred $10 million of covered insurable expenses in excess of our retentions (deductibles) which partially offset $50 million of insurance proceeds received during the third quarter of 2013, which was reported as a gain in Other (income) expense – net within Costs and expenses in our Consolidated Statement of Income.

Following the repair and plant expansion, the Geismar plant is expected to be in operation in June 2014. We expect our insurance coverage will significantly mitigate our financial loss. We currently estimate approximately $430 million of total cash recoveries from insurers related to business interruption losses and approximately $70 million related to the repair of the plant. Of these amounts, we received $50 million of insurance proceeds during 2013. In February 2014,

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the insurer agreed to pay a second installment of $125 million, which is expected to be received in the first quarter of 2014. We are impacted by certain uninsured losses, including amounts associated with the 60-day waiting period for business interruption, as well as other deductibles, policy limits, and uninsured expenses. Our assumptions and estimates, including the timing for the expanded plant return to operation, repair cost estimates, and insurance proceeds associated with our property damage and business interruption coverage are subject to various risks and uncertainties that could cause the actual results to be materially different.

Northeast G&P

Three Rivers Midstream

In April 2013, we announced an agreement to launch a new midstream joint project to provide gas gathering and gas processing services for production located in northwest Pennsylvania. The project is expected to invest in both wet-gas handling infrastructure and dry-gas infrastructure serving the Marcellus and Utica Shale wells in the area. We will initially own substantially all of the new project, Three Rivers Midstream, and operate the assets. Our partner has the right to invest capital and increase its ownership to a maximum of 50 percent by July 2015. Further development has been delayed pending additional evaluation of producers’ drilling plans.

Marcellus Shale

In the second quarter of 2013, we completed an expansion to our natural gas gathering system, processing facilities, and fractionator in our Ohio Valley Midstream business of the Marcellus Shale including a third turbo-expander at our Fort Beeler facility, which added 200 MMcf/d of processing capacity. In the first half of 2014, we expect to add fractionation capacity at our Moundsville fractionators bringing the NGL handling capacity to approximately 43 Mbbls/d, complete our first turbo-expander at our Oak Grove facility to add 200 MMcf/d of processing capacity, and finalize the construction of our first deethanizer with a capacity of 40 Mbbls/d and the associated 50-mile ethane line to Houston, Pennsylvania.

Caiman II

As a result of planned contributions through the second quarter of 2014, we expect, subject to regulatory approval, to increase our ownership in Caiman II from 47.5 percent up to approximately 59 percent. These additional contributions are used to fund a portion of Blue Racer Midstream, a joint project which comprises an expansion to gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica Shale.

Atlantic-Gulf

Mid-Atlantic Connector

The Mid-Atlantic Connector Project involved an expansion of Transco’s mainline from an existing interconnection with East Tennessee Natural Gas in North Carolina to markets as far downstream as Maryland. We placed the project into service in the first quarter of 2013, and it increased capacity by 142 Mdth/d.

Gulfstar One

Effective April 1, 2013, we sold a 49 percent interest in Gulfstar One to a third party for $187 million, representing their proportionate share of estimated capital expenditures to date for the construction of Gulfstar FPS™, which is a proprietary floating production system and has been under construction since late 2011. It is supported by multiple agreements with two major producers to provide production handling, export pipeline, oil and gas gathering and gas processing services for the Tubular Bells field development located in the eastern deepwater Gulf of Mexico. The Gulfstar FPS™ will tie into our wholly owned oil and gas gathering and gas processing systems in the eastern Gulf of Mexico. Gulfstar FPS™ is expected to have an initial capacity of 60 Mbbls/d, up to 200 MMcf/d of natural gas and the capability to provide seawater injection services. We expect Gulfstar FPS™ to be capable of serving as a central host facility for other deepwater prospects in the area. The project is expected to be in service in the third quarter of 2014. In December 2013, Gulfstar One agreed to host the Gunflint development, which will result in an expansion of the Gulfstar One system to provide production handling capacity of 20 Mbbls/d and 40 MMcf/d for Gunflint. The Gunflint project has a first oil target of mid-2016, dependent on the producer’s development activities.

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Mid-South

The Mid-South expansion project involved an expansion of Transco’s mainline from Station 85 in Choctaw County, Alabama to markets as far downstream as North Carolina. We placed the first phase of the project into service in the third quarter of 2012, which increased capacity by 95 Mdth/d. The second phase was placed into service in the second quarter of 2013, which increased capacity by an additional 130 Mdth/d.

Northeast Supply Link

The Northeast Supply Link Project involved an expansion of Transco’s existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in New York and New Jersey. The project was placed into service in the fourth quarter of 2013 and increased capacity by 250 Mdth/d.

Filing of rate cases

On August 31, 2012, Transco submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in its prior rate proceeding. The new rates became effective March 1, 2013, subject to refund and the outcome of the hearing. On August 27, 2013, Transco filed a stipulation and agreement with the FERC proposing to resolve all issues in this proceeding without the need for a hearing (Agreement). On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement will become effective March 1, 2014. We have provided a reserve for rate refunds of $98 million which we believe is adequate for required refunds as of December 31, 2013, under the Agreement. Refunds will be made on or before April 30, 2014.

Atlantic Sunrise

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

NGL & Petchem Services

Overland Pass Pipeline

Through our equity investment in OPPL, we completed the construction of a pipeline connection and capacity expansions in the second quarter of 2013, which increased the pipeline’s capacity to 255 Mbbls/d, In addition, a new connection was completed in April 2013 to bring new NGL volumes to OPPL from the Bakken Shale in the Williston basin.

Volume impacts in 2013

Due to unfavorable ethane economics, we reduced our recoveries of ethane in our plants during most of 2013, which resulted in 31 percent lower NGL production volumes and 48 percent lower NGL equity sales volumes in 2013 compared to 2012.

As a result of the Geismar Incident, ethylene sales volumes have decreased 56 percent in 2013 compared to 2012.

Volatile commodity prices

NGL margins were approximately 40 percent lower in 2013 compared to 2012 driven by reduced ethane recoveries, as previously mentioned, coupled with lower NGL prices and higher natural gas prices, and the absence of hedge gains recognized in 2012, which primarily increased our realized non-ethane sales prices. However, our average per-unit composite NGL margin in 2013 has increased slightly compared to 2012 as the relative mix of NGL products produced has shifted to a greater proportion of higher-margin non-ethane products.

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NGL margins are defined as NGL revenues less any applicable Btu replacement cost, plant fuel, and third-party transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. Our equity volumes include NGLs where we own the rights to the value from NGLs recovered at our plants under both “keep-whole” processing agreements, where we have the obligation to replace the lost heating value with natural gas, and “percent-of-liquids” agreements whereby we receive a portion of the extracted liquids with no obligation to replace the lost heating value.

The following graph illustrates the effects of this price volatility, notably the decline in equity ethane sales driven by reduced recoveries, as well as the margin differential between ethane and non-ethane products and the relative mix of those products.

Company Outlook

Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas, natural gas products, and crude oil that exists in North America. We seek to accomplish this through further developing our scale positions in current key markets and basins and entering new growth markets and basins where we can become the large-scale service provider. We will maintain a strong commitment to safety, environmental stewardship, operational excellence and customer satisfaction. We believe that accomplishing these goals will position us to deliver an attractive return to our unitholders.

Fee-based businesses are a significant component of our portfolio. As we continue to transition to an overall business mix that is increasingly fee-based, the influence of commodity price fluctuations on our operating results and cash flows is expected to become somewhat less significant.

As previously noted, the financial impact of the Geismar Incident is expected to be significantly mitigated by our insurance policies. We expect the timing of recognizing recoveries under our business interruption policy will favorably impact our operating results in 2014.

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Our business plan for 2014 reflects both significant capital investment and continued growth in distributions. Our planned capital investments for 2014 total approximately $3.6 billion. We also expect approximately 6 percent growth in 2014 per-unit distributions. We expect to maintain an attractive cost of capital and reliable access to capital markets, both of which will allow us to pursue development projects and acquisitions.

Potential risks and obstacles that could impact the execution of our plan include:

• General economic, financial markets, or industry downturn;

• Unexpected significant increases in capital expenditures or delays in capital project execution;

• Lower than anticipated or delay in receiving insurance recoveries associated with the Geismar Incident;

• Limited availability of capital due to a change in our financial condition, interest rates, market or industry conditions;

• Lower than expected levels of cash flow from operations;

• Counterparty credit and performance risk;

• Decreased volumes from third parties served by our midstream business;

• Lower than anticipated energy commodity prices and margins;

• Changes in the political and regulatory environments;

• Physical damages to facilities, including damage to offshore facilities by named windstorms;

• Reduced availability of insurance coverage.

We continue to address these risks through maintaining a strong financial position and ample liquidity, as well as through managing a diversified portfolio of energy infrastructure assets.

In 2014, we anticipate an overall improvement in operating results compared to 2013 primarily due to an increase in our fee based and olefins businesses, partially offset by lower NGL margins and higher operating expenses associated with the growth of our business.

The following factors, among others, could impact our businesses in 2014.

Commodity price changes

NGL and olefin price changes have historically correlated somewhat with changes in the price of crude oil, although NGL, olefin, crude, and natural gas prices are highly volatile and difficult to predict. Commodity margins are highly dependent upon regional supply/demand balances of natural gas as they relate to NGL margins, while olefins are impacted by continued demand within the global economy. NGL prices will benefit from exports to satisfy global demand. NGL products are currently the preferred feedstock for ethylene and propylene production and are expected to remain advantaged over crude-based feedstocks into the foreseeable future.

In 2014, we anticipate slightly higher overall commodity prices as compared to 2013:

• Natural gas prices are expected to be higher in part due to the additional demand to replace the gas volumes withdrawn during the colder than normal weather over the past winter season.

• Ethane prices are expected to be somewhat higher due to a modest increase in demand as well as slightly higher natural gas prices.  

• Propane prices are expected to be higher from an increase in exports and higher natural gas prices.

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• Ethylene prices are expected to be slightly lower as compared to 2013 prices.  The overall ethylene crack spread is also expected to be slightly lower due to the anticipated lower sales price and a projected higher ethane price. 

Gathering, processing, and NGL sales volumes

The growth of natural gas production supporting our gathering and processing volumes is impacted by producer drilling activities, which are influenced by commodity prices including natural gas, ethane and propane prices. In addition, the natural decline in production rates in producing areas impact the amount of gas available for gathering and processing. Due in part to the higher natural gas prices in the early part of the year, we anticipate that overall drilling economics will improve slightly, which will benefit us in the long-term.

• In our Northeast G&P segment, we anticipate significant growth compared to the prior year in our natural gas gathering and processing volumes as our infrastructure grows to support drilling activities in the region.

• In our Atlantic-Gulf segment, we anticipate higher natural gas transportation volumes compared to 2013, as a result of expansion projects placed into service at Transco in 2013 and anticipated to be placed in service in 2014. We also expect higher production handling volumes compared to 2013, following the scheduled completion of Gulfstar FPS™ in third quarter 2014.

• Our West segment expects an unfavorable impact in equity NGL volumes in 2014 compared to 2013, primarily due to a customer contract that expired in September 2013.

• In 2014, we anticipate a continuation of periods when it will not be economical to recover ethane.

Olefin production volumes

Our NGL & Petchem Services segment anticipates higher ethylene volumes in 2014 compared to 2013, substantially due to the repair and expansion of the Geismar plant expected to be in operation in the second quarter of 2014.

Other

• In our NGL & Petchem Services segment, we expect to receive insurance recoveries under our business interruption policy related to the Geismar Incident that will favorably impact our operating results in 2014.

• We anticipate higher operating expenses in 2014 compared to 2013, including depreciation expense related to our growing operations in our Northeast G&P segment and expansion projects in our Atlantic-Gulf and NGL & Petchem Services segments.

• In our Atlantic-Gulf segment, we expect higher equity earnings compared to 2013 following the scheduled completion of Discovery’s Keathley Canyon Connector™ lateral in the fourth quarter of 2014.

Eminence Storage Field leak

On December 28, 2010, we detected a leak in one of the seven underground natural gas storage caverns at our Eminence Storage Field in Mississippi. Due to the leak and related damage to the well at an adjacent cavern, both caverns are out of service. In addition, two other caverns at the field, which were constructed at or about the same time as those caverns, have experienced operating problems, and we have determined that they should also be retired. The event has not affected the performance of our obligations under our service agreements with our customers.

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

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As of December 31, 2013, we have incurred approximately $93 million of these abandonment costs. Management considers these costs to be prudent costs incurred in the abandonment of these caverns. Consistent with the terms of the recent rate case, we expensed $12 million in 2013 related to a portion of the Eminence abandonment regulatory asset that will not be recovered in rates. We have also recognized income of $16 million in 2013 related to insurance recoveries associated with this event.

Expansion Projects

We expect to invest total capital in 2014 among our business segments as follows:

	Expansion Capital
Segment:	(Millions)
Northeast G&P	$	1,400
Atlantic-Gulf	1,300
West	75
NGL & Petchem Services	500

Our ongoing major expansion projects include the following:

Northeast G&P

• Expansion of our gathering infrastructure including compression and gathering pipelines in the Susquehanna Supply Hub in northeastern Pennsylvania as production in the Marcellus increases. The Susquehanna Supply Hub is expected to reach a natural gas take away capacity of 3 Bcf/d by 2015.

• As previously discussed, we completed construction at our Fort Beeler facility in the Marcellus Shale, which added 200 MMcf/d of processing capacity in the second quarter of 2013. We have several significant projects under construction with targeted construction completion in the first half of 2014. We are completing a 43 Mbbls/d expansion of the Moundsville fractionator, installation of 40 Mbbls/d of deethanization capacity, a 50-mile ethane pipeline, condensate stabilization, and the first 200 MMcf/d of processing at Oak Grove.

• Expansions to the Laurel Mountain gathering system infrastructure to increase the capacity to 667 MMcf/d by the end of 2015 through capital to be invested within this equity investment.

• Construction of the Blue Racer Midstream joint project, an expansion to gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica Shale, primarily in Ohio and Northwest Pennsylvania through capital to be invested within our Caiman II equity investment. Expansion plans include the addition of Natrium II, a second 200 MMcf/d processing plant, at Natrium by the end of the first quarter of 2014. Construction of an additional 200 MMcf/d processing plant is underway at the Berne complex in Monroe County, Ohio. Berne I is expected to come online in the third quarter of 2014.

Atlantic-Gulf

• We will design, construct, and install our Gulfstar FPS™, a spar-based floating production system that utilizes a standard design approach with a capacity of 60 Mbbls/d of oil, up to 200 MMcf/d of natural gas, and the capability to provide seawater injection services, as previously discussed. Construction is under way and the project is expected to be in service in the third quarter of 2014. The previously discussed expansion that increases Gulfstar One’s production handling capacity related to the Gunflint Development is expected to be completed in mid- 2016, dependent on the producer’s development activities.

• Discovery is constructing a 215-mile, 20-inch deepwater lateral pipeline in the central deepwater Gulf of Mexico that it will own and operate. Discovery has signed long-term agreements with anchor customers for natural gas gathering and processing services for production from the Keathley Canyon and Green Canyon areas. The Keathley Canyon Connector™ lateral will originate from a third-party floating production facility in the southeast portion of the Keathley Canyon area and will connect to Discovery’s existing 30-inch offshore

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natural gas transmission system. The gas will be processed at Discovery’s Larose Plant and the NGLs will be fractionated at Discovery’s Paradis Fractionator. The lateral pipeline is estimated to have the capacity to flow more than 400 MMcf/d and will accommodate the tie-in of other deepwater prospects. The pipeline is expected to be in service in the fourth quarter of 2014.

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

• In September 2013, we filed an application with the FERC for Transco’s Leidy Southeast Expansion project to expand our existing natural gas transmission system from the Marcellus Shale production region on Transco’s Leidy Line in Pennsylvania to delivery points along its mainline as far south as Station 85 in Alabama. We plan to place the project into service during the fourth quarter of 2015, and expect it to increase capacity by 525 Mdth/d.

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

• In June 2013, we filed an application with the FERC for authorization to construct and operate the new jointly owned Constitution pipeline. We currently own 41 percent of Constitution with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We will be the operator of Constitution. The 120-mile Constitution pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We plan to place the project into service in late 2015 to 2016, with an expected capacity of 650 Mdth/d. The pipeline is fully subscribed with two shippers.

• In April 2013, we filed an application with the FERC for Transco’s Northeast Connector project to expand our existing natural gas transmission system from southeastern Pennsylvania to the proposed Rockaway Delivery Lateral. We plan to place the project into service during the second half of 2014, and expect it to increase capacity by 100 Mdth/d.

• In January 2013, we filed an application with the FERC for Transco’s Rockaway Delivery Lateral project to construct a three-mile offshore lateral to a distribution system in New York. We plan to place the project into service during the second half of 2014, the capacity of the lateral is expected to be 647 Mdth/d.

• In December 2012, we filed an application with the FERC for Transco’s Virginia Southside project to expand our existing natural gas transmission system from New Jersey to a proposed power station in Virginia and a delivery point in North Carolina. We plan to place the project into service during the third quarter of 2015, and expect it to increase capacity by 270 Mdth/d.

West

• Due to a reduction in drilling in the Piceance basin during 2012 and early 2013, we delayed the in-service date of our 350 MMcf/d cryogenic natural gas processing plant in Parachute that was planned for service in 2014. We are currently planning an in-service date in mid-2016. We will continue to monitor the situation to determine whether a different in-service date is warranted.

NGL & Petchem Services

• As a result of the Geismar Incident, the expansion of our Geismar olefins production facility is expected to be completed when the Geismar plant returns to operation, which is expected to occur in June 2014. The

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expansion is expected to increase the facility’s ethylene production capacity by 600 million pounds per year to a new annual capacity of 1.95 billion pounds. The additional capacity will be wholly owned by us and is expected to increase our ownership of the Geismar production facility from the current 83.3 percent.

Critical Accounting Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. We have reviewed the selection, application, and disclosure of these critical accounting estimates with our general partner’s Audit Committee. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.

Goodwill

At December 31, 2013, our Consolidated Balance Sheet includes $646 million of goodwill. We performed our annual assessment of goodwill for impairment as of October 1. All of our goodwill is allocated to our Northeast G&P segment (the reporting unit). In our evaluation, our estimate of the fair value of the reporting unit exceeded its carrying value by 15 percent, including goodwill, and thus no impairment was recognized in 2013. The fair value of the reporting unit was estimated by an income approach utilizing discounted cash flows and corroborated with a market capitalization analysis.

Judgments and assumptions are inherent in our estimate of future cash flows used to evaluate these assets. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of an impairment charge in the consolidated financial statements. Our calculation of fair value used a discount rate of 10.5 percent. We estimate that an increase of approximately 140 basis points in the discount rate could result in a fair value of the reporting unit below its carrying value, all other variables held constant.

Equity-method investments

At December 31, 2013, our Consolidated Balance Sheet includes approximately $2.2 billion of investments that are accounted for under the equity method of accounting. We evaluate these investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We generally estimate the fair value of our investments using an income approach where significant judgments and assumptions include expected future cash flows and the appropriate discount rate. In some cases, we may utilize a form of market approach to estimate the fair value of our investments.

If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge. Events or changes in circumstances that may be indicative of an other-than-temporary decline in value will vary by investment, but may include: 

• Lower than expected cash distributions from investees;

• Significant asset impairments or operating losses recognized by investees;

• Significant delays in or lack of producer development or significant declines in producer volumes in markets served by investees;

• Significant delays in or failure to complete significant growth projects of investees.

No impairments of investments accounted for under the equity method have been recorded for the year ended December 31, 2013.

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Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2013. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

	Years Ended December 31,
	2013			$ Change from 2012*	% Change from 2012*	2012			$ Change from 2011*	% Change from 2011*	2011
	(Millions)
Revenues:
Service revenues	$	2,910		+201	+7%	$	2,709		+192	+8%	$	2,517
Product sales	3,775			-836	-18%	4,611			-586	-11%	5,197
Total revenues	6,685					7,320					7,714
Costs and expenses:
Product costs	3,048			+478	+14%	3,526			+425	+11%	3,951
Operating and maintenance expenses	1,029			-42	-4%	987			-39	-4%	948
Depreciation and amortization expenses	758			-44	-6%	714			-93	-15%	621
Selling, general, and administrative expenses	493			+60	+11%	553			-147	-36%	406
Other (income) expense – net	15			+8	+35%	23			-10	-77%	13
Total costs and expenses	5,343					5,803					5,939
Operating income	1,342					1,517					1,775
Equity earnings (losses)	104			-7	-6%	111			-31	-22%	142
Interest expense	(387		)	+18	+4%	(405		)	+10	+2%	(415		)
Other income (expense) – net	11			+2	+22%	9			—	—	9
Net income	1,070					1,232					1,511
Less: Net income attributable to noncontrolling interests	3			-3	NM	—			—	—	—
Net income attributable to controlling interests	$	1,067				$	1,232				$	1,511

* + = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.

2013 vs. 2012

The increase in Service revenues is primarily due to higher fee revenues associated with the growth in the businesses acquired in the 2012 Caiman and Laser Acquisitions, as well as contributions from the processing and fractionation facilities placed in service in the latter half of 2012 and in 2013. Additionally, natural gas transportation fee revenues increased from expansion projects placed into service in 2012 and 2013 and new rates effective during first-quarter 2013. Partially offsetting these increases are decreased gathering and processing fee revenues driven by lower volumes in the Piceance, Four Corners and eastern Gulf Coast areas.

The decrease in Product sales is primarily due to lower NGL production revenues driven by reduced ethane recoveries and decreases in average realized NGL per-unit sales prices, as well as a decrease in olefin production revenues primarily from the loss of production as a result of the Geismar Incident, partially offset by higher olefin per-unit sales prices. Additionally, marketing revenues decreased resulting from lower NGL per-unit prices and lower crude oil and ethane volumes, partially offset by higher non-ethane volumes. The changes in marketing revenues are more than offset by similar changes in marketing purchases, reflected above as Product costs.

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The decrease in Product costs is primarily due to a decrease in NGL marketing purchases resulting from lower NGL prices and lower crude oil volumes, partially offset by higher non-ethane volumes. The changes in marketing purchases are substantially offset by similar changes in marketing revenues. In addition, olefin feedstock purchases decreased reflecting lower volumes and lower average per-unit feedstock costs. Costs associated with the production of NGLs also decreased primarily resulting from lower ethane recoveries, partially offset by an increase in average natural gas prices.

The increase in Operating and maintenance expenses is primarily associated with the subsequent growth in the operations of the businesses acquired in the Caiman and Laser Acquisitions and $13 million of costs incurred under our insurance deductibles resulting from the Geismar Incident. These increases are partially offset by lower compressor and natural gas pipeline maintenance and repair expenses primarily due to the absence of expenses related to the substantial completion of our natural gas pipeline integrity management plan during 2012, and lower operating costs in our Four Corners area, which experienced lower volumes.

The increase in Depreciation and amortization expenses reflects a full year of depreciation and amortization expense in 2013 associated with the businesses acquired in 2012 and depreciation on subsequent infrastructure additions, partially offset by the absence of increased depreciation in 2012 on certain assets in the Gulf Coast region resulting from a change in the estimated useful lives.

The decrease in Selling, general, and administrative expenses (SG&A) is primarily due to a reduction in allocated administrative expenses from Williams reflecting the absence of reorganization related costs incurred in 2012 (see Note 5 – Related Party Transactions of Notes to Consolidated Financial Statements) and the absence of acquisition and transition costs incurred in 2012 (see Note 2 – Acquisitions, Goodwill, and Other Intangible Assets of Notes to Consolidated Financial Statements).

Other (income) expense – net within Operating income includes the following decreases to net expense:

• $40 million of income associated with net insurance recoveries related to the Geismar Incident in 2013;

• $16 million of income from insurance recoveries related to the abandonment of certain of Eminence storage assets in 2013;

• $9 million involuntary conversion gain recognized in 2013 related to a 2012 furnace fire for our Geismar olefins plant.

Other (income) expense – net within Operating income includes the following increases to net expense:

• $25 million accrued loss for a settlement in principle of a producer claim against us;

• $23 million increase in amortization expense related to our regulatory asset associated with asset retirement obligations;

• $12 million expense recognized in 2013 related to the portion of the Eminence abandonment regulatory asset that will not be recovered in rates.

The decrease in Operating income generally reflects lower NGL production margins, lower olefin production margins, and higher operating costs, partially offset by increased fee revenues, higher marketing margins, lower SG&A expenses, and the net favorable changes in Other (income) expense – net as described above.

The unfavorable change in Equity earnings (losses) is primarily due to lower equity earnings from Discovery. This increase is partially offset by improved equity earnings from Laurel Mountain.

Interest expense decreased due to a $33 million increase in Interest capitalized related to construction projects, partially offset by a $15 million increase in Interest incurred primarily due to an increase in borrowings. (See Note 11 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements).

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2012 vs. 2011

The increase in Service revenues is primarily due to increased gathering and processing fee revenues from higher volumes in the Marcellus Shale, including new volumes from the 2012 Caiman and Laser Acquisitions and higher volumes in the western deepwater Gulf of Mexico and in the Piceance basin. Additionally, natural gas pipeline transportation revenues increased from expansion projects placed into service in 2011 and 2012.

The decrease in Product sales is primarily due to lower NGL and olefin production revenues reflecting an overall decrease in average per-unit sales prices. Marketing revenues also decreased primarily due to significant decreases in NGL and olefin prices, partially offset by higher NGL and crude oil volumes, as well as new volumes from natural gas marketing activities.

The decrease in Product costs is primarily due to lower olefins feedstock costs reflecting a decrease in average per-unit prices and lower costs associated with the production of NGLs primarily due to a decrease in average natural gas prices. Marketing purchases also decreased primarily resulting from significantly lower average NGL prices, partially offset by higher NGL and crude oil volumes, as well as new volumes from natural gas marketing activities.

The increase in Operating and maintenance expenses is primarily due to increased employee-related benefit costs and increased pipeline maintenance as well as increased maintenance expenses primarily associated with our gathering and processing assets acquired in 2012, partially offset by lower costs in our Four Corners area related to the consolidation of certain operations.

The increase in Depreciation and amortization expenses is primarily associated with our gathering and processing assets acquired in 2012 (see Note 2 – Acquisitions, Goodwill, and Other Intangible Assets of Notes to Consolidated Financial Statements).

The increase in SG&A includes $66 million of higher allocated administrative costs from Williams reflecting our higher proportionate share of these costs and $25 million of reorganization-related costs in 2012 primarily relating to Williams’ engagement of a consulting firm to assist in better aligning resources to support our business strategy following Williams’ spin-off of WPX, which was completed December 31, 2011. SG&A in 2012 also includes $23 million of acquisition and transition-related costs as well as higher employee-related and information technology expenses driven by general growth within our midstream operations.

The decrease in Operating income generally reflects lower NGL production and marketing margins, as well as previously described increases in Operating and maintenance expenses, Depreciation and amortization expenses, and SG&A. Higher fee revenues and olefin production margins partially offset these decreases.

Equity earnings (losses) changed unfavorably primarily reflecting lower operating results at Laurel Mountain, Aux Sable, and Discovery and the impairment of two minor NGL processing plants at Laurel Mountain, partially offset by an increase in equity earnings resulting from the acquisition of an additional 24.5 percent interest in Gulfstream in May 2011.

Interest expense decreased due to an increase in Interest capitalized related primarily to gathering and processing construction projects, partially offset by an increase in Interest incurred related to increased borrowings.

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Year-Over-Year Operating Results – Segments

Northeast G&P

	Years Ended December 31,
	2013			2012			2011
	(Millions)
Service revenues	$	335		$	168		$	49
Product sales	166			2			—
Segment revenues	501			170			49
Product costs	160			4			—
Depreciation and amortization expenses	132			76			5
Other segment costs and expenses	226			104			20
Equity (earnings) losses	7			23			1
Segment profit (loss)	$	(24	)	$	(37	)	$	23

Our Northeast G&P segment includes our Susquehanna Supply Hub (primarily resulting from the acquisition of certain assets in 2010 and the Laser Acquisition in February 2012), our Ohio Valley Midstream business (primarily resulting from the Caiman Acquisition in April 2012), and our equity-method investments in Laurel Mountain and Caiman Energy II.

2013 vs. 2012

Service revenues increased due primarily to $129 million in higher gathering fees associated with 78 percent higher volumes driven by new well connections related to infrastructure additions placed into service in 2012 and 2013, a full year of operations associated with the gathering systems included in the 2012 acquisitions, and increased gathering rates associated with customer contract modifications primarily in the Susquehanna Supply Hub. Service revenues also reflect contributions from the processing and fractionation facilities placed in service in the latter half of 2012 and in 2013 in our Ohio Valley Midstream business.

Product sales in 2013 primarily represent new NGL marketing revenues attributable to the Ohio Valley Midstream business. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as product costs.

Depreciation and amortization expenses reflect a full year of expenses in 2013 associated with the acquired businesses and depreciation on subsequent infrastructure additions.

Other segment costs and expenses increased primarily due to higher expenses associated with the acquired businesses and the subsequent growth in these operations. This increase includes approximately $26 million in higher employee-related costs and $19 million in higher outside service operating expenses including $15 million related to pipeline maintenance and repair costs. In addition, 2013 reflects a $25 million accrued loss for a settlement in principle of a producer claim against us and higher allocated support costs due to the relative growth in the businesses. These increases are partially offset by the absence of $23 million related to acquisition and transition costs incurred in 2012.

Equity (earnings) losses changed favorably primarily due to $15 million improved Laurel Mountain equity earnings driven primarily by 55 percent higher gathering volumes, the receipt of an annual minimum volume commitment fee in 2013, and lower leased compression expenses.

The favorable change in Segment profit (loss) is primarily due to an increase in fee revenues in the Susquehanna Supply Hub and Ohio Valley Midstream businesses, improved Laurel Mountain equity earnings and the absence of acquisition and transition costs incurred in 2012. These increases are partially offset by higher costs primarily in our Ohio Valley Midstream business and a $25 million charge associated with the settlement in principle of a producer claim against us.

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2012 vs. 2011

Service revenues increased due to a $118 million increase in fee revenues primarily due to higher volumes in the Marcellus Shale, including new volumes on gathering and processing assets acquired in 2012 in our Ohio Valley Midstream and Susquehanna Supply Hub businesses.

Depreciation and amortization expenses increased due to the assets and intangibles acquired in 2012.

Other segment costs and expenses increased primarily due to a $42 million increase in other operating costs and expenses also generally associated with assets acquired in 2012 and a $40 million increase in general and administrative expenses including $23 million of Caiman and Laser acquisition and transition-related costs, as well as increases in employee-related and information technology expenses driven by general growth within our business operations.

Equity (earnings) losses changed unfavorably primarily due to $19 million lower Laurel Mountain equity earnings driven by lower gathering rates indexed to natural gas prices, higher operating costs, including depreciation, and the impairment of two minor NGL processing plants, partially offset by higher gathering volumes.

The unfavorable change in Segment profit (loss) is primarily due to the previously described increases in depreciation and amortization expenses, other operating costs and general and administrative expenses, and lower Laurel Mountain equity earnings. These changes were partially offset by higher fee revenues.

Atlantic-Gulf

	Years Ended December 31,
	2013			2012			2011
	(Millions)
Service revenues	$	1,424		$	1,383		$	1,332
Product sales	925			1,072			1,137
Segment revenues	2,349			2,455			2,469
Product costs	843			956			1,005
Depreciation and amortization expenses	363			381			365
Other segment costs and expenses	601			636			604
Equity (earnings) losses	(72		)	(92		)	(90		)
Segment profit	$	614		$	574		$	585
NGL margin	$	79		$	113		$	126

2013 vs. 2012

Service revenues increased primarily due to a $72 million increase in natural gas transportation fee revenues primarily associated with expansion projects placed in service in 2012 and 2013 and to the implementation of new rates for Transco in March 2013. These increases are partially offset by $34 million lower fee revenues in the eastern Gulf Coast primarily driven by natural declines in Bass Lite and Blind Faith production area volumes.

Product sales decreased primarily due to:

• A $158 million decrease in marketing revenues reflecting a $120 million decrease in crude oil marketing sales and a $38 million decrease in NGL marketing sales. Crude oil marketing sales decreased primarily due to 25 percent lower crude oil volumes related to natural declines in production areas served by our Mountaineer crude oil pipeline. NGL marketing sales decreased primarily due to lower NGL prices. These changes in marketing revenues are offset by similar changes in marketing purchases.

• A $39 million decrease in revenues from our equity NGLs reflecting a decrease of $21 million associated with lower equity NGL sales volumes and a decrease of $18 million associated with lower average realized NGL per-unit sales prices. Equity NGL sales volumes are 29 percent lower driven by 56 percent lower ethane

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volumes due primarily to unfavorable ethane economics, as previously mentioned, and 7 percent lower non-ethane volumes. Average realized ethane and non-ethane per-unit sales prices decreased by 54 percent and 11 percent, respectively.

• A $48 million increase in other product sales primarily due to higher system management gas sales from Transco. System management gas sales are offset in Product costs and, therefore, have no impact on Segment profit.

Product costs decreased primarily due to:

• A $158 million decrease in crude oil and NGL marketing purchases (offset in Product sales).

• A $5 million decrease in costs associated with our equity NGLs primarily due to an $11 million decrease associated with lower natural gas volumes, partially offset by a $6 million increase related to higher per-unit natural gas prices.

• A $48 million increase in other product costs primarily due to higher system management gas costs (offset in Product sales).

Depreciation and amortization expenses decreased primarily reflecting the absence of increased depreciation in 2012 on certain assets in the Gulf Coast region resulting from a change in the estimated useful lives.

Other segment costs and expenses decreased primarily due to lower operating costs, including compressor and pipeline maintenance and repair expenses resulting from the absence of expenses relating to the substantial completion of a natural gas pipeline integrity management plan during 2012, lower project development costs, and insurance recoveries recognized by Transco in 2013 related to the abandonment of certain of its Eminence storage assets. These decreases are partially offset by increased amortization of regulatory assets associated with asset retirement obligations, a decrease in reversals of project feasibility costs from expense to capital associated with expansion projects, and expense recognized in 2013 related to the portion of the Eminence abandonment regulatory asset that is not expected to be recovered in rates.

Equity earnings decreased primarily due to lower equity earnings from Discovery driven by lower NGL margins reflecting lower volumes including reduced ethane recoveries and natural declines, as well as lower NGL prices.Additionally, charges to write-down two lateral pipelines and electrical equipment in 2013 and the absence of a favorable customer settlement in 2012 decreased our equity earnings from Discovery.

Segment profit increased primarily due to higher service revenues and lower operating and depreciation expenses, partially offset by $34 million lower NGL margins reflecting commodity price changes including lower NGL sales prices coupled with higher per-unit natural gas costs and lower volumes, increased amortization of regulatory assets associated with asset retirement obligations, and lower equity earnings, as previously discussed.

2012 vs. 2011

Service revenues increased due to a $51 million increase in fee revenues primarily due to an increase in transportation revenues associated with expansion projects placed in service during 2011 and 2012 on our interstate natural gas pipeline and higher gas gathering and oil transportation volumes in the western deepwater Gulf of Mexico, including higher volumes on our Perdido Norte natural gas and oil pipelines, partially offset by lower volumes in the eastern deepwater Gulf of Mexico primarily due to natural field declines.

Product sales decreased primarily due to:

• A $49 million decrease in other product sales due primarily to a $39 million decrease in system management gas sales (offset in Product costs).

• A $25 million decrease in revenues from our equity NGLs primarily reflecting a decrease of $37 million associated with an overall 19 percent decrease in average NGL per-unit sales prices. Average ethane and non-ethane per-unit prices decreased by 48 percent and 12 percent, respectively.

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• An $8 million increase in marketing revenues reflecting an increase of $73 million driven by higher crude oil volumes and an $86 million increase driven by higher non-ethane volumes, partially offset by a $148 million decrease driven by lower ethane and non-ethane prices. The changes in marketing revenues are offset by similar changes in marketing purchases.

Product costs decreased primarily due to:

• A $44 million decrease in other product costs due primarily to a $39 million decrease in system management gas costs (offset in Product sales).

• A $12 million decrease in costs associated with our equity NGLs primarily due to a 34 percent decrease in average natural gas prices.

Depreciation and amortization expenses increased $16 million primarily resulting from accelerated depreciation of our Canyon Station production handling platform in the eastern deepwater Gulf of Mexico and additional Transco assets placed in service in 2011.

Other segment costs and expenses increased primarily due to a $20 million increase in operating costs and expenses including higher employee-related benefits costs, pipeline maintenance costs, and project feasibility costs, partially offset by lower operations and maintenance expense associated with the Eminence Storage Field leak and an increase in reversals of project feasibility costs from expense to capital associated with expansion projects. Additionally, general and administrative expenses increased $12 million primarily due to higher employee-related, information technology services and rental costs.

Equity earnings increased primarily due to an $11 million increase related to the acquisition of an additional interest in Gulfstream in May 2011, partially offset by $12 million lower Discovery equity earnings primarily due to lower NGL margins and volumes.

Segment profit decreased primarily due to a $48 million increase in depreciation, operating costs and expenses and general and administrative expenses, as previously discussed, and a $13 million decrease in NGL margins driven primarily by commodity price changes including lower NGL prices, partially offset by lower natural gas prices. These decreases were partially offset by a $51 million increase in fee revenues, as previously discussed.

West

	Years Ended December 31,
	2013		2012		2011
	(Millions)
Service revenues	$	1,054	$	1,072	$	1,057
Product sales	772		1,129		1,633
Segment revenues	1,826		2,201		2,690
Product costs	380		472		760
Depreciation and amortization expenses	236		234		236
Other segment costs and expenses	469		515		513
Segment profit	$	741	$	980	$	1,181
NGL margin	$	369	$	637	$	854

2013 vs. 2012

Service revenues decreased primarily due to a $43 million decrease in gathering and processing fee revenues primarily due to a natural decline in production volumes, primarily in the Piceance basin and Four Corners area, and

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severe winter weather conditions in the first quarter of 2013 which prevented producers from delivering gas. Transportation revenues increased $30 million, primarily related to new rates effective January 1, 2013 at Northwest Pipeline.

Product sales decreased primarily due to:

• A $314 million decrease in revenues from our equity NGLs primarily reflecting a decrease of $242 million due to lower volumes and a $72 million decrease associated with 10 percent lower average realized non-ethane per-unit sales prices and 42 percent lower average ethane per-unit sales prices. Equity ethane sales volumes are 84 percent lower driven by reduced ethane recoveries and equity non-ethane volumes are 11 percent lower due primarily to a customer contract that expired in September 2013 and a change in a customer’s contract at the end of 2012 to fee-based processing, along with periods of local severe winter weather conditions in the first quarter of 2013 which prevented producers from delivering gas.

• A $46 million decrease in NGL marketing revenues due primarily to 68 percent lower ethane volumes (more than offset in Product costs).

Product costs decreased primarily due to:

• A $47 million decrease in NGL marketing purchases (substantially offset in Product sales).

• A $44 million decrease in costs associated with our equity NGLs reflecting an $82 million decrease associated with lower natural gas volumes, partially offset by a $38 million increase related to a 32 percent increase in average natural gas prices.

Other segment costs and expenses decreased primarily due to lower allocated support costs due to relative growth in the other segments, as well as increased operating efficiencies and lower volumes in our Four Corners area which resulted in reduced operating costs, including operating lease payments and materials and supplies.

Segment profit decreased primarily due to $268 million lower NGL margins reflecting lower NGL volumes, lower average NGL prices, and higher average natural gas prices, as well as the decrease in gathering and processing fee revenues, partially offset by lower operating costs in our Four Corners area, lower allocated support expenses, and increased natural gas transportation revenues.

2012 vs. 2011

Service revenues increased primarily due to a $14 million increase in fee revenues resulting from higher gas gathering and processing volumes in the Piceance basin.

Product sales decreased primarily due to:

• A $343 million decrease in revenues from our equity NGLs primarily reflecting a decrease of $314 million associated with an overall 27 percent decrease in average NGL per-unit sales prices. Average ethane and non-ethane per-unit prices decreased by 49 percent and 15 percent, respectively.

• A $159 million decrease in marketing revenues primarily due to significantly lower average NGL prices and 11 percent lower NGL volumes. The changes in marketing revenues are offset by similar changes in marketing purchases.

Product costs decreased primarily due to:

• A $159 million decrease in marketing purchases primarily due to significantly lower average NGL prices and lower NGL volumes. These changes are offset by similar changes in marketing revenues.

• A $126 million decrease in costs associated with our equity NGLs primarily due to a 31 percent decrease in average natural gas prices.

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Other segment costs and expenses increased primarily due to a $20 million increase in general and administrative expenses including increases in employee-related, information technology services and rental costs, significantly offset by a $19 million decrease in other operating costs and expenses due primarily to lower costs in our Four Corners area related to the consolidation of certain operations.

Segment profit decreased primarily due to a $217 million decrease in NGL margins driven primarily by commodity price changes including lower NGL prices, partially offset by lower natural gas prices. This decrease was partially offset by a $14 million increase in fee revenues, as previously discussed.

NGL & Petchem Services

	Years Ended December 31,
	2013			2012			2011
	(Millions)
Service revenues	$	108		$	103		$	83
Product sales	3,009			4,118			4,636
Segment revenues	3,117			4,221			4,719
Product costs	2,774			3,822			4,400
Depreciation and amortization expenses	27			23			15
Other segment (income) costs and expenses	80			123			111
Equity (earnings) losses	(39		)	(42		)	(53		)
Segment profit	$	275		$	295		$	246
Olefins margin	$	206		$	298		$	192
Marketing margin	21			(11		)	34

2013 vs. 2012

Product sales decreased primarily due to:

• A $798 million decrease in marketing revenues due primarily to lower NGL volumes and prices, partially offset by higher natural gas volumes and prices. These changes are more than offset in Product costs.

• A $312 million decrease in olefin sales due to $363 million of lower volumes, partially offset by $51 million associated with higher per-unit sales prices. Olefin production volumes are lower primarily due to the loss of production as a result of the Geismar Incident, an outage in a third-party storage facility which caused us to reduce production at our RGP splitter facility and changes in inventory management. Ethylene and propylene prices averaged 21 percent and 11 percent higher, respectively, partially offset by 29 percent lower butadiene prices.

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Product costs decreased primarily due to:

• An $830 million decrease in NGL marketing purchases partially offset by increased natural gas marketing purchases (substantially offset in Product sales).

• A $220 million decrease in olefin feedstock purchases due to $207 million of lower volumes, primarily due to the loss of production as a result of the Geismar Incident, the third-party storage facility outage discussed above, and $13 million lower feedstock costs, reflecting 21 percent lower average per-unit ethylene feedstock prices, partially offset by 11 percent higher average per-unit propylene feedstock prices.

Other segment (income) costs and expenses improved primarily due to the recognition of $40 million of income associated with net insurance recoveries related to the Geismar Incident during 2013, $9 million involuntary conversion gains related to a 2012 furnace fire at our Geismar olefins plant, and the absence of $5 million of furnace repair expenses incurred during 2012. Partially offsetting this favorable impact are $13 million of costs incurred under our insurance deductibles associated with the Geismar Incident.

Segment profit decreased primarily due to lower olefin product margins and $13 million of costs incurred under our insurance deductibles discussed above. Partially offsetting these decreases is the $40 million net insurance recovery discussed above, higher marketing margins, $9 million involuntary conversion gains related to a 2012 furnace fire at our Geismar olefins plant and the absence of $5 million of furnace repair expenses incurred during 2012. Olefin margins decreased $92 million, including $156 million lower product volumes at our Geismar plant partially offset by $41 million higher ethylene prices and $21 million lower ethylene feedstock costs. Marketing margins are $32 million higher primarily due to favorable prices in 2013 and the absence of losses recognized in the second quarter of 2012 which were driven by significant declines in NGL prices while product was in transit.

2012 vs. 2011

Service revenues increased primarily due to a $20 million increase in fee revenues including increases at our Gulf Olefin pipeline systems and Conway storage and fractionation facilities.

Product sales decreased primarily due to:

• A $441 million decrease in marketing revenues primarily due to a significant decrease in NGL and olefin prices, partially offset by higher NGL volumes, as well as new volumes from natural gas marketing activities.

• A $77 million decrease in olefin sales revenues including $42 million lower ethylene production sales revenues primarily due to 10 percent lower average per-unit sales prices and $26 million lower propylene production sales revenues primarily due to 17 percent lower average per-unit sales prices.

Product costs decreased primarily due to:

• A $396 million decrease in marketing costs primarily due to significantly lower average NGL prices, partially offset by higher NGL volumes, as well as new volumes from natural gas marketing activities. The changes in natural gas marketing purchases are more than offset by similar changes in natural gas marketing revenues.

• A $183 million decrease in olefin feedstock costs, including $130 million lower ethylene feedstock costs driven by 38 percent lower average per-unit feedstock costs and $28 million lower propylene feedstock costs primarily due to 20 percent lower per-unit feedstock costs.

Depreciation and amortization expenses increased $8 million primarily due to accelerated depreciation on assets that will become obsolete with the Geismar expansion project.

Other segment (income) costs and expenses changed unfavorablyprimarily due to a $9 million increase in general and administrative expenses including increases in employee-related and information technology services expenses.

Equity earnings decreased primarily due to lower equity earnings from Aux Sable driven by lower gas processing margins.

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Segment profit increased primarily due to a $106 million increase in olefin product margins including $88 million higher ethylene production margins and $13 million higher DAC production margins. Additionally, fee revenues increased $20 million, as previously discussed. Partially offsetting these increases is a $45 million decrease in margins related to the marketing of NGLs and a $7 million unfavorable change in write-downs of inventories to lower of cost or market. Also offsetting the increases to segment profit is an $11 million decrease in equity earnings, a $9 million increase in general and administrative expenses, and an $8 million increase in depreciation expense, as previously discussed.

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Management’s Discussion and Analysis of Financial Condition and Liquidity

Overview

In 2013, we continued to focus upon both growth in our businesses through disciplined investment and growth in our per-unit distributions. Examples of this growth included:

• Expansion of our interstate natural gas pipeline system to meet the demand of growth markets;

• Continued investment in our gathering and processing capacity and infrastructure in the Marcellus Shale area and the deepwater Gulf of Mexico, as well as expanding our olefins business in the Gulf Coast region;

• Total per-unit distributions grew almost 9 percent to $3.415 in 2013 compared to $3.14 in 2012.

This growth was funded primarily through cash flow from operations and debt and equity offerings.

Outlook

We seek to manage our businesses with a focus on applying conservative financial policy in order to maintain investment-grade credit metrics. Our plan for 2014 reflects our ongoing transition to an overall business mix that is increasingly fee-based. Although our cash flows are impacted by fluctuations in energy commodity prices, that impact is somewhat mitigated by certain of our cash flow streams that are not directly impacted by short-term commodity price movements, including:

• Firm demand and capacity reservation transportation revenues under long-term contracts;

• Fee-based revenues from certain gathering and processing services.

We believe we have, or have access to, the financial resources and liquidity necessary to meet our requirements for working capital, capital and investment expenditures, unitholder distributions, and debt service payments while maintaining a sufficient level of liquidity. In particular, we note the following:

• We increased our per-unit quarterly distribution with respect to the fourth quarter of 2013 from $0.8775 to $0.8925. We expect to increase quarterly limited partner per-unit cash distributions by approximately 6 percent in 2014 and 2015.

• We expect to fund working capital requirements, capital and investment expenditures, debt service payments, and distributions to unitholders primarily through cash flow from operations, cash and cash equivalents on hand, issuances of debt and/or equity securities, and utilization of our credit facility and/or commercial paper program. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $2.95 billion and $3.3 billion in 2014. In addition, we retain the flexibility to adjust our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities.

Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2014. Our internal and external sources of liquidity include:

• Cash and cash equivalents on hand;

• Cash generated from operations, including cash distributions from our equity-method investees and expected business interruption proceeds related to the Geismar Incident;

• Cash proceeds from issuances of debt and/or equity securities;

• Use of our credit facility and/or commercial paper program.

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We anticipate our more significant uses of cash to be:

• Maintenance and expansion capital expenditures;

• Contributions to our equity-method investees to fund their expansion capital expenditures;

• Interest on our long-term debt;

• Quarterly distributions to our unitholders and general partner.

Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include those previously discussed in Company Outlook.

As of December 31, 2013, we had a working capital deficit (current liabilities, inclusive of commercial paper borrowings, in excess of current assets) of $780 million. However, we note the following about our available liquidity.

Available Liquidity	December 31, 2013
	(Millions)
Cash and cash equivalents	$	102
Capacity available under our $2.5 billion five-year credit facility (expires July 31, 2018), less amounts outstanding under the $2 billion commercial paper program (1)	2,275
	$	2,377

__________

(1) The highest amount outstanding during 2013 was $1.085 billion under our commercial paper program. As of February 25, 2014, $900 million is outstanding under our commercial paper program. At December 31, 2013, we are in compliance with the financial covenants associated with this credit facility and commercial paper program. (See Note 11 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.) On July 31, 2013, we amended our $2.4 billion credit facility to increase the aggregate commitments to $2.5 billion and extend the maturity date to July 31, 2018. The full amount of the credit facility is available to us, to the extent not otherwise utilized by Transco and Northwest Pipeline, and may, under certain conditions, be increased by up to an additional $500 million. Transco and Northwest Pipeline are each able to borrow up to $500 million under the credit facility to the extent not otherwise utilized by the other co-borrowers. In managing our available liquidity, we do not expect a maximum outstanding amount under this commercial paper program in excess of the capacity available under our credit facility.

Commercial Paper

In March 2013, we initiated a commercial paper program. The program allows a maximum outstanding amount at any time of $2 billion of unsecured commercial paper notes. The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. Proceeds from these notes are used for general partnership purposes, including funding capital expenditures, working capital, and partnership distributions. We classify these commercial paper notes outstanding as short-term borrowings as they have maturity dates less than three months from the date of issuance. At December 31, 2013, we had $225 million in commercial paper outstanding.

Debt Offering

In November 2013, we completed a public offering of $600 million of 4.5 percent senior unsecured notes due 2023 and $400 million of 5.8 percent senior unsecured notes due 2043. We used the net proceeds to repay amounts outstanding under our commercial paper program, to fund capital expenditures, and for general partnership purposes.

Distributions from Equity-Method Investees

Our equity-method investees’ organizational documents require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective

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businesses. Our more significant equity-method investees include: Aux Sable, Caiman II, Discovery, Gulfstream, Laurel Mountain, and OPPL.

Shelf Registration

In April 2013, we filed a shelf registration statement for the offer and sale from time to time of common units representing limited partner interests in us having an aggregate offering price of up to $600 million. These sales will be made over a period of time and from time to time in transactions at prices which are market prices prevailing at the time of sale, prices related to market price or at negotiated prices. Such sales will be made pursuant to an equity distribution agreement between us and certain banks who may act as sales agents or purchase for their own accounts as principals. As of December 31, 2013, no common units have been issued under this registration.

Equity Offerings

In August 2013, we completed an equity issuance of 21,500,000 common units. Subsequently, the underwriters exercised their option to purchase 3,225,000 common units. The net proceeds of approximately $1.2 billion were used to repay amounts outstanding under our commercial paper program, to fund capital expenditures, and for general partnership purposes.

In March 2013, we completed an equity issuance of 14,250,000 common units, including 3,000,000 common units sold to Williams in a private placement. Subsequently, the underwriters exercised their option to purchase 1,687,500 common units. The net proceeds of approximately $760 million were used to repay amounts outstanding under our credit facility.

Credit Ratings

Our ability to borrow money is impacted by our credit ratings. The current ratings are as follows:

Rating Agency	Outlook	Senior Unsecured Debt Rating
Standard & Poor’s	Stable	BBB
Moody’s Investors Service	Stable	Baa2
Fitch Ratings	Positive	BBB-

With respect to Standard and Poor’s, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” indicates that the security has significant speculative characteristics. A “BB” rating indicates that Standard and Poor’s believes the issuer has the capacity to meet its financial commitment on the obligation, but adverse business conditions could lead to insufficient ability to meet financial commitments. Standard and Poor’s may modify its ratings with a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.

With respect to Moody’s, a rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. The “1”, “2”, and “3” modifiers show the relative standing within a major category. A “1” indicates that an obligation ranks in the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” indicates a ranking at the lower end of the category.

With respect to Fitch, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. Fitch may add a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.

Credit rating agencies perform independent analyses when assigning credit ratings. No assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their current criteria for investment grade ratios. A downgrade of our credit rating might increase our future cost of borrowing and would require us to post additional collateral with third parties, negatively impacting our available liquidity. As of December 31, 2013, we estimate that a downgrade to a rating below investment grade could require us to post up to $282 million in additional collateral with third parties.

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Capital and Investment Expenditures

Each of our businesses is capital-intensive, requiring investment to upgrade or enhance existing operations and comply with safety and environmental regulations. The capital requirements of these businesses consist primarily of:

• Maintenance capital expenditures, which are generally not discretionary, including: (1) capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives, (2) expenditures which are mandatory and/or essential to comply with laws and regulations and maintain the reliability of our operations, and (3) certain well connection expenditures.

• Expansion capital expenditures, which are generally more discretionary than maintenance capital expenditures, including: (1) expenditures to acquire additional assets to grow our business, to expand and upgrade plant or pipeline capacity and to construct new plants, pipelines and storage facilities, and (2) well connection expenditures which are not classified as maintenance expenditures.

The following table provides summary information related to our expected capital expenditures, purchases of businesses, and purchases of and contributions to equity-method investments for 2014. Included are gross increases to our property, plant, and equipment, including changes related to accounts payable and accrued liabilities:

Segment		Maintenance		Expansion		Total
	(Millions)
Northeast G&P		$	20	$	1,400	$	1,420
Atlantic-Gulf		175		1,300		1,475
West		125		75		200
NGL & Petchem Services		20		500		520
Total		$	340	$	3,275	$	3,615

See Company Outlook - Expansion Projects for discussions describing the general nature of these expenditures.

Cash Distributions to Unitholders

We have paid quarterly distributions to unitholders and our general partner after every quarter since our initial public offering on August 23, 2005. We have increased our quarterly distribution from $0.8775 with respect to the third quarter of 2013 to $0.8925 per unit, which resulted in a fourth quarter 2013 distribution of approximately $556 million that was paid on February 13, 2014, to the general and limited partners of record at the close of business on February 6, 2014. (See Note 4 – Allocation of Net Income and Distributions of Notes to Consolidated Financial Statements.)

Sources (Uses) of Cash

	Years Ended December 31,
	2013			2012			2011
	(Millions)
Net cash provided (used) by:
Operating activities	$	2,061		$	2,018		$	2,290
Financing activities	1,374			2,412			(918		)
Investing activities	(3,353		)	(4,573		)	(1,396		)
Increase (decrease) in cash and cash equivalents	$	82		$	(143	)	$	(24	)

Operating activities

The factors that determine operating activities are largely the same as those that affect Net income, with the exception of noncash expenses such as Depreciation and amortization. Our Net cash provided by operating activities in 2013 increased from 2012 primarily due to proceeds from insurance recoveries on the Eminence Storage Field leak and Geismar Incident and net favorable changes in operating working capital, substantially offset by lower operating income.

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Net cash provided by operating activitiesdecreased $272 million in 2012 as compared to 2011 primarily due to lower operating income.

Financing activities

Significant transactions include:

2013

• $ 224 million net proceeds received from commercial paper issuances;

• $1.705 billion received from credit facility borrowings;

• $994 million net proceeds received from our November 2013 public offering of $600 million of 4.5 percent senior unsecured notes due 2023 and $400 million of 5.8 percent senior unsecured notes due 2043.

• $2.08 billion paid on credit facility borrowings;

• $1.962 billion received from our equity offerings, including $143 million received from Williams, which was used to repay credit facility borrowings;

• $1.846 billion, including $1.376 billion to Williams, related to quarterly cash distributions paid to limited partner unitholders and our general partner;

• $398 million received in contributions from noncontrolling interests.

2012

• $1.559 billion received from our equity offerings;

• $1.44 billion related to quarterly cash distributions paid to limited partner unitholders and our general partner;

• $1 billion received from Williams for common units issued, used for the funding of a portion of the cash purchase price of the Caiman Acquisition;

• $1.49 billion received in credit facility borrowings for general partnership purposes, including capital expenditures;

• $745 million net proceeds received from our August 2012 public offering of $750 million of senior unsecured notes due in 2022;

• $395 million net proceeds received from Transco’s July 2012 issuance of $400 million of senior unsecured notes due in 2042;

• $1.115 billion of credit facility borrowings paid;

• $325 million paid to retire Transco’s 8.875 percent notes upon their maturity on July 15, 2012.

2011

• $1.12 billion related to quarterly cash distributions paid to limited partner unitholders and our general partner;

• $500 million received from our public offering of senior unsecured notes in November 2011 primarily used to repay borrowings on our credit facility;

• $375 million received from Transco’s issuance of senior unsecured notes in August 2011;

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• $300 million paid to retire Transco’s senior unsecured notes that matured in August 2011;

• $300 million received in borrowings from our $1.75 billion unsecured credit facility used to acquire a 24.5 percent interest in Gulfstream from Williams in May 2011;

• $150 million paid to retire senior unsecured notes that matured in June 2011;

• $123 million distributed to Williams related to the excess purchase price over the contributed basis of Gulfstream in May 2011.

Investing activities

Significant transactions include:

2013

• $2.933 billion in capital expenditures;

• Purchases of and contributions to our equity-method investments of $439 million.

2012

• $2.112 billion in capital expenditures;

• $1.72 billion paid, net of purchase price adjustments, for the Caiman Acquisition in April 2012;

• $325 million paid, net of cash acquired in the transaction, for entities acquired in the Laser Acquisition in March 2012;

• $471 million contributed to our equity-method investments.

2011

• $1.005 billion in capital expenditures;

• $174 million related to our acquisitions of a 24.5 percent interest in Gulfstream from Williams in May 2011;

• $137 million contribution to our Laurel Mountain equity investment.

Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments

We have various other guarantees and commitments which are disclosed in Note 3 – Variable Interest Entities, Note 10 – Property, Plant and Equipment, Note 11 – Debt, Banking Arrangements, and Leases, Note 13 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk, and Note 14 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements. We do not believe these guarantees or the possible fulfillment of them will prevent us from meeting our liquidity needs.

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Contractual Obligations

The table below summarizes the maturity dates of our contractual obligations at December 31, 2013:

	2014		2015 - 2016		2017 - 2018		Thereafter		Total
	(Millions)
Long-term debt:
Principal	$	—	$	1,125	$	1,285	$	6,668	$	9,078
Interest	475		884		728		3,731		5,818
Commercial paper	225		—		—		—		225
Operating leases (1)	42		68		59		123		292
Purchase obligations (2)	1,886		431		410		923		3,650
Other obligations	2		1		—		—		3
Total	$	2,630	$	2,509	$	2,482	$	11,445	$	19,066

____________

(1) Includes a right-of-way agreement with the Jicarilla Apache Nation. We are required to make a fixed annual payment of $8 million and an additional annual payment, which varies depending on per-unit NGL margins and the volume of gas gathered by our gathering facilities subject to the right-of-way agreement. The table above for years 2015 and thereafter does not include such variable amounts related to this agreement as the variable amount is not yet determinable. The variable portion to be paid in 2014 based on 2013 gathering volumes is $5 million and is included in the table for year 2014.

(2) Includes approximately $1.1 billion in open property, plant and equipment purchase orders. Larger projects include Gulfstar One and the Oak Grove plant. Includes an estimated $621 million long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2013 prices. This obligation is part of an overall exchange agreement whereby volumes we transport on OPPL are sold at a third-party fractionator near Conway, Kansas, and we are subsequently obligated to purchase ethane volumes at Mont Belvieu. The purchased ethane volumes may be utilized or resold at comparable prices in the Mont Belvieu market. Includes an estimated $953 million long-term NGL purchase obligation with index-based pricing terms that primarily supplies a third party at its plant and is valued in this table at a price calculated using December 31, 2013 prices. Any excess purchased volumes may be sold at comparable market prices. In addition, we have not included certain natural gas life-of-lease contracts for which the future volumes are indeterminable. We have not included commitments, beyond purchase orders, for the acquisition or construction of property, plant and equipment or expected contributions to our jointly owned investments. (See Company Outlook – Expansion Projects.)

Effects of Inflation

Our operations have historically not been materially affected by inflation. Approximately 51 percent of our gross property, plant, and equipment is comprised of our interstate natural gas pipeline assets. They are subject to regulation, which limits recovery to historical cost. While amounts in excess of historical cost are not recoverable under current FERC practices, we anticipate being allowed to recover and earn a return based on increased actual cost incurred to replace existing assets. Cost-based regulations, along with competition and other market factors, may limit our ability to recover such increased costs. For our gathering and processing assets, operating costs are influenced to a greater extent by both competition for specialized services and specific price changes in crude oil and natural gas and related commodities than by changes in general inflation. Crude oil, natural gas, and NGL prices are particularly sensitive to the Organization of the Petroleum Exporting Countries (OPEC) production levels and/or the market perceptions concerning the supply and demand balance in the near future, as well as general economic conditions. However, our exposure to certain of these price changes is reduced through the fee-based nature of certain of our services and the use of hedging instruments.

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Environmental

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and/or remedial processes at certain sites, some of which we currently do not own (see Note 14 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements). We are monitoring these sites in a coordinated effort with other potentially responsible parties, the EPA, or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Current estimates of the most likely costs of such activities are approximately $20 million, all of which are included in Other accrued liabilities and Regulatory assets, deferred charges, and other on the Consolidated Balance Sheet at December 31, 2013. We will seek recovery of approximately $13 million of these accrued costs through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2013, we paid approximately $13 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $7 million in 2014 for these activities. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. At December 31, 2013, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. However, in September 2009, the EPA announced it would reconsider the 2008 NAAQS for ground level ozone to ensure that the standards were clearly grounded in science and were protective of both public health and the environment. As a result, the EPA delayed designation of new eight-hour ozone nonattainment areas under the 2008 standards until the reconsideration is complete. In January 2010, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels. In September 2011, the EPA announced that it was proceeding with required actions to implement the 2008 ozone standard and area designations. In May 2012, the EPA completed designation of new eight-hour ozone nonattainment areas. Several Transco facilities are located in 2008 ozone nonattainment areas; however, each facility has been previously subjected to federal and/or state emission control requirements implemented to address the preceding ozone standards. To date, no new federal or state actions have been proposed to mandate additional emission controls at these facilities. At this time, it is unknown whether future federal or state regulatory actions associated with implementation of the 2008 ozone standard will impact our operations and increase the cost of additions to Property, plant, and equipment – net on the Consolidated Balance Sheet. Until any additional federal or state regulatory actions are proposed, we are unable to estimate the cost of additions that may be required to meet this new regulation. Additionally, several nonattainment areas exist in or near areas where we have operating assets. States are required to develop implementation plans to bring these areas into compliance. Implementing regulations are expected to result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net on the Consolidated Balance Sheet for both new and existing facilities in affected areas.

In June 2010, the EPA promulgated a final rule establishing a new one-hour sulfur dioxide (SO2) NAAQS. The effective date of the new SO2 standard was August 23, 2010. The EPA has not adopted final modeling guidance. We are unable at this time to estimate the cost of additions that may be required to meet this new regulation.

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

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Our interstate natural gas pipelines consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates.

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Item 7A.Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio. Our debt portfolio is primarily comprised of fixed rate debt, which mitigates the impact of fluctuations in interest rates. Any borrowings under our credit facilities and any issuances under our commercial paper program could be at a variable interest rate and could expose us to the risk of increasing interest rates. The maturity of our long-term debt portfolio is partially influenced by the expected lives of our operating assets. (See Note 11 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)

The tables below provide information by maturity date about our interest rate risk-sensitive instruments as of December 31, 2013 and 2012. Long-term debt in the tables represents principal cash flows, net of (discount) premium, and weighted-average interest rates by expected maturity dates. The fair value of our publicly traded long-term debt is valued using indicative year-end traded bond market prices. Private debt is valued based on market rates and the prices of similar securities with similar terms and credit ratings.

	2014			2015			2016			2017			2018			Thereafter(1)			Total		Fair Value December 31, 2013
	(Millions)
Long-term debt, including current portion:
Fixed rate	$	—		$	750		$	375		$	785		$	500		$	6,647		$	9,057	$	9,581
Interest rate	5.2		%	5.3		%	5.3		%	5.2		%	5.1		%	5.6		%
Variable rate (2)	$	225		$	—		$	—		$	—		$	—		$	—		$	225	$	225
Interest rate (3)
	2013			2014			2015			2016			2017			Thereafter(1)			Total		Fair Value December 31, 2012
	(Millions)
Long-term debt, including current portion:
Fixed rate	$	—		$	—		$	750		$	375		$	785		$	6,152		$	8,062	$	9,249
Interest rate	5.3		%	5.3		%	5.3		%	5.4		%	5.3		%	5.6		%
Variable rate	$	—		$	—		$	—		$	375		$	—		$	—		$	375	$	375
Interest rate (3)

______________

(1) Includes unamortized discount.

(2) Consists of Commercial paper.

(3) The weighted average interest rate was 0.42 percent and 2.7 percent at December 31, 2013 and 2012, respectively.

Commodity Price Risk

We are exposed to the impact of fluctuations in the market price of NGLs, olefins, and natural gas, as well as other market factors, such as market volatility and energy commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets, our long-term energy-related contracts, and limited proprietary trading activities. Our management of the risks associated with these market fluctuations includes maintaining a conservative capital structure and significant liquidity, as well as using various derivatives and nonderivative energy-related contracts. The fair value of derivative contracts is subject to many factors, including changes in energy commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted, and changes in interest rates. At December 31, 2013 and 2012, our derivative activity was not material. (See Note 13 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)

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Item 8. Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Williams Partners GP LLC,

General Partner of Williams Partners L.P.

and the Limited Partners of Williams Partners L.P.

We have audited the accompanying consolidated balance sheet of Williams Partners L.P. (the “Partnership”) as of December 31, 2013 and 2012, and the related consolidated statements of comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Gulfstream Natural Gas System, L.L.C. (“Gulfstream”) (a limited liability corporation in which the Partnership has a 50 percent interest). The Partnership’s investment in Gulfstream constituted one and two percent, respectively, of the Partnership’s assets as of December 31, 2013 and 2012, and the Partnership’s equity earnings in the net income of Gulfstream constituted six, five and four percent, respectively, of the Partnership’s net income for each of the three years in the period ended December 31, 2013. Gulfstream’s financial statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Gulfstream, is based solely on the report of the other auditors.

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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Williams Partners L.P. at December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Williams Partners L.P.’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated February 26, 2014 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 26, 2014

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members of Gulfstream Natural Gas System, L.L.C.

We have audited the balance sheets of Gulfstream Natural Gas System, L.L.C., (the "Company") as of December 31, 2013 and 2012, and the related statements of operations, comprehensive income, members' equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the 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. The Company is not required to have, nor were we engaged to perform, an audit of its 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, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Gulfstream Natural Gas System, L.L.C. as of December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Houston, Texas

February 24, 2014

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Williams Partners L.P.

Consolidated Statement of Comprehensive Income

		Years Ended December 31,
		2013			2012			2011
	(Millions, except per-unit amounts)
Revenues:
Service revenues		$	2,910		$	2,709		$	2,517
Product sales		3,775			4,611			5,197
Total revenues		6,685			7,320			7,714
Costs and expenses:
Product costs		3,048			3,526			3,951
Operating and maintenance expenses		1,029			987			948
Depreciation and amortization expenses		758			714			621
Selling, general, and administrative expenses		493			553			406
Other (income) expense – net		15			23			13
Total costs and expenses		5,343			5,803			5,939
Operating income		1,342			1,517			1,775
Equity earnings (losses)		104			111			142
Interest incurred		(456		)	(441		)	(426		)
Interest capitalized		69			36			11
Other income (expense) – net		11			9			9
Net income		1,070			1,232			1,511
Less: Net income attributable to noncontrolling interests		3			—			—
Net income attributable to controlling interests		$	1,067		$	1,232		$	1,511
Allocation of net income for calculation of earnings per common unit:
Net income attributable to controlling interests		$	1,067		$	1,232		$	1,511
Allocation of net income to general partner		456			587			441
Allocation of net income to common units		$	611		$	645		$	1,070
Basic and diluted net income per common unit		$	1.45		$	1.89		$	3.69
Weighted average number of common units outstanding (thousands)		420,916			341,981			290,255
Cash distributions per common unit		$	3.480		$	3.205		$	2.960
Other comprehensive income (loss):
Net unrealized gain (loss) from derivative instruments		$	1		$	30		$	(17	)
Reclassifications into earnings of net derivative instruments (gain) loss		—			(30		)	18
Other comprehensive income (loss)		1			—			1
Comprehensive income		1,071			1,232			1,512
Less: Comprehensive income attributable to noncontrolling interests		3			—			—
Comprehensive income attributable to controlling interests		$	1,068		$	1,232		$	1,512

See accompanying notes.

77

Williams Partners L.P.

Consolidated Balance Sheet

	December 31,
	2013			2012
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	102		$	20
Trade accounts and notes receivable, net	523			562
Inventories	193			173
Other current assets	96			95
Total current assets	914			850
Investments	2,187			1,800
Property, plant, and equipment – net	16,488			14,287
Goodwill	646			649
Other intangible assets	1,642			1,702
Regulatory assets, deferred charges, and other	481			421
Total assets	$	22,358		$	19,709
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	828		$	851
Affiliate	93			117
Accrued interest	115			110
Asset retirement obligations	63			68
Other accrued liabilities	370			203
Commercial paper	225			—
Total current liabilities	1,694			1,349
Long-term debt	9,057			8,437
Asset retirement obligations	491			508
Regulatory liabilities, deferred income, and other	557			518
Contingent liabilities and commitments (Note 14)
Equity:
Partners’ equity:
Common units (438,625,699 units outstanding at December 31, 2013 and 397,963,199 units outstanding at December 31, 2012)	11,596			10,372
General partner	(1,451		)	(1,487		)
Accumulated other comprehensive income (loss)	(1		)	(2		)
Total partners’ equity	10,144			8,883
Noncontrolling interests in consolidated subsidiaries	415			14
Total equity	10,559			8,897
Total liabilities and equity	$	22,358		$	19,709

See accompanying notes.

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Williams Partners L.P.

Consolidated Statement of Changes in Equity

	Williams Partners L.P.
	Common Units			General Partner			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests		Total Equity
	(Millions)
Balance – December 31, 2010	$	6,564		$	(1,313	)	$	(3	)	$	—	$	5,248
Net income	1,088			423			—			—		1,511
Other comprehensive income (loss)	—			—			1			—		1
Cash distributions (Note 4)	(842		)	(282		)	—			—		(1,124		)
Distributions to The Williams Companies, Inc.- net	—			(99		)	—			—		(99		)
Excess of purchase price over contributed basis of investment purchase from affiliate	—			(123		)	—			—		(123		)
Contributions from general partner	—			31			—			—		31
Other	—			(12		)	—			—		(12		)
Balance – December 31, 2011	$	6,810		$	(1,375	)	$	(2	)	$	—	$	5,433
Net income	672			560			—			—		1,232
Cash distributions (Note 4)	(1,056		)	(384		)	—			—		(1,440		)
Distributions to the Williams Companies, Inc.- net	—			(42		)	—			—		(42		)
Sales of common units (Note 12)	2,559			—			—			—		2,559
Issuances of common units related to acquisitions (Note 12)	1,044			—			—			—		1,044
Issuances of common units in common control transactions (Note 12)	345			(338		)	—			—		7
Contributions from general partner	—			93			—			—		93
Contributions from noncontrolling interest	—			—			—			14		14
Other	(2		)	(1		)	—			—		(3		)
Balance – December 31, 2012	$	10,372		$	(1,487	)	$	(2	)	$	14	$	8,897
Net income	660			407			—			3		1,070
Other comprehensive income (loss)	—			—			1			—		1
Cash distributions (Note 4)	(1,422		)	(424		)	—			—		(1,846		)
Sales of common units (Note 12)	1,962			—			—			—		1,962
Contributions from general partner	—			78			—			—		78
Contributions from noncontrolling interests	—			—			—			398		398
Other	24			(25		)	—			—		(1		)
Balance – December 31, 2013	$	11,596		$	(1,451	)	$	(1	)	$	415	$	10,559

See accompanying notes.

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Williams Partners L.P.

Consolidated Statement of Cash Flows

	Years Ended December 31,
	2013			2012			2011
	(Millions)
OPERATING ACTIVITIES:
Net income	$	1,070		$	1,232		$	1,511
Adjustments to reconcile to net cash provided by operations:
Depreciation and amortization	758			714			621
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable	39			19			(92		)
Inventories	(19		)	7			56
Other current assets and deferred charges	25			25			(7		)
Accounts payable	(40		)	(89		)	138
Accrued liabilities	171			(8		)	60
Affiliate accounts receivable and payable – net	(25		)	49			(97		)
Other, including changes in noncurrent assets and liabilities	82			69			100
Net cash provided by operating activities	2,061			2,018			2,290
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	224			—			—
Proceeds from long-term debt	2,699			2,639			1,596
Payments of long-term debt	(2,080		)	(1,440		)	(1,184		)
Proceeds from sales of common units	1,962			2,559			—
General partner contributions	53			93			31
Distributions to limited partners and general partner	(1,846		)	(1,440		)	(1,124		)
Contributions from noncontrolling interests	398			13			—
Excess of purchase price over contributed basis of business and investment	—			—			(123		)
Distributions to The Williams Companies, Inc. - net	—			(17		)	(99		)
Other – net	(36		)	5			(15		)
Net cash provided (used) by financing activities	1,374			2,412			(918		)
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures	(2,933		)	(2,112		)	(1,005		)
Net proceeds from dispositions	3			22			5
Purchases of businesses	—			(2,049		)	(41		)
Purchase of businesses and investments from affiliates	25			(25		)	(174		)
Purchases of and contributions to equity method investments	(439		)	(471		)	(197		)
Purchase of ARO trust investments	(58		)	(34		)	(41		)
Proceeds from sale of ARO trust investments	46			43			56
Other – net	3			53			1
Net cash used by investing activities	(3,353		)	(4,573		)	(1,396		)
Increase (decrease) in cash and cash equivalents	82			(143		)	(24		)
Cash and cash equivalents at beginning of year	20			163			187
Cash and cash equivalents at end of year	$	102		$	20		$	163

See accompanying notes.

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Williams Partners L. P.

Notes to Consolidated Financial Statements

Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies

General

We are a publicly traded Delaware limited partnership. Williams Partners GP LLC, a Delaware limited liability company wholly owned by The Williams Companies, Inc. (Williams), serves as our general partner. As of December 31, 2013, Williams owns an approximate 62 percent limited partner interest, a 2 percent general partner interest and incentive distribution rights (IDRs) in us. All of our activities are conducted through Williams Partners Operating LLC (OLLC), an operating limited liability company (wholly owned by us). Our operations are located in the United States.

Description of Business

Our operations are located in North America and are organized into the following reportable segments: Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services.

Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus and Utica shale regions, as well as a 51 percent equity investment in Laurel Mountain Midstream, LLC (Laurel Mountain) and a 47.5 percent equity investment in Caiman Energy II, LLC (Caiman II).

Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transcontinental Gas Pipe Line Company, LLC (Transco), and significant natural gas gathering and processing and crude oil production handling and transportation in the Gulf Coast region, as well as a 50 percent equity investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), and a 60 percent equity investment in Discovery Producer Services LLC (Discovery).

West is comprised of our gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming and our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline).

NGL & Petchem Services is comprised of our natural gas liquid (NGL) and natural gas marketing business, an NGL fractionator and storage facilities near Conway, Kansas, a 50 percent equity investment in Overland Pass Pipeline, LLC (OPPL), and an 83.3 percent undivided interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf Coast region.

Basis of Presentation

In May 2011, we acquired a 24.5 percent equity interest in Gulfstream from a subsidiary of Williams in exchange for aggregate consideration of $297 million of cash, 632,584 of our limited partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. In June 2012, we acquired an additional 1 percent interest in Gulfstream from a subsidiary of Williams in exchange for 238,050 of our limited partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. The equity interests acquired in these transactions were affiliates of Williams at the time of the acquisitions; therefore, each was accounted for as a common control transaction. The equity interests acquired were combined with our investments as of the date of transfer such that our historical results of operations for periods prior to the acquisitions were unchanged. These transactions are collectively referred to as the Gulfstream Acquisitions and the investment is reported in our Atlantic-Gulf segment.

In November 2012, we acquired an entity that holds an 83.3 percent undivided interest in an olefins-production facility in Geismar, Louisiana, and associated assets from Williams for total consideration of 42,778,812 of our limited partner units, $25 million in cash, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest (Geismar Acquisition). The acquired entity was an affiliate of Williams at the time of the acquisition; therefore, the acquisition was accounted for as a common control transaction, whereby the acquired assets and liabilities were combined with ours at their historical amounts. This common control acquisition was treated similar to a pooling of interests whereby the historical results of operations were combined with ours for all periods

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Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

presented. In first-quarter 2013, we received $25 million in cash from Williams and Williams waived $4 million in payments on its IDRs with respect to our May 2013 distribution related to a working capital adjustment associated with the acquisition.

Summary of Significant Accounting Policies

Principles of consolidation

The consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of ventures in which we own an undivided interest. Management judgment is required to evaluate whether we control an entity. Key areas of that evaluation include:

• Determining whether an entity is a variable interest entity (VIE);

• Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that we and our related parties have over those activities through our variable interests;

• Identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether we are a VIE’s primary beneficiary;

• Evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant decisions that would be expected to be made in the ordinary course of business such that we do not have the power to control such entities.

We apply the equity method of accounting to investments in entities over which we exercise significant influence but do not control.

Common control transactions

Entities and assets acquired from Williams and its affiliates are accounted for as common control transactions whereby the net assets acquired are combined with ours at their historical amounts. If any cash consideration transferred in such a transaction exceeds the carrying value of the net assets acquired, the excess is treated as a capital transaction with our general partner, similar to a dividend. If the carrying value of the net assets acquired exceeds any cash consideration transferred and limited partner units are also issued as consideration, then the limited partner units are recorded at an amount equal to the excess of the carrying value of the net assets acquired over any cash consideration transferred. To the extent that such transactions require prior periods to be recast, historical net equity amounts prior to the transaction date are reflected in the account of the general partner. Cash consideration up to the carrying value of net assets acquired is presented as an investing activity in our Consolidated Statement of Cash Flows. Cash consideration in excess of the carrying value of net assets acquired is presented as a financing activity in our Consolidated Statement of Cash Flows.

Use of estimates

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

Significant estimates and assumptions include:

• Impairment assessments of investments, property, plant, and equipment, goodwill and other identifiable intangible assets;

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Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

• Litigation-related contingencies;

• Environmental remediation obligations;

• Asset retirement obligations;

• Acquisition related purchase price allocations.

These estimates are discussed further throughout these notes.

Regulatory accounting

Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC). Their rates, which are established by the FERC, are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, our management has determined that it is appropriate to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are established. Accounting for these operations that are regulated can differ from the accounting requirements for non regulated operations. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, and postretirement benefits. Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2013 and 2012 are as follows:

	December 31,
	2013		2012
	(Millions)
Current assets reported within Other current assets	$	39	$	39
Noncurrent assets reported within Regulatory assets, deferred charges, and other	315		275
Total regulated assets	$	354	$	314
Current liabilities reported within Other accrued liabilities	$	19	$	15
Noncurrent liabilities reported within Regulatory liabilities, deferred income and other	289		250
Total regulated liabilities	$	308	$	265

Cash and cash equivalents

Cash and cash equivalents in the Consolidated Balance Sheet includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.

Accounts receivable

Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted.

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Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

Inventory valuation

All Inventories in the Consolidated Balance Sheet are stated at the lower of cost or market. The cost of inventories is primarily determined using the average-cost method.

Property, plant, and equipment

Property, plant, and equipment is recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values.

As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply a declining balance method. (SeeNote 10 – Property, Plant and Equipment.)

Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation; other gains or losses are recorded in Other (income) expense – net included in Operating income in the Consolidated Statement of Comprehensive Income.

Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment.

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. As regulated entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that is attributable to capitalized ARO cost to a regulatory asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income, except for regulated entities, for which the liability is offset by a regulatory asset as management expects to recover amounts in future rates. The regulatory asset is amortized commensurate with the collection of those costs in rates.

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.

Goodwill

Goodwill in the Consolidated Balance Sheet represents the excess cost over fair value of the net assets of businesses acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount. As part of the evaluation, we compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess.

Other intangible assets

Our identifiable intangible assets are primarily related to gas gathering, processing and fractionation contracts, and relationships with customers. Our intangible assets are amortized on a straight-line basis over the period in which these assets contribute to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining useful life.

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Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

Impairment of property, plant, and equipment, other identifiable intangible assets, and investments

We evaluate our property, plant, and equipment and other identifiable intangible 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 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 and we may 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. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.

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

We evaluate our investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal.

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.

Cash flows from revolving credit facility and commercial paper program

Proceeds and payments related to borrowings under our credit facility are reflected in the financing activities in the Consolidated Statement of Cash Flows on a gross basis. Proceeds and payments related to borrowings under our commercial paper program are reflected in the financing activities in the Consolidated Statement of Cash Flows on a net basis, as the outstanding notes generally have maturity dates less than three months from the date of issuance. (See Note 11 – Debt, Banking Arrangements, and Leases.)

Derivative instruments and hedging activities

We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of physical energy commodities. We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Other current assets; Regulatory assets, deferred charges, and other; Other accrued liabilities; or Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet. We determine the

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Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis. See Note 13 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.

The accounting for the changes in fair value of a commodity derivative can be summarized as follows:

Derivative Treatment	Accounting Method
Normal purchases and normal sales exception	Accrual accounting
Designated in a qualifying hedging relationship	Hedge accounting
All other derivatives	Mark-to-market accounting

We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.

We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income.

For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in Accumulated other comprehensive income (loss) (AOCI) in the Consolidated Balance Sheet and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in Product sales or Product costs in the Consolidated Statement of Comprehensive Income at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by management.

For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income.

Certain gains and losses on derivative instruments included in the Consolidated Statement of Comprehensive Income are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception.

Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives for NGL processing activities and which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.

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Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

Revenues

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.

Service revenues

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

Certain revenues from our midstream operations include those derived from natural gas gathering and processing services and are performed under volumetric-based fee contracts. These revenues are recorded when services have been performed.

Crude oil gathering and transportation revenues and offshore production handling fees are recognized when the services have been performed. Certain offshore production handling contracts contain fixed payment terms that result in the deferral of revenues until such services have been performed.

Storage revenues from our midstream operations associated with prepaid contracted storage capacity contracts are recognized on a straight-line basis over the life of the contract as services are provided.

Product sales

In the course of providing transportation services to customers of our interstate natural gas pipeline businesses, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided for in our FERC tariffs. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances.

We market NGLs, crude oil, natural gas, and olefins that we purchase from our producer customers as part of the overall service provided to producers. Revenues from marketing NGLs are recognized when the products have been sold and delivered.

Under our keep-whole and percent-of-liquids processing contracts, we retain the rights to all or a portion of the NGLs extracted from the producers’ natural gas stream and recognize revenues when the extracted NGLs are sold and delivered.

Our olefins business produces olefins from purchased or produced feedstock and we recognize revenues when the olefins are sold and delivered.

Interest capitalized

We capitalize interest during construction on major projects with construction periods of at least 3 months and a total project cost in excess of $1 million. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds. The latter is included in Other income (expense) – net below Operating incomein the Consolidated Statement of Comprehensive Income. The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by nonregulated companies are based on our average interest rate on debt.

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Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

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 individual partners. Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregated difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available to us.

Earnings per unit

We use the two-class method to calculate basic and diluted earnings per unit whereby net income, adjusted for items specifically allocated to our general partner, is allocated on a pro-rata basis between unitholders and our general partner. Basic and diluted earnings per unit are based on the average number of common units outstanding. Basic and diluted earnings per unit are equivalent as there are no dilutive securities outstanding.

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 8 – Benefit Plans.) 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.

Note 2 – Acquisitions, Goodwill, and Other Intangible Assets

Business Combinations

In addition to the entities and assets acquired in the common control transactions described in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies, we note the following additional acquisitions.

On February 17, 2012, we completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC, in exchange for $325 million in cash, net of cash acquired in the transaction, and 7,531,381 of our common units valued at $441 million (Laser Acquisition). The fair value of the common units issued as part of the consideration paid was determined on the basis of the closing market price of our common units on the acquisition date, adjusted to reflect certain time-based restrictions on resale. The acquired entities primarily own the Laser Gathering System, which is comprised of a natural gas pipeline and associated gathering facilities in the Marcellus Shale in Susquehanna County, Pennsylvania, as well as gathering lines in southern New York.

On April 27, 2012, we completed the acquisition of 100 percent of the ownership interests in Caiman Eastern Midstream, LLC, from Caiman Energy, LLC in exchange for $1.72 billion in cash and 11,779,296 of our common units valued at $603 million (Caiman Acquisition). The fair value of the common units issued as part of the consideration paid was determined on the basis of the closing market price of our common units on the acquisition date, adjusted to reflect certain time-based restrictions on resale. The acquired entity operates a gathering and processing business in northern West Virginia, southwestern Pennsylvania, and eastern Ohio. Acquisition transaction costs of $16 million were incurred during 2012 by Northeast G&P related to the Caiman Acquisition and are reported in Selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income.

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Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

The following table presents the allocation of the acquisition-date fair value of the major classes of the net assets, which are included in the Northeast G&P segment:

	Laser			Caiman
	(Millions)
Assets held-for-sale	$	18		$	—
Other current assets	3			16
Property, plant, and equipment	158			656
Intangible assets:
Customer contracts	316			1,141
Customer relationships	—			250
Other	2			2
Current liabilities	(21		)	(94		)
Noncurrent liabilities	—			(3		)
Identifiable net assets acquired	476			1,968
Goodwill	290			356
	$	766		$	2,324

Revenues and earnings related to the Laser and Caiman Acquisitions included within the Consolidated Statement of Comprehensive Income in 2012 are not material. Supplemental pro forma revenue and earnings for the pre-acquisition periods reflecting these acquisitions as if they had occurred as of January 1, 2011, are not materially different from the information presented in our accompanying Consolidated Statement of Comprehensive Income (since the historical operations of these acquisitions were insignificant relative to our historical operations) and are, therefore, not presented.

Goodwill and Other Intangible Assets

Goodwill

The Laser and Caiman Acquisitions were accounted for as business combinations which, among other things, require assets acquired and liabilities assumed to be measured at their acquisition-date fair values. The excess of cost over those fair values was recorded as goodwill and allocated to our Northeast G&P segment (the reporting unit). Goodwill recognized in the acquisitions relates primarily to enhancing our strategic platform for expansion in the Marcellus and Utica shale plays in the Appalachian basin area. Our annual goodwill impairment review did not result in a goodwill impairment in 2013.

Other Intangible Assets

Other intangible assets primarily relate to gas gathering, processing and fractionation contracts and relationships with customers recognized in the Laser and Caiman Acquisitions. The basis for determining the value of these intangible assets was estimated future net cash flows to be derived from acquired customer contracts and relationships, which were offset with appropriate charges for the use of contributory assets and discounted using a risk-adjusted discount rate. The intangible assets are being amortized on a straight-line basis over an initial period of 30 years which represents a portion of the term over which the customer contracts and relationships are expected to contribute to our cash flows.

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Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

The gross carrying amount and accumulated amortization of Other intangible assetsat December 31 are as follows:

	2013					2012
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
	(Millions)
Customer contracts	$	1,493	$	(88	)	$	1,493	$	(38	)
Customer relationships	250		(14		)	250		(6		)
Other	4		(3		)	4		(1		)
Total	$	1,747	$	(105	)	$	1,747	$	(45	)

We expense costs incurred to renew or extend the terms of our gas gathering, processing and fractionation contracts with customers. Based on the estimated future revenues during the contract periods (as estimated at the time of the respective acquisition), the weighted-average periods prior to the next renewal or extension of the customer contracts associated with the Laser and Caiman Acquisitions were approximately 9 years and 18 years, respectively. Although a significant portion of the expected future cash flows associated with these contracts are dependent on our ability to renew or extend the arrangements beyond the initial contract periods, these expected future cash flows are significantly influenced by the scope and pace of our producer customers’ drilling programs. Once producer customers’ wells are connected to our gathering infrastructure, their likelihood of switching to another provider before the wells are abandoned is reduced due to the significant capital investments required.

The aggregate amortization expense related to Other intangible assets was $60 million, $43 million and $2 million in 2013, 2012 and 2011, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $60 million.

Note 3 – Variable Interest Entities

Consolidated VIEs

As of December 31, 2013, we consolidate the following VIEs:

Gulfstar One

During the second quarter of 2013, a third party contributed $187 million to Gulfstar One LLC (Gulfstar One) in exchange for a 49 percent ownership interest in Gulfstar One. This contribution was based on 49 percent of our estimated cumulative net investment at that time. The $187 million was then distributed to us. Following this transaction, we own a 51 percent interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance. We, as construction agent for Gulfstar One, are designing, constructing, and installing a proprietary floating-production system, Gulfstar FPS™, and associated pipelines which will initially provide production handling and gathering services for the Tubular Bells oil and gas discovery in the eastern deepwater Gulf of Mexico. The project is expected to be in service in the third quarter of 2014. We have received certain advance payments from the producer customers and are committed to the producer customers to construct this system. The current estimate of the total remaining construction costs is less than $325 million, which will be funded with capital contributions from us and the other equity partner, proportional to ownership interest. The producer customers will be responsible for the firm price of building the facilities if they do not develop the offshore oil and gas fields to be connected to Gulfstar One. In December 2013, we committed an additional $134 million to Gulfstar One to fund an expansion of the system that will provide production handling, gathering, and processing services for the Gunflint oil and gas discovery in the eastern deepwater Gulf of Mexico. The expansion project is expected to be in service in 2016. The other equity partner has an option to participate in the funding of the expansion project on a proportional basis.

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Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

Constitution

We own a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its firm transportation contracts, is a VIE. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Constitution’s economic performance. We, as construction agent for Constitution, are building a pipeline connecting our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. We plan to place the project in service in late 2015 to 2016 and estimate the total remaining construction costs of the project to be less than $600 million, which will be funded with capital contributions from us and the other equity partners, proportional to ownership interest.

The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of these VIEs, which are joint projects in the development and construction phase:

	December 31,
	2013			2012			Classification
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	76		$	8		Cash and cash equivalents
Construction in progress	998			556			Property, plant, and equipment, at cost
Accounts payable	(120		)	(128		)	Accounts payable - trade
Construction retainage	(3		)	—			Other accrued liabilities
Current deferred revenue	(10		)	—			Other accrued liabilities
Noncurrent deferred revenue associated with customer advance payments	(115		)	(109		)	Regulatory liabilities, deferred income, and other

Nonconsolidated VIEs

We have also identified certain interests in VIEs for which we are not the primary beneficiary. These include:

Laurel Mountain

Our 51 percent-owned equity-method investment in Laurel Mountain is considered to be a VIE generally due to contractual provisions that transfer certain risks to customers. As decisions about the activities that most significantly impact the economic performance of this entity require a unanimous vote of all members, we are not the primary beneficiary. Our maximum exposure to loss is limited to the carrying value of this investment, which was $481 million at December 31, 2013.

Caiman II

Our 47.5 percent-owned equity-method investment in Caiman II has been determined to be a VIE because it has insufficient equity to finance activities during the construction stage of the Blue Racer Midstream joint project, which is an expansion to gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale primarily in Ohio and northwest Pennsylvania. We are not the primary beneficiary because we do not have the power to direct the activities of Caiman II that most significantly impact its economic performance. At December 31, 2013, the carrying value of our investment in Caiman II was $256 million, which substantially reflects our contributions to that date. In January 2014, we increased our total commitment for contributions to fund the project from $380 million to $500 million inclusive of contributions made to date which represents our current maximum exposure to loss related to this investment.

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Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

Note 4 – Allocation of Net Income and Distributions

The allocation of net income among our general partner, limited partners, and noncontrolling interests as reflected in the Consolidated Statement of Changes in Equity is as follows:

	Years Ended December 31,
	2013			2012			2011
	(Millions)
Allocation of net income to general partner:
Net income	$	1,070		$	1,232		$	1,511
Net income applicable to pre-partnership operations allocated to general partner	—			(185		)	(133		)
Net income applicable to noncontrolling interests	(3		)	—			—
Net costs charged directly to general partner	1			1			(2		)
Income subject to 2% allocation of general partner interest	1,068			1,048			1,376
General partner’s share of net income	2		%	2		%	2		%
General partner’s allocated share of net income before items directly allocable to general partner interest	21			21			28
Priority allocations, including incentive distributions, paid to general partner (1)	387			355			260
Net costs charged directly to general partner	(1		)	(1		)	2
Pre-partnership net income allocated to general partner interest	—			185			133
Net income allocated to general partner	$	407		$	560		$	423
Net income	$	1,070		$	1,232		$	1,511
Net income allocated to general partner	407			560			423
Net income allocated to noncontrolling interests	3			—			—
Net income allocated to common limited partners	$	660		$	672		$	1,088

____________

(1) The net income allocated to the general partner’s capital account reflects IDRs paid during the current reporting period. In the calculation of basic and diluted net income per common unit, the net income allocated to the general partner includes IDRs pertaining to the current reporting period but paid in the subsequent period.

The Net costs charged directly to general partner may include the net of both income and expense items. Under the terms of omnibus agreements, we are reimbursed by our general partner for certain expense items and are required to distribute certain income items to our general partner.

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Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

The following table sets forth the partnership cash distributions paid on the dates indicated, related to the preceding quarter (in millions, except for per unit amounts):

					General Partner
Payment Date	Per Unit Distribution		Common Units		2%		Incentive Distribution Rights		Total Cash Distribution
2/11/2011	$	0.7025	$	204	$	5	$	59	$	268
5/13/2011	0.7175		208		5		63		276
8/12/2011	0.7325		213		6		67		286
11/11/2011	0.7475		217		6		71		294
2/10/2012	0.7625		227		6		78		311
5/11/2012	0.7775		268		8		86		362
8/10/2012	0.7925		274		7		92		373
11/9/2012	0.8075		287		8		99		394
2/8/2013	0.8275		329		9		104		442
5/10/2013	0.8475		351		10		112		473
8/09/2013	0.8625		357		11		121		489
11/12/2013	0.8775		385		11		46		442
2/13/2014 (1)	0.8925		392		11		153		556

____________

(1) On February 13, 2014, we paid a cash distribution of $0.8925 per unit on our outstanding common units to unitholders of record at the close of business on February 6, 2014.

The 2012, 2013, and 2014 cash distributions paid to our general partner in the table above have been reduced by $147 million resulting from the temporary waiver of IDRs associated with certain assets acquired in 2012 and an additional $90 million in IDRs waived by our general partner related to the third quarter 2013 distributions, to support our cash distribution metrics as our large platform of growth projects moves toward completion.

Note 5 – Related Party Transactions

Reimbursement of Expenses of Our General Partner

The employees of our operated assets are employees of Williams. Williams directly charges us for the payroll and benefit costs associated with operations employees and carries the obligations for many employee-related benefits in its financial statements, including the liabilities related to employee retirement, medical plans, and paid time off. Our share of the costs is charged to us through affiliate billings and reflected in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income.

In addition, employees of Williams provide general and administrative 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. Our share of direct and allocated administrative expenses is reflected in Selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income. 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.

In 2012, Williams engaged a consulting firm to assist in better aligning resources to support their business strategy following the December 31, 2011, spin-off of WPX Energy, Inc. (WPX). Our share of the allocated reorganization-related costs, included in Selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income, is $2 million and $25 million for the years ended December 31, 2013, and December 31, 2012, respectively.

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Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

Transactions with Affiliates and Equity-Method Investees

Product costs, in the Consolidated Statement of Comprehensive Income, include charges for the following types of transactions with affiliates and equity-method investees:

• Purchases of olefin and NGL products for resale from Williams Energy Canada ULC, a subsidiary of Williams, at market prices at the time of purchase.

• Purchases of NGLs for resale from Discovery at market prices at the time of purchase.

• Payments to OPPL for transportation of NGLs from certain natural gas processing plants.

Transactions with WPX

We consider WPX an affiliate prior to its spin-off from Williams. Revenues, in the Consolidated Statement of Comprehensive Income, for the year ended December 31, 2011 include the following types of transactions we have with WPX prior to this separation:

• Revenues from transportation and exchange service and rental of communication facilities with WPX. The rates charged to provide sales and services to affiliates are comparable to those that are charged to similarly situated nonaffiliated customers.

• Revenues from gathering, treating, and processing services for WPX under several contracts. We believe that the rates charged to provide these services are reasonable as compared to those that are charged to similarly situated nonaffiliated customers. 

Product costs and Operating and maintenance expenses, in the Consolidated Statement of Comprehensive Income, for the year ended December 31, 2011 include charges for the following types of transactions we have with WPX prior to this separation:

• Purchases of NGLs for resale from WPX at market prices at the time of purchase.

• Purchases of natural gas for shrink replacement and fuel from WPX at market prices at the time of purchase or contract execution.

• Costs related to a transportation capacity agreement transferred to WPX in a prior year. To the extent that WPX did not utilize this transportation capacity for its needs (primarily transporting third-party gas volumes), we reimbursed WPX for these transportation costs.

Historically, we periodically entered into derivative contracts with WPX to hedge forecasted NGL sales and natural gas purchases. These contracts were priced based on market rates at the time of execution.

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Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

Summary of the related party transactions discussed in all sections above. 

	Years Ended December 31,
	2013		2012		2011
	(Millions)
Revenues	$	—	$	—	$	310
Product costs	270		300		802
Operating and maintenance expenses:
Employee costs	328		269		236
Other	—		—		305
Selling, general, and administrative expenses:
Employee direct costs	256		287		232
Employee allocated costs	160		184		118

The Accounts payable — affiliate in the Consolidated Balance Sheet represents the payable positions that result from the transactions with affiliates discussed above. We also have $13 million and $15 million in Accounts payable — trade in the Consolidated Balance Sheet with our equity-method investees at December 31, 2013 and December 31, 2012, respectively.

Operating Agreements with Equity-Method Investees

We have operating agreements with certain equity-method investees. These operating agreements typically provide for reimbursement or payment to us for certain direct operational payroll and employee benefit costs, materials, supplies, and other charges and also for management services. Williams supplied a portion of these services, primarily those related to employees since we do not have any employees, to certain equity-method investees. The total gross charges to equity-method investees for these fees included in the Consolidated Statement of Comprehensive Income are $67 million, $75 million and $57 million for the years ended December 31, 2013, 2012, and 2011, respectively.

Omnibus Agreement

In February 2010, we entered into an omnibus agreement with Williams. Under this agreement, Williams is obligated to reimburse us for (i) amounts incurred by us or our subsidiaries for repair or abandonment costs for damages to certain facilities caused by Hurricane Ike, up to a maximum of $10 million, (ii) maintenance capital expenditure amounts incurred by us or our subsidiaries for certain U.S. Department of Transportation projects, up to a maximum of $50 million, and (iii) an amount based on the amortization over time of deferred revenue amounts that relate to cash payments received by Williams prior to the closing of the contribution transaction for services to be rendered by us in the future at the Devils Tower floating production platform. In addition, we will be obligated to pay to Williams the proceeds of certain sales of natural gas recovered from the Hester storage field pursuant to the FERC order dated March 7, 2008, approving a settlement agreement. Net amounts received under this agreement for the years ended December 31, 2013, 2012 and 2011 were $12 million, $15 million, and $31 million, respectively.

We have a contribution receivable from our general partner of $3 million and $4 million at December 31, 2013 and December 31, 2012, respectively, for amounts reimbursable to us under omnibus agreements. We net this receivable against Total partners’ equity in the Consolidated Balance Sheet.

Acquisitions and Equity Issuances

Basis of Presentation in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies includes related party transactions for the Geismar and Gulfstream Acquisitions. Prior to the acquisition, Geismar operations were included in Williams’ cash management program under an unsecured promissory note agreement with Williams for both advances to and from Williams. In connection with the Geismar Acquisition, the outstanding advances were distributed to Williams at the close of the transaction. The distribution had

95

Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

no impact on our assets or liabilities. Changes in the advances to Williams are presented as Distributions to The Williams Companies, Inc.- net in the Consolidated Statement of Changes in Equity.

Note 12 – Partners’ Capital includes related party transactions for the sale of limited partner units to Williams in March 2013 and April 2012.

Board of Directors

A member of Williams’ Board of Directors, who was elected in 2013, is also the current chairman, president, and chief executive officer of an energy services company that is a customer of ours. We recorded $131 million inService revenues in Consolidated Statement of Comprehensive Income from this company for transportation and storage of natural gas for the year ended December 31, 2013. This board member does not have any material interest in any transactions between the energy services company and us and he had no role in any such transactions.

Mr. H. Michael Krimbill, a member of our Board of Directors until his term completion in August 2012, has served as the Chief Executive Officer of NGL Energy Partners LP, formerly Silverthorne Energy Partners LP, and as a director of its general partner since 2010. We recorded $61 million and $62 million in Product sales in the Consolidated Statement of Comprehensive Income from NGL Energy Partners LP primarily for the sale of propane at market prices and $13 million and $9 million in Product costs in the Consolidated Statement of Comprehensive Income for the purchase of propane at market prices for the years ended December 31, 2012 and 2011, respectively.

Note 6 – Investments

Investments accounted for using the equity method consist of:

	December 31,
	2013		2012
	(Millions)
OPPL - 50%	$	452	$	454
Gulfstream - 50%	333		348
Discovery - 60% (1)	527		350
Laurel Mountain - 51% (1)	481		444
Caiman II - 47.5%	256		67
Other	138		137
	$	2,187	$	1,800

____________

(1) We account for these investments under the equity method due to the significant participatory rights of our partners such that we do not control or are otherwise not the primary beneficiary of the investments.

The difference between the carrying value of our equity-method investments and the underlying equity in the net assets of the investees is $60 million at December 31, 2013, primarily related to impairments we previously recognized. These differences are amortized over the expected remaining life of the investees’ underlying assets.

We generally fund our portion of significant expansion or development projects of these investees through additional capital contributions. As of December 31, 2013, our proportionate share of amounts remaining to be spent for specific capital projects already in progress for Discovery, Laurel Mountain, and Caiman II totaled $244 million, $72 million, and $119 million, respectively.

We acquired a 1 percent and 24.5 percent interest in Gulfstream from a subsidiary of Williams in June 2012 and May 2011, respectively. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.) We contributed $193 million and $169 million to Discovery in 2013 and 2012, respectively; $42 million, $174 million and $137 million to Laurel Mountain in 2013, 2012, and 2011, respectively; and $192 million and $69 million to Caiman II in 2013 and 2012, respectively.

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Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

Our equity-method investees’ organizational documents generally require distribution of available cash to equity holders on a quarterly basis. Dividends and distributions, including those presented below, received from companies accounted for by the equity method were $154 million, $172 million, and $169 million in 2013, 2012, and 2011, respectively. These transactions reduced the carrying value of our investments. These dividends and distributions primarily included:

	Years Ended December 31,
	2013		2012		2011
	(Millions)
Gulfstream	$	81	$	78	$	60
Discovery	12		21		40
Aux Sable Liquid Products L.P.	20		28		35
OPPL	27		28		19

Summarized Financial Position and Results of Operations of All Equity-Method Investments

	December 31,
	2013			2012
	(Millions)
Assets (liabilities):
Current assets	$	412		$	366
Noncurrent assets	5,956			5,225
Current liabilities	(264		)	(247		)
Noncurrent liabilities	(1,305		)	(1,301		)

	Years Ended December 31,
	2013		2012		2011
	(Millions)
Gross revenue	$	1,333	$	1,213	$	1,242
Operating income	367		378		535
Net income	291		309		460

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Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

Note 7 – Other Income and Expenses

The following table presents significant gains or losses reflected in Other (income) expense – netwithin Costs and expenses:

	Years Ended December 31,
	2013			2012			2011
	(Millions)
Northeast G&P
Settlement in principle of a producer claim	$	25		$	—		$	—
Atlantic-Gulf
Amortization of regulatory asset associated with asset retirement obligations	30			7			6
Write-off of the Eminence abandonment regulatory asset not recoverable through rates	12			—			—
Insurance recoveries associated with the Eminence abandonment	(16		)	—			—
Project feasibility costs	4			21			10
Capitalization of project feasibility costs previously expensed	(1		)	(19		)	(11		)
NGL & Petchem Services
Net insurance recoveries associated with the Geismar Incident	(40		)	—			—

The reversals of project feasibility costs from expense to capital are associated with natural gas pipeline expansion projects. These reversals were made upon determining that the related projects were probable of development. These costs are now included in the capital costs of the projects, which we believe are probable of recovery through the project rates.

On June 13, 2013, an explosion and fire occurred at our Geismar olefins plant. The fire was extinguished on the day of the incident. The incident (Geismar Incident) rendered the facility temporarily inoperable and resulted in significant human, financial and operational effects.

We have substantial insurance coverage for repair and replacement costs, lost production, and additional expenses related to the incident as follows:

• Property damage and business interruption coverage with a combined per-occurrence limit of $500 million and retentions (deductibles) of $10 million per occurrence for property damage and a waiting period of 60 days per occurrence for business interruption;

• General liability coverage with per-occurrence and aggregate annual limits of $610 million and retentions (deductibles) of $2 million per occurrence;

• Workers’ compensation coverage with statutory limits and retentions (deductibles) of $1 million total per occurrence.

We have expensed $13 million at NGL & Petchem Services during 2013 of costs under our insurance deductibles in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income. Recoveries under our business interruption policy will be recognized upon resolution of any contingencies with the insurer associated with the claim. Through December 31, 2013, we have recognized $50 million of insurance recoveries related to this incident as a gain to Other (income) expense – net within Costs and expenses in our Consolidated Statement of Comprehensive Income. During the fourth quarter of 2013, we incurred $10 million of covered insurable expenses in excess of our retentions (deductibles) which partially offset the $50 million gain included in Other (income) expense – net within Costs and expenses in our Consolidated Statement of Comprehensive Income.

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Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

Additional Items

We detected a leak in an underground cavern at our Eminence Storage Field in Mississippi on December 28, 2010. We recorded $3 million, $2 million, and $15 million of charges to Operating and maintenance expenses at Atlantic-Gulf during 2013, 2012, and 2011, respectively, primarily related to assessment and monitoring costs incurred to ensure the safety of the surrounding area.

Other income (expense) – net below Operating income for 2013, includes a charge of $14 million associated with the impact of a second quarter Texas franchise tax law change.

Note 8 – 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 plans

Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible employees. Pension costs charged to us by Williams for 2013, 2012, and 2011 totaled $44 million, $41 million, and $32 million, respectively. At the total Williams plan level, the pension plans had a projected benefit obligation of $1.4 billion and $1.5 billion at December 31, 2013 and 2012, respectively. The plans were underfunded by $143 million and $478 million at December 31, 2013 and 2012, respectively.

Postretirement benefits other than pensions

Williams provides certain retiree health care and life insurance benefits for eligible participants. Generally, employees that 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 are eligible for subsidized retiree medical benefits. The cost charged to us for the plans anticipates future cost-sharing that is consistent with Williams’ expressed intent to increase the retiree contribution level, generally in line with health care cost increases. We recognized a net periodic postretirement benefit credited to us by Williams of $4 million in 2013 and $2 million in 2011, and a net periodic postretirement benefit cost charged to us by Williams of $4 million in 2012. At the total Williams plan level, the postretirement benefit plans had an accumulated postretirement benefit obligation of $213 million and $331 million at December 31, 2013 and 2012, respectively. The plans were underfunded by $12 million and $156 million at December 31, 2013 and 2012, respectively.

Any differences between the annual expense and amounts currently being recovered in rates by our FERC-regulated gas pipelines are recorded as an adjustment to expense and collected or refunded through future rate adjustments.

Defined contribution plan

Williams charged us compensation expense of $15 million, $18 million, and $16 million in 2013, 2012, and 2011, respectively, for Williams’ matching contributions to this plan.

Employee Stock-Based Compensation Plan information

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

Williams bills us directly for compensation expense related to stock-based compensation awards based on the fair value of the awards.

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Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

Total stock-based compensation expense for the years ended December 31, 2013, 2012, and 2011 was $11 million, $12 million and $10 million, respectively.

Note 9 – Inventories

	December 31,
	2013		2012
	(Millions)
Natural gas liquids, olefins, and natural gas in underground storage	$	112	$	96
Materials, supplies, and other	81		77
	$	193	$	173

Note 10 – Property, Plant and Equipment

	Estimated	Depreciation
	Useful Life (1)	Rates (1)	December 31,
	(Years)	(%)	2013			2012
			(Millions)
Nonregulated:
Natural gas gathering and processing facilities	5 - 40		$	8,018		$	7,000
Construction in progress	Not applicable		2,658			1,599
Other	3 - 45		899			745
Regulated:
Natural gas transmission facilities		1.2 - 6.97	10,633			9,963
Construction in progress		Not applicable	273			337
Other		1.35 - 33.33	1,293			1,418
Total property, plant, and equipment, at cost			$	23,774		$	21,062
Accumulated depreciation and amortization			(7,286		)	(6,775		)
Property, plant, and equipment — net			$	16,488		$	14,287

______________________

(1) Estimated useful life and depreciation rates are presented as of December 31, 2013. Depreciation rates for regulated assets are prescribed by the FERC.

Depreciation and amortization expense for Property, plant, and equipment – net was $697 million, $670 million and $618 million in 2013, 2012, and 2011, respectively.

Regulated Property, plant, and equipment – net includes approximately $785 million and $825 million at December 31, 2013 and 2012, respectively, related to amounts in excess of the original cost of the regulated facilities within our gas pipeline businesses as a result of our prior acquisitions. This amount is being amortized over 40 years using the straight-line amortization method. Current FERC policy does not permit recovery through rates for amounts in excess of original cost of construction.

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Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

Asset Retirement Obligations

Our accrued obligations relate to underground storage caverns, offshore platforms, fractionation and compression facilities, gas gathering well connections and 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 restore land and remove surface equipment at gas processing, fractionation and compression facilities, 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.

The following table presents the significant changes to our asset retirement obligations (ARO):

	December 31,
	2013			2012
	(Millions)
Beginning balance	$	576		$	570
Liabilities incurred	4			8
Liabilities settled (1)	(30		)	(44		)
Accretion expense	52			43
Revisions (2)	(48		)	(1		)
Ending balance	$	554		$	576

______________

(1) For 2013 and 2012, liabilities settled include $25 million and $31 million, respectively, related to the abandonment of certain of Transco’s natural gas storage caverns that are associated with a leak in 2010.

(2) Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining life of the assets. The 2013 revision primarily reflects increases in the estimated remaining useful life of the assets. The 2012 revision primarily reflects a decrease in removal cost estimates. The 2013 and 2012 revisions also include increases of $9 million and $13 million, respectively, related to changes in the timing and method of abandonment on certain of Transco’s natural gas storage caverns that were associated with a leak in 2010.

Transco is entitled to collect in rates the amounts necessary to fund its ARO. All funds received for such retirements are deposited into an external trust account dedicated to funding its ARO (ARO Trust). (See Note 13 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) Under its current rate settlement Transco’s annual funding obligation is approximately $36 million, with installments to be deposited monthly.

101

Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

Note 11 – Debt, Banking Arrangements, and Leases

Long-Term Debt

	December 31,
	2013			2012
	(Millions)
Unsecured:
Transco:
6.4% Notes due 2016	$	200		$	200
6.05% Notes due 2018	250			250
7.08% Debentures due 2026	8			8
7.25% Debentures due 2026	200			200
5.4% Notes due 2041	375			375
4.45% Notes due 2042	400			400
Northwest Pipeline:
7% Notes due 2016	175			175
5.95% Notes due 2017	185			185
6.05% Notes due 2018	250			250
7.125% Debentures due 2025	85			85
Williams Partners L.P.:
3.8% Notes due 2015	750			750
7.25% Notes due 2017	600			600
5.25% Notes due 2020	1,500			1,500
4.125% Notes due 2020	600			600
4% Notes due 2021	500			500
3.35% Notes due 2022	750			750
4.5% Notes due 2023	600			—
6.3% Notes due 2040	1,250			1,250
5.8% Notes due 2043	400			—
Credit facility loans	—			375
Unamortized debt discount	(21		)	(16		)
Long-term debt	$	9,057		$	8,437

The terms of our senior unsecured notes are governed by indentures that contain covenants that, among other things, limit: (1) our ability and the ability of our subsidiaries to create liens securing indebtedness and (2) mergers, consolidations, and sales of assets. The indentures also contain customary events of default, upon which the trustee or the holders of the senior unsecured notes may declare all outstanding senior unsecured notes to be due and payable immediately.

102

Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

The following table presents aggregate minimum maturities of long-term debt (excluding unamortized discount) for each of the next five years:

	December 31, 2013
	(Millions)
2014	$	—
2015	750
2016	375
2017	785
2018	500

Issuances and retirements

In November 2013, we completed a public offering of $600 million of 4.5 percent senior unsecured notes due 2023 and $400 million of 5.8 percent senior unsecured notes due 2043. We used the net proceeds to repay amounts outstanding under our commercial paper program, to fund capital expenditures, and for general partnership purposes.

In August 2012, we completed a public offering of $750 million of 3.35 percent senior unsecured notes due 2022. We used the net proceeds to repay outstanding borrowings on our senior unsecured revolving credit facility and for general partnership purposes.

In July 2012, Transco issued $400 million of 4.45 percent senior unsecured notes due 2042 to investors in a private debt placement. An offer to exchange these unregistered notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended, was commenced in November 2012 and completed in December 2012. A portion of the proceeds from the issuance of these notes was used to repay Transco’s $325 million of 8.875 percent senior unsecured notes that matured on July 15, 2012.

Credit Facility

In July 2013, we amended our $2.4 billion credit facility to increase the aggregate commitments to $2.5 billion and extend the maturity date to July 31, 2018. Additionally, Transco and Northwest Pipeline are each able to borrow up to $500 million under the amended credit facility to the extent not otherwise utilized by the other co-borrowers. Our credit facility may also, under certain conditions, be increased up to an additional $500 million. As a result of the modifications, the previously deferred fees and costs related to these facilities are being amortized over the term of the new arrangements. At December 31, 2013, letter of credit capacity under our $2.5 billion credit facility is $1.3 billion, no letters of credit have been issued, and no loans are outstanding under our credit facility.

Our significant financial covenants require our ratio of debt to EBITDA (each as defined in the credit facility) must be no greater than 5 to 1. For the fiscal quarter and the two following fiscal quarters in which one or more acquisitions for a total aggregate purchase price equal to or greater than $50 million has been executed, we are required to maintain a ratio of debt to EBITDA of no greater than 5.5 to 1. In addition, the ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for each of Transco and Northwest Pipeline. At December 31, 2013, we are in compliance with these financial covenants.

The credit agreement governing our credit facility contains the following terms and conditions:

• Each time funds are borrowed, the applicable borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.’s alternate base rate plus an applicable margin or a periodic fixed rate equal to LIBOR plus an applicable margin. The applicable borrower is required to pay a commitment fee (currently 0.175 percent) based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings.

103

Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

• 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, make investments, and allow any material change in the nature of its business.

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

Commercial Paper Program

In March 2013, we initiated a commercial paper program. The program allows a maximum outstanding amount at any time of $2 billion of unsecured commercial paper notes. The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. Proceeds from these notes are used for general partnership purposes, including funding capital expenditures, working capital, and partnership distributions.  We classify commercial paper outstanding in Current liabilities in the Consolidated Balance Sheet, as the outstanding notes at December 31, 2013, have maturity dates less than three months from the date of issuance. At December 31, 2013, $225 million of Commercial paper is outstanding at a weighted average interest rate of 0.42 percent.

Cash Payments for Interest (Net of Amounts Capitalized)

Cash payments for interest (net of amounts capitalized) were $366 million in 2013, $381 million in 2012, and $387 million in 2011.

Leases-Lessee

The future minimum annual rentals under noncancelable operating leases, are payable as follows:

	December 31, 2013
	(Millions)
2014	$	41
2015	35
2016	33
2017	30
2018	29
Thereafter	123
Total	$	291

Under our right-of-way agreement with the Jicarilla Apache Nation, we make annual payments of approximately $8 million and an additional annual payment which varies depending on the prior year’s per-unit NGL margins and the volume of gas gathered by our gathering facilities subject to the agreement. Depending primarily on the per-unit NGL margins for any given year, the additional annual payments could exceed the fixed amount. This agreement expires March 31, 2029.

Total rent expense was $50 million in 2013, $45 million in 2012, and $37 million in 2011.

104

Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

Note 12 – Partners’ Capital

At December 31, 2013 and 2012, the public held 36 percent and 30 percent, respectively, of our total units outstanding, and affiliates of Williams held the remaining units. Transactions which occurred during 2013 and 2012 are summarized below.

In March 2013, we completed an equity issuance of 14,250,000 common units, including 3,000,000 common units sold to Williams in a private placement. Subsequently, the underwriters exercised their option to purchase an additional 1,687,500 common units. The net proceeds of approximately $760 million were used to repay amounts outstanding under our credit facility.

In August 2013, we completed an equity issuance of 21,500,000 common units. Subsequently, the underwriters exercised their option to purchase an additional 3,225,000 common units. The net proceeds of approximately $1.2 billion were used to repay amounts outstanding under our commercial paper program, to fund capital expenditures and for general partnership purposes.

In January 2012, we issued 7,000,000 common units. The net proceeds of approximately $426 million were used to fund capital expenditures and for other partnership purposes.

In February 2012, we closed the Laser Acquisition. In connection with this transaction, we issued 7,531,381 of our common units. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)

In February 2012, the underwriters exercised their option to purchase an additional 1,050,000 common units pursuant to our common unit offering in January 2012. The net proceeds of approximately $64 million were used for general partnership purposes.

In April 2012, we issued 10,000,000 common units. Subsequently, the underwriters exercised their option to purchase an additional 973,368 common units. The net proceeds of approximately $581 million were used for general partnership purposes, including the funding of a portion of the cash purchase price of the Caiman Acquisition. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.) We also used $1 billion in proceeds from an April 2012 sale of 16,360,133 common units to Williams to partially fund the Caiman Acquisition.

In April 2012, we closed the Caiman Acquisition. In connection with this transaction, we issued 11,779,296 of our common units. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)

In June 2012, we acquired a 1 percent interest in Gulfstream from a subsidiary of Williams. In connection with this transaction, we issued 238,050 of our common units. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)

In August 2012, we completed an equity issuance of 8,500,000 common units. Subsequently, the underwriters exercised their option to purchase an additional 1,275,000 common units. The net proceeds of approximately $488 million were used to repay amounts outstanding under our revolving credit facility and for general partnership purposes.

In November 2012, we closed the Geismar Acquisition with Williams. In connection with this transaction, we issued 42,778,812 of our common units. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)

105

Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

Limited Partners’ Rights

Significant rights of the limited partners include the following:

• Right to receive distributions of available cash within 45 days after the end of each quarter.

• No limited partner shall have any management control over our business and affairs; the general partner shall conduct, direct and manage our activities.

• The general partner may be removed if such removal is approved by the unitholders holding at least 66 2/3 percent of the outstanding units voting as a single class, including units held by our general partner and its affiliates.

Incentive Distribution Rights

Our general partner is entitled to incentive distributions if the amount we distribute to unitholders with respect to any quarter exceeds specified target levels shown below:

Quarterly Distribution Target Amount (per unit)	Unitholders	General Partner
Minimum quarterly distribution of $0.35	98%	2%
Up to $0.4025	98	2
Above $0.4025 up to $0.4375	85	15
Above $0.4375 up to $0.5250	75	25
Above $0.5250	50	50

See Note 4 – Allocation of Net Income and Distributions for information regarding IDR waivers.

In the event of liquidation, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and our general partner in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

Issuances of Additional Partnership Securities

Our partnership agreement allows us to issue additional partnership securities for any partnership purpose at any time and from time to time for consideration and on terms and conditions as our general partner determines, all without the approval of any limited partners.

106

Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

Note 13 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, commercial paper, 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, 2013:
Measured on a recurring basis:
ARO Trust investments	$	33		$	33		$	33	$	—		$	—
Energy derivatives assets not designated as hedging instruments	3			3			—		—			3
Energy derivatives liabilities not designated as hedging instruments	(3		)	(3		)	—		(1		)	(2		)
Additional disclosures:
Notes receivable and other	7			7			1		6			—
Long-term debt	(9,057		)	(9,581		)	—		(9,581		)	—
Assets (liabilities) at December 31, 2012:
Measured on a recurring basis:
ARO Trust investments	$	18		$	18		$	18	$	—		$	—
Energy derivatives assets not designated as hedging instruments	5			5			—		—			5
Energy derivatives liabilities not designated as hedging instruments	(1		)	(1		)	—		—			(1		)
Additional disclosures:
Notes receivable and other	11			10			2		8			—
Long-term debt	(8,437		)	(9,624		)	—		(9,624		)	—

Fair Value Methods

We use the following methods and assumptions in estimating the fair value of our financial instruments:

Assets and liabilities measured at fair value on a recurring basis

ARO Trust investments:  Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust that 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, is classified as available-for-sale, and is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.

107

Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

Energy derivatives:  Energy derivatives include commodity based exchange-traded contracts and over-the-counter (OTC) contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives assets are reported in Other current assets and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Energy derivatives liabilities are reported in Other accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.

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 years ended December 31, 2013 or 2012.

Additional fair value disclosures

Notes receivable and other: The disclosed fair value of our notes receivable is primarily determined by an income approach which considers the underlying contract amounts and our assessment of our ability to recover these amounts. The current portion is reported in Trade accounts and notes receivable, net, and the noncurrent portion is reported in Regulatory assets, deferred charges, and otherin 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.

Guarantees

We are required by our revolving credit agreement to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.

Concentration of Credit Risk

Cash equivalents

Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.

Accounts and notes receivable

The following table summarizes concentration of receivables, net of allowances.

	December 31,
	2013		2012
	(Millions)
NGLs, natural gas, and related products and services	$	327	$	393
Transportation of natural gas and related products	193		169
Other	3		—
Total	$	523	$	562

108

Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

Customers include producers, distribution companies, industrial users, gas marketers and pipelines primarily located in the continental United States. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.

Revenues

In 2013, 2012 and 2011, we had one customer in our NGL & Petchem Services segment that accounted for 10 percent, 14 percent, and 17 percent of our consolidated revenues, respectively.

Note 14 – Contingent Liabilities and Commitments

Environmental Matters

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), and other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of December 31, 2013, we have accrued liabilities totaling $20 million for these matters, as discussed below. Our accrual reflects the most likely costs of cleanup, which are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. Certain assessment studies are still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty about the actual number of contaminated sites ultimately identified, the actual amount and extent of contamination discovered and the final cleanup standards mandated by the EPA and other governmental authorities.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. More recent rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, new air quality standards for ground level ozone, one hour nitrogen dioxide emission limits, and new air quality standards impacting storage vessels, pressure valves, and compressors. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.

Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At December 31, 2013, we have accrued liabilities of $13 million for these costs. We expect that these costs will be recoverable through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December 31, 2013, we have accrued liabilities totaling $7 million for these costs.

Geismar Incident

As a result of the previously discussed Geismar Incident, there were two fatalities and numerous individuals (including affiliate employees and contractors) reported injuries, which varied from minor to serious. We are cooperating with the Chemical Safety Board and the EPA regarding their investigations of the Geismar Incident. On October 21, 2013, the EPA issued an Inspection Report pursuant to the Clean Air Act’s Risk Management Program following its inspection of the facility on June 24 through 28, 2013. The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating procedures, employee

109

Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

training, and other matters.  We and the EPA continue to discuss such preliminary determinations, and the EPA could issue penalties pertaining to final determinations.  On December 11, 2013, the Occupational Safety and Health Administration (OSHA) issued Citations for the June 13, 2013 incident, which included a Notice of Penalty for $99,000. Although we and OSHA continue settlement negotiations, we are contesting the citation. On June 28, 2013, the Louisiana Department of Environmental Quality (LDEQ) issued a Consolidated Compliance Order & Notice of Potential Penalty to Williams Olefins, L.L.C. that consolidates claims of unpermitted emissions and other deviations under the Clean Air Act that the parties had been negotiating since 2010 and alleged unpermitted emissions arising from the Geismar Incident. Negotiations with the LDEQ are ongoing. Any potential fines and penalties from these agencies would not be covered by our insurance policy. Additionally, multiple lawsuits, including class actions for alleged offsite impacts, property damage, and personal injury, have been filed against various of our subsidiaries.

Due to the ongoing investigation into the cause of the incident, and the limited information available associated with the filed lawsuits, which do not specify any amounts for claimed damages, we cannot reasonably estimate a range of potential loss related to these contingencies at this time.

Rate Matters

On August 31, 2012, Transco submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in its prior rate proceedings. The new rates became effective March 1, 2013, subject to refund and the outcome of the hearing. On August 27, 2013, Transco filed a stipulation and agreement with the FERC proposing to resolve all issues in this proceeding without the need for a hearing (Agreement). On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement will become effective March 1, 2014. We have provided a reserve for rate refunds of $98 million, in Other accrued liabilities, which we believe is adequate for required refunds as of December 31, 2013, under the Agreement. Refunds will be made on or before April 30, 2014.

Other

In addition to the foregoing, various other proceedings are pending against us which are 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 disclose all significant matters for which we are unable to reasonably estimate a range of possible loss.

Commitments

Commitments for construction and acquisition of property, plant and equipment are approximately $1.4 billion at December 31, 2013.

110

Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

Note 15 – Segment Disclosures

Our reportable segments are Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)

Performance Measurement

We currently evaluate segment operating performance based on Segment profit (loss) from operations, which includes Segment revenues from external and internal customers, segment costs and expenses, and Equity earnings (losses). General corporate expenses represent Selling, general, and administrative expenses that are not allocated to our segments. The accounting policies of the segments are the same as those described in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies. Intersegment revenues primarily represent the sale of NGLs from our natural gas processing plants to our marketing business and are generally accounted for at current market prices as if the sales were to unaffiliated third parties.

111

Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

The following table reflects the reconciliation of Segment revenues and Segment profit (loss) to Total revenues and Operating income as reported in the Consolidated Statement of Comprehensive Income. It also presents other financial information related to long-lived assets.

	Northeast G&P			Atlantic- Gulf		West		NGL & Petchem Services		Eliminations			Total
	(Millions)
2013
Segment revenues:
Service revenues
External	$	335		$	1,414	$	1,053	$	108	$	—		$	2,910
Internal	—			10		1		—		(11		)	—
Total service revenues	335			1,424		1,054		108		(11		)	2,910
Product sales
External	166			830		64		2,715		—			3,775
Internal	—			95		708		294		(1,097		)	—
Total product sales	166			925		772		3,009		(1,097		)	3,775
Total revenues	$	501		$	2,349	$	1,826	$	3,117	$	(1,108	)	$	6,685
Segment profit (loss)	$	(24	)	$	614	$	741	$	275				$	1,606
Less equity earnings (losses)	(7		)	72		—		39					104
Segment operating income (loss)	$	(17	)	$	542	$	741	$	236				1,502
General corporate expenses													(160		)
Operating income													$	1,342
Other financial information:
Depreciation and amortization	$	132		$	363	$	236	$	27	$	—		$	758
2012
Segment revenues:
Service revenues
External	$	168		$	1,371	$	1,067	$	103	$	—		$	2,709
Internal	—			12		5		—		(17		)	—
Total service revenues	168			1,383		1,072		103		(17		)	2,709
Product sales
External	2			709		40		3,860		—			4,611
Internal	—			363		1,089		258		(1,710		)	—
Total product sales	2			1,072		1,129		4,118		(1,710		)	4,611
Total revenues	$	170		$	2,455	$	2,201	$	4,221	$	(1,727	)	$	7,320
Segment profit (loss)	$	(37	)	$	574	$	980	$	295				$	1,812
Less equity earnings (losses)	(23		)	92		—		42					111
Segment operating income (loss)	$	(14	)	$	482	$	980	$	253				1,701
General corporate expenses													(184		)
Operating income													$	1,517
Other financial information:
Depreciation and amortization	$	76		$	381	$	234	$	23	$	—		$	714

112

Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

	Northeast G&P			Atlantic- Gulf		West		NGL & Petchem Services		Eliminations			Total
	(Millions)
2011
Segment revenues:
Service revenues
External	$	49		$	1,332	$	1,053	$	83	$	—		$	2,517
Internal	—			—		4		—		(4		)	—
Total service revenues	49			1,332		1,057		83		(4		)	2,517
Product sales
External	—			606		11		4,580		—			5,197
Internal	—			531		1,622		56		(2,209		)	—
Total product sales	—			1,137		1,633		4,636		(2,209		)	5,197
Total revenues	$	49		$	2,469	$	2,690	$	4,719	$	(2,213	)	$	7,714
Segment profit (loss)	$	23		$	585	$	1,181	$	246				$	2,035
Less equity earnings (losses)	(1		)	90		—		53					142
Segment operating income (loss)	$	24		$	495	$	1,181	$	193				1,893
General corporate expenses													(118		)
Operating income													$	1,775
Other financial information:
Depreciation and amortization	$	5		$	365	$	236	$	15	$	—		$	621

The following table reflects Total assets, Investments, and Additions to long-lived assets by reportable segment:  

	Total Assets at December 31,						Investments at December 31,				Additions to Long-Lived Assets at December 31,
	2013			2012			2013		2012		2013		2012		2011
	(Millions)
Northeast G&P (1)	$	6,229		$	4,745		$	737	$	511	$	1,376	$	3,909	$	204
Atlantic-Gulf	10,007			8,734			930		774		1,072		1,002		650
West	4,767			4,688			—		—		210		360		301
NGL & Petchem Services	1,822			1,500			520		515		392		282		103
Other corporate assets	147			409			—		—		5		16		25
Eliminations (2)	(614		)	(367		)	—		—		—		—		—
Total	$	22,358		$	19,709		$	2,187	$	1,800	$	3,055	$	5,569	$	1,283

(1) 2012 Additions to long-lived assets includes the Caiman and Laser Acquisitions. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)

(2) Eliminations primarily relate to the intercompany accounts receivable generated by our cash management program.

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Williams Partners L. P.

Notes to Consolidated Financial Statements – (Continued)

Note 16 – Subsequent Events

Commercial Paper Outstanding Balance

As of February 25, 2014, $900 million is outstanding under our commercial paper program.

Canada Dropdown

In February 2014, we agreed to acquire certain Canadian operations from Williams for total consideration valued at approximately $1.2 billion. The transaction is expected to close in February 2014. We expect to fund the purchase with $25 million of cash, the issuance of 25,577,521 Class D limited-partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. In lieu of cash distributions, the Class D units will receive quarterly distributions of additional paid-in-kind Class D units, all of which will be convertible to common units at a future date. The acquired Canadian operations will be included in our NGL & Petchem Services segment. The agreement also provides that we can issue additional Class D units to Williams on a quarterly basis through 2015 for up to a total of $200 million in cash for the purpose of funding certain facility expansions.

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Williams Partners L.P.

Quarterly Financial Data

(Unaudited)

Summarized quarterly financial data are as follows:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(Millions, except per-unit amounts)
2013
Revenues	$	1,756	$	1,727	$	1,586	$	1,616
Product costs	798		810		718		722
Net income	321		257		280		212
Net income attributable to controlling interests	321		256		279		211
Basic and diluted net income per common unit	0.50		0.31		0.52		0.12
2012
Revenues	$	1,968	$	1,817	$	1,717	$	1,818
Product costs	974		907		781		864
Net income	408		243		290		291
Net income attributable to controlling interests	408		243		290		291
Basic and diluted net income per common unit	0.85		0.29		0.38		0.42

The sum of earnings per unit for the four quarters may not equal the total earnings per unit for the year due to changes in the average number of common units outstanding and rounding.

2013

Net income for fourth-quarter 2013 includes:

• $16 million accrued loss associated with a settlement in principle of a producer claim against us at Northeast G&P (see Note 7 – Other Income and Expenses);

• $14 million in expenses associated with the Geismar Incident at NGL & Petchem Services (see Note 7 – Other Income and Expenses).

Net income for third-quarter 2013 includes:

• $9 million accrued loss associated with a contingent liability related to a producer claim against us at Northeast G&P (see Note 7 – Other Income and Expenses);

• $50 million of income associated with insurance recoveries related to the Geismar Incident at NGL & Petchem Services (see Note 7 – Other Income and Expenses).

Net income for second-quarter 2013 includes $12 million of income related to an insurance recovery associated with the Eminence abandonment regulatory asset that will not be recovered through rates at Atlantic-Gulf. (See Note 7 – Other Income and Expenses.)

2012

Net income for fourth-quarter 2012 includes:

• $18 million related to the reversal of project feasibility costs from expense to capital at Atlantic-Gulf (see Note 7 – Other Income and Expenses);

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Williams Partners L.P.

Quarterly Financial Data – (Continued)

(Unaudited)

• $11 million of reorganization-related costs, including consulting costs, allocated to us from Williams (see Note 5 – Related Party Transactions).

Net income for second-quarter 2012 includes $21 million of Caiman and Laser acquisition and transition-related costs at Northeast G&P. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)

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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 general partner’s Chief Executive Officer and Chief Financial 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 Williams Partners L.P. 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 general partner’s Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.

Changes in Internal Controls Over Financial Reporting

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

Management’s Annual Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a - 15(f) and 15d - 15(f) under the Securities Exchange Act of 1934). Our internal controls over financial reporting are designed to provide reasonable assurance to our management and board of directors 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 board of directors; 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 general partner’s Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2013, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (1992). Based on our assessment we concluded that, as of December 31, 2013, our internal control over financial reporting was effective.

Ernst & Young LLP, our independent registered public accounting firm, has audited our internal control over financial reporting, as stated in their report which is included in this Annual Report on Form 10-K.

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Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting

The Board of Directors of Williams Partners GP LLC,

General Partner of Williams Partners L.P.

and the Limited Partners of Williams Partners L.P.

We have audited Williams Partners L.P.’s (the “Partnership”) internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (the “COSO criteria”). Williams Partners L.P.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Williams Partners L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Williams Partners L.P. as of December 31, 2013 and 2012, and the related consolidated statements of comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2013, and our report dated February 26, 2014 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 26, 2014

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Item 9B.Other Information

None.

PART III

Item 10.Directors, Executive Officers and Corporate Governance

As a limited partnership, we have no directors or officers. Instead, our general partner, Williams Partners GP LLC, manages our operations and activities. Our general partner is not elected by our unitholders and is not subject to re-election on a regular basis in the future. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our general partner’s directors are appointed by Williams, the corporate parent of our general partner. Accordingly, we do not have a procedure by which our unitholders may recommend nominees to our general partner’s Board of Directors.

All of the senior officers of our general partner are also senior officers of Williams.

The following table shows information for the directors and executive officers of our general partner.

Name	Age	Position with Williams Partners GP LLC
Alan S. Armstrong	51	Chairman of the Board and Chief Executive Officer
Donald R. Chappel	62	Chief Financial Officer and Director
Rory L. Miller	53	Senior Vice President - Atlantic-Gulf and Director
James E. Scheel	49	Senior Vice President - Northeast G&P and Director
H. Brent Austin	59	Director and Member of Audit and Conflicts Committees
Alice M. Peterson	61	Director and Member of Audit and Conflicts Committees
Laura A. Sugg	52	Director and Member of Audit Committee
Frank E. Billings	51	Senior Vice President - Corporate Strategic Development
Allison G. Bridges	54	Senior Vice President - West
John R. Dearborn	56	Senior Vice President - NGL & Petchem Services
Fred E. Pace	52	Senior Vice President - E&C
Brian L. Perilloux	52	Senior Vice President - Operational Excellence
Craig L. Rainey	61	General Counsel
Ted T. Timmermans	57	Vice President, Controller, and Chief Accounting Officer

Officers serve at the discretion of the Board of Directors of our general partner. There are no family relationships among any of the directors or executive officers of our general partner. The directors of our general partner are appointed for one-year terms. In addition to independence and financial literacy for members of our general partner’s Board of Directors who serve on the Audit Committee and Conflicts Committee, our general partner considers the following qualifications relevant to service on its Board of Directors in the context of our business and structure:

• Industry Experience in the oil, natural gas, and petrochemicals business.

• Engineering and Construction Experience.

• Financial and Accounting Experience.

• Corporate Governance Experience.

• Securities and Capital Markets Experience.

• Executive Leadership Experience.

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• Public Policy and Government Experience.

• Strategy Development and Risk Management Experience.

• Operating Experience.

• Knowledge of the marketplace and political and regulatory environments relevant to the energy sector in the locations where we operate currently or plan to in the future (Marketplace Knowledge).

Certain information about each of our general partner’s directors and executive officers is set forth below, including qualifications relevant to service on our general partner’s Board of Directors.

Alan S. Armstrong has served as a director of our general partner since 2005 and has served as the Chairman of the Board of Directors and the Chief Executive Officer of our general partner since 2011. Mr. Armstrong has served as the Chief Executive Officer, President, and a director of Williams since 2011. From 2010 to 2011, Mr. Armstrong served as Senior Vice President – Midstream of our general partner. From 2005 until 2010, Mr. Armstrong served as the Chief Operating Officer of our general partner. From 2002 to 2011, Mr. Armstrong served as Senior Vice President - Midstream of Williams and acted as President of Williams’ midstream business. From 1999 to 2002, Mr. Armstrong was Vice President, Gathering and Processing in Williams’ midstream business and from 1998 to 1999 was Vice President, Commercial Development, in Williams’ midstream business. Since 2012, Mr. Armstrong has served as a director of Access Midstream Partners GP, L.L.C. (ACMP GP), the general partner of Access Midstream Partners, L.P. (a midstream natural gas service provider), in which Williams owns an interest. Mr. Armstrong has also served as a director of BOK Financial Corporation, a financial services company, since April 2013.

Mr. Armstrong’s qualifications include Marketplace Knowledge and industry, engineering and construction, financial and accounting, corporate governance, securities and capital markets, executive leadership, public policy and government, strategy development and risk management, and operating experience.

Donald R. Chappel has served as the Chief Financial Officer and a director of our general partner since 2005. Mr. Chappel has served as Senior Vice President and Chief Financial Officer of Williams since 2003. Mr. Chappel served as Chief Financial Officer and a director of the general partner of Williams Pipeline Partners L.P. (WMZ), a limited partnership formed by Williams to own and operate natural gas transportation and storage assets, from 2008 until WMZ merged with us in 2010. Since 2012, Mr. Chappel has served as a director of ACMP GP. Mr. Chappel has served as a member of the Management Committee of Northwest Pipeline since 2007. Mr. Chappel also serves as a director of SUPERVALU Inc., a grocery and pharmacy company.

Mr. Chappel’s qualifications include Marketplace Knowledge and industry, financial and accounting, corporate governance, securities and capital markets, executive leadership, and strategy development and risk management experience.

Rory L. Miller has served as a director of our general partner since 2011 and as Senior Vice President - Atlantic-Gulf of Williams and our general partner since January 2013. From 2011 until January 2013, Mr. Miller was Senior Vice President - Midstream of Williams and our general partner, acting as President of Williams’ midstream business. Mr. Miller was a Vice President of Williams’ midstream business from 2004 until 2011. Mr. Miller has served as a member of the Management Committee of Transco since 2013.

Mr. Miller’s qualifications include Marketplace Knowledge and industry, engineering and construction, executive leadership, strategy development and risk management, and operating experience.

James E. Scheel has served as a director of our general partner since 2012 and as Senior Vice President - Northeast G&P of Williams and our general partner since January 2014. From 2012 to January 2014 he served as Senior Vice President - Corporate Strategic Development of Williams and our general partner. From 2011 until 2012, Mr. Scheel served as Vice President of Business Development of Williams’ midstream business. He joined Williams in 1988 and has served in leadership roles in business strategic development, engineering and operations, the NGL business, and international operations. Since 2012, Mr. Scheel has served as a director of ACMP GP.

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Mr. Scheel’s qualifications include Marketplace Knowledge and industry, engineering and construction, executive leadership, strategy development and risk management, and operating experience.

H. Brent Austin has served as a director of our general partner since 2010. Mr. Austin has been Managing Director and Chief Investment Officer of Alsamora L.P., a Houston-based private limited partnership with real estate and diversified equity investments, since 2003. Mr. Austin served as a director of the general partner of WMZ from October 2008 until WMZ merged with us in 2010. From 2002 to 2003, Mr. Austin was President and Chief Operating Officer of El Paso Corporation, an owner and operator of natural gas transportation pipelines, storage, and other midstream assets, where he managed all nonregulated operations as well as all financial functions.

Mr. Austin’s qualifications include Marketplace Knowledge and industry, financial and accounting, corporate governance, securities and capital markets, executive leadership, public policy and government, strategy development and risk management, and operating experience.

Alice M. Peterson has served as a director of our general partner since 2005. Since October 2012, Ms. Peterson has served as Chief Operating Officer of PPL Group, a private equity firm. Since 2000, Ms. Peterson has served as a director of RIM Finance, LLC, a wholly owned subsidiary of Research in Motion, Ltd., the maker of the Blackberry™ handheld device. From 2009 to 2010, Ms. Peterson served as the Chief Ethics Officer of SAI Global, a provider of compliance and ethics services, and was a special advisor to SAI Global until 2012. From 2011 to 2013, Ms. Peterson served as a director of Patina Solutions, which provides professionals on a flexible basis to help companies achieve their business objectives. From 2006 to 2010, Ms. Peterson served as a director of Navistar Financial Corporation, a wholly owned subsidiary of Navistar International, a manufacturer of commercial and military trucks, diesel engines and parts. Ms. Peterson founded and served as the president of Syrus Global, a provider of ethics, compliance, and reputation management solutions from 2002 to 2009, when it was acquired by SAI Global. Ms. Peterson served as a director of Hanesbrands Inc., an apparel company, from 2006 to 2009. Ms. Peterson served as a director of TBC Corporation, a marketer of private branded replacement tires, from July 2005 to November 2005, when it was acquired by Sumitomo Corporation of America. From 1998 to 2004, she served as a director of Fleming Companies, a supplier of consumer package goods. From 2000 to 2001, Ms. Peterson served as President and General Manager of RIM Finance, LLC. From 1998 to 2000, Ms. Peterson served as Vice President of Sears Online and from 1993 to 1998, as Vice President and Treasurer of Sears, Roebuck and Co. Ms. Peterson serves on the faculty of the Practicing Law Institute and the National Association of Corporate Directors.

Ms. Peterson’s qualifications include industry, financial and accounting, corporate governance, securities and capital markets, executive leadership, strategy development and risk management, and operating experience.

Laura A. Sugg has served as a director of our general partner since January 2014, having previously served as a director of our general partner from 2011 to 2012. Ms. Sugg has served as a director of Williams since 2010 and has served as a director of Denbury Resources, Inc., an independent oil and gas company, since 2012. Ms. Sugg retired from ConocoPhillips (then an international, integrated oil company) in 2010, having served as President, Australasia Division, a position responsible for the profit and loss and growth responsibility of ConocoPhillip’s operations in Australia and East Timor. Ms. Sugg began her career in 1983 at Sohio Petroleum and joined Phillips Petroleum, now ConocoPhillips, in 1986 and performed various business development, human resources and operations roles. From 2003 to 2005, Ms. Sugg was ConocoPhillip’s General Manager E&P Human Resources, with responsibility for global compensation and benefits, leadership succession planning, and all human resource functions for 10,000 worldwide employees in 16 countries. From 2002 to 2003, Ms. Sugg was a ConocoPhillip’s midstream executive responsible for profit and loss, health, safety and environment, and operations for its gas gathering, processing, and fractionation business in the U.S., Canada, and Trinidad. From 2000 to 2002, Ms. Sugg was Vice President Worldwide Gas for Phillips with responsibility for its global liquefied natural gas and coal bed methane business development and the profit and loss for its North American gas marketing operations. Ms. Sugg was a director of Mariner Energy, Inc., an independent oil and gas exploration and production company, from 2009 until its merger with Apache Corporation in 2010.

Ms. Sugg’s qualifications include industry, engineering and construction, financial and accounting, corporate governance, executive leadership, strategy development and risk management, operating, and human resource management experiences.

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Frank E. Billings has served as Senior Vice President - Corporate Strategic Development of Williams and our general partner since January 2014. From January 2013 to January 2014, he served as Senior Vice President - Northeast G&P of Williams and our general partner. Mr. Billings served as a Vice President of Williams’ midstream business from 2011 until 2013 and as Vice President, Business Development of Williams from 2010 to 2011. He served as President of Cumberland Plateau Pipeline Company (a privately held company developing an ethane pipeline to serve the Marcellus shale area) from 2009 until 2010. From 2008 to 2009, Mr. Billings served as Senior Vice President of Commercial for Crosstex Energy, Inc. and Crosstex Energy L.P. (an independent midstream energy services master limited partnership and its parent corporation). In 1988, Mr. Billings joined MAPCO Inc., which merged with a Williams subsidiary in 1998, serving in various management roles, including in 2008 as a Vice President in the midstream business.

Allison G. Bridges has served as Senior Vice President - West of Williams and our general partner since January 2013. Ms. Bridges served as the Vice President and General Manager of Williams Gas Pipeline - West from 2010 until 2013. From 2003 to 2010, Ms. Bridges was Vice President Commercial Operations of Northwest Pipeline. Ms. Bridges joined Transco in 1981, now a subsidiary of Williams and us, holding various management positions in accounting, rates, planning and business development. Ms. Bridges has served as a member of the Management Committee of Northwest Pipeline since 2007.

John R. Dearborn has served as Senior Vice President - NGL & Petchem Services of Williams and our general partner since April 2013. Mr. Dearborn served as a senior leader for Saudi Basic Industries Corporation, a petrochemical company, from 2011 to 2013. From 2001 to 2011, Mr. Dearborn served in a variety of leadership positions with The Dow Chemical Company (Dow). Mr. Dearborn also worked for Union Carbide Corporation (prior to its merger with Dow) from 1981 to 2001 where he served in several leadership roles.

Fred E. Pace has served as Senior Vice President - E&C (engineering and construction) of Williams and our general partner since January 2013. From 2011 until 2013, Mr. Pace served Williams in project engineering and development roles, including service as Vice President, Engineering and Construction for Williams’ midstream business. From 2009 to 2011, Mr. Pace was the managing member of PACE Consulting, LLC, an engineering and consulting firm serving the energy industry. In 2003, Mr. Pace co-founded Clear Creek Natural Gas, LLC, later known as Clear Creek Energy Services, LLC, a provider of engineering, construction, and operational services to the energy industry, where he served as Chief Executive Officer until 2009. Mr. Pace has over 30 years of experience in the engineering, construction, operation, and project management areas of the energy industry, including prior service with Williams from 1985 to 1990.

Brian L. Perilloux has served as Senior Vice President – Operational Excellence of Williams and our general partner since January 2013. Mr. Perilloux served as a Vice President of Williams’ midstream business from 2011 until 2013. From 2007 to 2011, Mr. Perilloux served in various roles in Williams’ midstream business, including engineering and construction roles. Prior to joining Williams, Mr. Perilloux was an officer of a private international engineering and construction company.

Craig L. Rainey has served as the General Counsel of our general partner since 2012. Mr. Rainey has also served as Senior Vice President and General Counsel of Williams since 2012. From 2001 until 2012, Mr. Rainey served as an Assistant General Counsel of Williams, primarily supporting Williams’ midstream business and former exploration and production business during that time. He joined Williams in 1999 as a senior counsel and he has practiced law since 1977.

Ted T. Timmermans has served as Vice President, Controller, and Chief Accounting Officer of Williams and our general partner since 2005. Mr. Timmermans served as an Assistant Controller of Williams from 1998 to 2005. Mr. Timmermans served as Chief Accounting Officer of the general partner of WMZ from 2008 until WMZ merged with us in 2010.

Governance

Our general partner adopted governance guidelines that address, among other areas, director independence, policies on meeting attendance and preparation, executive sessions of nonmanagement directors and communications with nonmanagement directors.

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Director Independence

Because we are a limited partnership, the NYSE does not require our general partner’s Board of Directors to be composed of a majority of directors who meet the criteria for independence required by the NYSE or to maintain nominating/corporate governance and compensation committees composed entirely of independent directors.

Our general partner’s Board of Directors has adopted governance guidelines which require at least three members of our general partner’s Board of Directors to be independent directors as defined by the rules of the NYSE and have no material relationship with us or our general partner. Our general partner’s Board of Directors at least annually reviews the independence of its members expected to be independent and affirmatively makes a determination that each director meets these independence standards. Our governance guidelines are available on our website at www.williamslp.com at the Corporate Responsibility/Corporate Governance Guidelines tab.

Our general partner’s Board of Directors affirmatively determined that each of Mesdames Peterson and Sugg, and Messrs. Austin and Thomas F. Karam (who served as a director of our general partner until January 2014) is an “independent director” under the current listing standards of the NYSE and our director independence standards. In so doing, the Board of Directors determined that each of these individuals met the “bright line” independence standards of the NYSE. In addition, there were no transactions or relationships between each director and any member of his or her immediate family on one hand, and us or any affiliate of us on the other, that were identified and considered by the Board of Directors. Accordingly, the Board of Directors of our general partner affirmatively determined that all of the directors mentioned above are independent. Because Messrs. Armstrong, Chappel, Miller, and Scheel, are employees, officers and/or directors of Williams, they are not independent under these standards.

Mesdames Peterson and Sugg and Mr. Austin do not serve as an executive officer of any nonprofit organization to which we or our affiliates made contributions within any single year of the preceding three years that exceeded the greater of $1.0 million or 2 percent of such organization’s consolidated gross revenues. Further, there were no discretionary contributions made by us or our affiliates to a nonprofit organization with which such director, or such director’s spouse, has a relationship that impact the director’s independence.

Meeting Attendance and Preparation

Members of the Board of Directors of our general partner are expected to attend at least 75 percent of regular Board meetings and meetings of the committees on which they serve, either in person or telephonically. In addition, directors are expected to be prepared for each meeting of the Board by reviewing written materials distributed in advance.

Executive Sessions of NonManagement Directors

Our general partner’s nonmanagement Board members periodically meet outside the presence of our general partner’s executive officers. The Chair of the Audit Committee serves as the presiding director for executive sessions of nonmanagement Board members. The current Chair of the Audit Committee and the presiding director is Ms. Alice M. Peterson.

Communications with Directors

Interested parties wishing to communicate with our general partner’s nonmanagement directors, individually or as a group, may do so by contacting our general partner’s Corporate Secretary or the presiding director. The contact information is maintained at the corporate responsibility/corporate governance guidelines tab of our website at www.williamslp.com.

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The current contact information is as follows:

Williams Partners L.P.

c/o Williams Partners GP LLC

One Williams Center, Suite 4700

Tulsa, Oklahoma 74172

Attn: Presiding Director

Williams Partners L.P.

c/o Williams Partners GP LLC

One Williams Center, Suite 4700

Tulsa, Oklahoma 74172

Attn: Corporate Secretary

Board Committees

The Board of Directors of our general partner has a separately designated standing Audit Committee established in accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934 and a Conflicts Committee. The following is a description of each of the committees and committee membership.

Board Committee Membership

	Audit	Conflicts
	Committee	Committee
H. Brent Austin	ü	•
Alice M. Peterson	•	ü
Laura A. Sugg	ü

__________________________

ü  = committee member

•    = chairperson

Audit Committee

Our general partner’s Board of Directors has determined that all members of the Audit Committee meet the heightened independence requirements of the NYSE for audit committee members and that all members are financially literate as defined by the rules of the NYSE. The Board of Directors has further determined that Ms. Peterson and Mr. Austin qualify as “audit committee financial experts” as defined by the rules of the SEC. Biographical information for each of these persons is set forth above. The Audit Committee is governed by a written charter adopted by the Board of Directors. For further information about the Audit Committee, please read the “Report of the Audit Committee” below and “Principal Accountant Fees and Services.”

Conflicts Committee

The Conflicts Committee of our general partner’s Board of Directors reviews specific matters that the Board believes may involve conflicts of interest. The Conflicts Committee determines if resolution of the conflict is fair and reasonable to us. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates and must meet the independence and experience requirements established by the NYSE and other federal securities laws. Because Ms. Sugg also serves on the Board of Directors of Williams, she is not eligible to serve on the Conflicts Committee. Any matters approved by the Conflicts Committee will be conclusively deemed fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe to us or our unitholders.

Code of Business Conduct and Ethics

Our general partner has adopted a Code of Business Conduct and Ethics for directors, officers and employees. We intend to disclose any amendments to or waivers of the Code of Business Conduct and Ethics on behalf of our general

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partner’s Chief Executive Officer, Chief Financial Officer, Controller and persons performing similar functions on our website at www.williamslp.com under the Corporate Responsibility tab, promptly following the date of any such amendment or waiver.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires our general partner’s executive officers and directors and persons who own more than 10 percent of a registered class of our equity securities to file with the SEC and the NYSE reports of ownership of our securities and changes in reported ownership. Executive officers and directors of our general partner and greater than 10 percent unitholders are required by SEC rules to furnish to us copies of all Section 16(a) reports that they file. Based solely on a review of reports furnished to our general partner, or written representations from reporting persons that all reportable transactions were reported, we believe that during the fiscal year ended December 31, 2013 our general partner’s officers, and directors and our greater than 10 percent common unitholders timely filed all reports they were required to file under Section 16(a).

Transfer Agent and Registrar

Computershare Trust Company, N.A. serves as registrar and transfer agent for our common units. Contact information for Computershare is as follows:

Computershare Trust Company, N.A.

P.O. Box 30170

College Station, Texas 77842-3170

Phone: (781) 575-2879 or toll-free, (877) 498-8861

Hearing impaired: (800) 952-9245

Internet: www.computershare.com/investor

Send overnight mail to:

Computershare Trust Company, N.A.

211 Quality Circle, Suite 210

College Station, Texas 77845

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REPORT OF THE AUDIT COMMITTEE

The Audit Committee oversees our financial reporting process on behalf of the Board of Directors. Management has the primary responsibility for the financial statements and the reporting process including the systems of internal controls. The Audit Committee operates under a written charter approved by the Board. The charter, among other things, provides that the Audit Committee has authority to appoint, retain, oversee and terminate when appropriate the independent auditor. In this context, the Audit Committee:

• Reviewed and discussed the audited financial statements in this annual report on Form 10-K with management, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and the clarity of disclosures in the financial statements;

• Reviewed with Ernst & Young LLP, the independent auditors, who are responsible for expressing an opinion on the conformity of those audited financial statements with generally accepted accounting principles, their judgments as to the quality and acceptability of Williams Partners L.P.’s accounting principles and such other matters as are required to be discussed with the Audit Committee under generally accepted auditing standards;

• Received the written disclosures and the letter from Ernst & Young LLP required by applicable requirements of the Public Company Accounting Oversight Board regarding Ernst & Young LLP’s communications with the audit committee concerning independence, and discussed with Ernst & Young LLP its independence;

• Discussed with Ernst & Young LLP the matters required to be discussed by Auditing Standard No. 16, “Communications with Audit Committees” issued by the Public Company Accounting Oversight Board;

• Discussed with Williams Partners L.P.’s internal auditors and Ernst & Young LLP the overall scope and plans for their respective audits. The Audit Committee meets with the internal auditors and Ernst & Young LLP, with and without management present, to discuss the results of their examinations, their evaluations of Williams Partners L.P.’s internal controls and the overall quality of Williams Partners L.P.’s financial reporting; and

• Based on the foregoing reviews and discussions, recommended to the Board of Directors that the audited financial statements be included in the annual report on Form 10-K for the year ended December 31, 2013, for filing with the SEC.

This report has been furnished by the members of the Audit Committee of the Board of Directors:

— Alice M. Peterson - Chair

— H. Brent Austin

— Laura A. Sugg

The report of the Audit Committee in this report shall not be deemed incorporated by reference into any other filing by Williams Partners L.P. under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under such acts.

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Item 11.Executive Compensation

Compensation Discussion and Analysis

We are managed by the executive officers of our general partner who are also executive officers of Williams. Neither we nor our general partner have a compensation committee. The executive officers of our general partner are compensated directly by Williams. All decisions as to the compensation of the executive officers of our general partner who are involved in our management are made by the Compensation Committee of Williams. Therefore, we do not have any policies or programs relating to compensation of the executive officers of our general partner and we make no decisions relating to such compensation. None of the executive officers of our general partner have employment agreements with us or are otherwise specifically compensated for their service as an executive officer of our general partner. A full discussion of the policies and programs of the Compensation Committee of Williams will be set forth in the proxy statement for Williams’ 2014 annual meeting of stockholders which will be available upon its filing on the SEC’s website at www.sec.gov and on Williams’ website at www.williams.com at the “Investors - SEC Filings” tab (Williams’ 2014 Proxy Statement). Williams’ 2014 Proxy Statement will also be available free of charge from the Corporate Secretary of our general partner. We reimburse our general partner for direct and indirect general and administrative expenses attributable to our management (which expenses include the share of the compensation paid to the executive officers of our general partner attributable to the time they spend managing our business). Please read “Certain Relationships and Related Transactions, and Director Independence - Reimbursement of Expenses of Our General Partner” for more information regarding this arrangement.

Executive Compensation

The following table summarizes the compensation attributable to services performed for us in 2013 for our general partner’s named executive officers (NEOs), consisting of our principal executive officer, principal financial officer, and three other most highly compensated executive officers.

Further information regarding compensation of our principal executive officer, Mr. Armstrong, who also serves as the President and Chief Executive Officer of Williams, our principal financial officer, Mr. Chappel, who also serves as the Senior Vice President and Chief Financial Officer of Williams, Mr. Miller, who serves as our Senior Vice President – Atlantic-Gulf and who also serves as Senior Vice President – Atlantic-Gulf of Williams, and Mr. Scheel, who serves as our Senior Vice President – Northeast G&P and who also serves as Senior Vice President – Northeast G&P of Williams, will be set forth in Williams’ 2014 Proxy Statement. Compensation amounts set forth in Williams’ 2014 Proxy Statement will include all compensation paid by Williams, including the amounts in the table below attributable to services performed for us.

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2013 Summary Compensation Table

The following table sets forth certain information with respect to Williams’ compensation of our general partner’s NEOs attributable to us during fiscal years 2013, 2012, and 2011:

Name and Principal Position (1)	Year	Salary		Bonus		Stock Awards(2)		Option Awards(3)		Nonequity Incentive Plan Compensation(4)		Change in Pension Value and Nonqualified Deferred Compensation Earnings (5)			All Other Compensation(6)		Total
Alan S. Armstrong	2013	$	961,504	$	—	$	3,038,135	$	781,694	$	977,904	$	(417,140	)	$	25,694	$	5,367,791
Chairman &	2012	897,083		—		2,683,728		821,993		1,051,409		893,930			20,562		6,368,705
Chief Executive Officer	2011	548,550		—		1,545,849		277,298		997,943		409,057			34,722		3,813,419
Donald R. Chappel	2013	602,267		—		1,582,276		394,708		398,268		(261,822		)	21,175		2,736,872
Chief Financial Officer	2012	574,182		—		1,636,073		493,354		504,004		393,328			15,316		3,616,257
	2011	383,865		—		986,533		233,883		462,091		297,698			11,313		2,375,383
Rory L. Miller	2013	452,692		—		914,600		228,153		285,000		(190,499		)	16,468		1,706,414
Senior Vice President,	2012	370,774		—		942,723		284,275		247,816		256,771			16,955		2,119,314
Atlantic-Gulf	2011	344,933		—		968,722		229,652		306,233		238,837			13,253		2,101,630
Frank E. Billings	2013	400,000		—		914,600		228,153		160,000		(103,025		)	23,312		1,623,040
Senior Vice President,	2012	—		—		—		—		—		—			—		—
Corporate Strategic Development	2011	—		—		—		—		—		—			—		—
James E. Scheel	2013	366,303		—		918,749		229,191		177,232		(128,675		)	19,073		1,581,873
Senior Vice President,	2012	320,924		—		1,014,919		306,046		208,058		154,558			18,986		2,023,491
Northeast G&P	2011	—		—		—		—		—		—			—		—

(1) Name and Principal Position. Mr. Billings previously served as our Senior Vice President – Northeast G&P from January 2013 to January 2014. Mr. Scheel previously served as our Senior Vice President – Corporate Strategic Development from February 2012 to January 2014.

(2) Stock Awards. Awards were granted under the terms of Williams’ 2007 Incentive Plan and include time-based and performance-based restricted stock units (RSUs). Amounts shown are the grant date fair value of awards attributable to us computed in accordance with FASB ASC Topic 718. The assumptions used by Williams to determine the grant date fair value of the stock awards can be found in the Williams Annual Report on Form 10-K for the year-ended December 31, 2013.

The potential maximum values attributable to us of the performance-based RSUs, subject to changes in performance outcomes of Williams, are as follows:

	2013 Performance-Based RSU Maximum Potential
Alan S. Armstrong	$	3,849,223
Donald R. Chappel	1,590,247
Rory L. Miller	919,184
Frank E. Billings	919,184
James E. Scheel	923,377

(3) Option Awards. Awards are granted under the terms of Williams’ 2007 Incentive Plan and include nonqualified stock options. Amounts shown are the grant date fair value of awards attributable to us computed in accordance with FASB ASC Topic 718. The assumptions used by Williams to determine the grant date fair value of the option awards can be found in the Williams Annual Report on Form 10-K for the year-ended December 31, 2013. The options may be exercised to acquire Williams’ common stock. The NEOs do not receive any option awards from us.

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(4) Non-Equity Incentive Plan. Williams provides an annual incentive program to the NEOs and payments are based on the financial performance of Williams. The maximum annual incentive pool funding for NEOs is 250 percent of target. We do not sponsor any non-equity incentive plans.

(5) Change in Pension Value and Nonqualified Deferred Compensation Earnings. The amount shown is the aggregate change from December 31, 2012 to December 31, 2013 in the actuarial present value of the accrued benefit under the qualified pension and nonqualified plans sponsored by Williams that is attributable to us. Please refer to the “Pension Benefits” table in Williams’ 2014 Proxy Statement for further details of the present value of the accrued benefit. We do not sponsor any qualified pension or nonqualified plans.

(6) All Other Compensation. Amounts shown represent payments made by Williams on behalf of the NEOs and attributable to us. These amounts include life insurance premiums, a 401(k) matching contribution, tax gross-ups on the imputed income related to spousal travel for business purposes, and perquisites (if applicable). Amounts do not include arrangements that are generally available to our employees and do not discriminate in scope, terms, or operations in favor of our NEOs, such as relocation, medical, dental, and disability programs. None of these amounts were provided directly by us. Perquisites include financial planning services, mandated annual physical exam, and personal use of Williams’ aircraft. If the NEOs used Williams’ aircraft, the incremental cost method was used to calculate the personal use of Williams’ aircraft. The incremental cost calculation includes such items as fuel, maintenance, weather and airport services, pilot meals, pilot overnight expenses, aircraft telephone, and catering. No perquisites are disclosed because the aggregate amount attributable to us did not exceed $10,000 for any of our NEOs.

We have not included tables with information about grants of plan-based awards, outstanding equity awards at fiscal year-end, option exercises and stock vested, pension benefits, and nonqualified deferred compensation because we do not currently sponsor such plans or grant awards to our NEOs under our general partner’s long-term incentive plan, which is the only compensation plan sponsored by our general partner. Information related to Williams’ sponsorship of any such plans will be set forth in Williams’ 2014 Proxy Statement. In addition, our NEOs are not entitled to any compensation as a result of a change-in-control of us or the termination of their service as an NEO of our general partner.

Compensation Committee Interlocks and Insider Participation

As previously discussed, our general partner’s Board of Directors is not required to maintain, and does not maintain, a compensation committee. During 2013, all compensation decisions with respect to our NEOs were made by the Compensation Committee of the Board of Directors of Williams, which is comprised entirely of independent members of Williams’ Board. In addition, none of these individuals receive any compensation directly from us or our general partner. Please read “Certain Relationships and Related Transactions, and Director Independence” below for information about relationships among us, our general partner and Williams.

Compensation Policies and Practices as They Relate to Risk Management

We do not have any employees. We are managed and operated by the directors and officers of our general partner and employees of Williams perform services on our behalf. We do not have any compensation policies or practices that need to be assessed or evaluated for the effect on our operations. Please read “Compensation Discussion and Analysis,” “Employees,” and “Certain Relationships and Related Transactions, and Director Independence” for more information about this arrangement. For an analysis of any risks arising from Williams’ compensation policies and practices, please read Williams’ 2014 Proxy Statement.

Board Report on Compensation

Neither we nor our general partner has a compensation committee. The Board of Directors of our general partner has reviewed and discussed with management the Compensation Discussion and Analysis set forth above and based on this review and discussion has approved it for inclusion in this Form 10-K.

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The Board of Directors of Williams Partners GP LLC:

Alan S. Armstrong,

H. Brent Austin,

Donald R. Chappel,

Rory L. Miller,

Alice M. Peterson,

James E. Scheel,

Laura A. Sugg

Compensation of Directors

We are managed by the Board of Directors of our general partner. Members of the Board of Directors who are also officers or employees of Williams or an affiliate of us or Williams do not receive additional compensation for serving on the Board of Directors. Please read “Compensation Discussion and Analysis,” “Executive Compensation,” and “Certain Relationships and Related Transactions, and Director Independence - Reimbursement of Expenses of Our General Partner” for information about how we reimburse our general partner for direct and indirect general and administrative expenses attributable to our management. Effective August 2013, non-employee directors receive a bi-annual compensation package consisting of the following, which amounts are paid on September 1 and March 1: (a) $60,000 cash retainer; and (b) $2,500 cash retainer each for service on the Conflicts Committee or Audit Committee of the Board of Directors. If a non-employee director’s service on the Board of Directors commenced after September 1 and prior to the final day of February, or between March 1 and August 31, the non-employee director receives a prorated bi-annual compensation package. In addition to the bi-annual compensation package, each non-employee director who was first elected to the Board of Directors receives a one-time cash payment of $25,000 on the date of such election. Also, each non-employee director serving as a member of the Conflicts Committee receives $1,250 cash for each Conflicts Committee meeting attended by such director. Fees for attendance at meetings of the Conflicts Committee are paid on March 1 and September 1 for meetings held during the preceding months.

Each non-employee director is also reimbursed for out-of-pocket expenses in connection with attending meetings of the Board of Directors or its committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law. We also reimburse non-employee directors for the costs of education programs relevant to their duties as Board members.

For their service, non-management directors earned the following compensation in 2013:

Director Compensation Fiscal Year 2013

Name	Fees Earned or Paid in Cash (1)		Unit Awards	Option Awards	Nonequity Incentive Plan Compensation	Change in Pension Value and Nonqualified Deferred Compensation Earnings	All Other Compensation	Total
H. Brent Austin	$	116,250	—	—	—	—	—	$	116,250
Thomas F. Karam (2)	115,000		—	—	—	—	—	115,000
Alice M. Peterson	116,500		—	—	—	—	—	116,500

_____________

(1) Bi-annual compensation retainer fees and Conflicts Committee meeting fees earned in 2013 are reflected in this column.

(2) Mr. Karam resigned his board position in January 2014.

Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth information known to us as of February 26, 2014, concerning beneficial ownership by holders of 5 percent or more of our common units. Unless otherwise indicated by footnote, the companies named in the table have sole voting and investment power with respect to the common units listed.

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Name of Beneficial Owner	Common Units Beneficially Owned	Percentage of Total Common Units Beneficially Owned
The Williams Companies, Inc.(1)	279,472,244	63.72%
Williams Gas Pipeline Company, LLC(1)	279,472,244	63.72%

Percentage of common units beneficially owned is based on 438,625,699 common units outstanding. Our general partner, Williams Partners GP LLC, also owns all of our 2 percent general partner interest and IDRs. The Williams Companies, Inc. is the sole member of our general partner.

____________

(1) Williams Gas Pipeline Company, LLC (WGP) is the record owner of 279,472,244 common units. The Williams Companies, Inc. (Williams) is the sole member of WGP and may, pursuant to Rule 13d-3 of the Securities Exchange Act of 1934 (the Act), be deemed to beneficially own the common units held by WGP. Williams files information with, or furnishes information to, the Securities and Exchange Commission pursuant to the information requirements of the Act. The address of each of these companies is One Williams Center, Tulsa, Oklahoma 74172.

The following table sets forth, as of February 3, 2014, the number of shares of common stock of Williams beneficially owned by each of the directors of our general partner, by the NEOs of our general partner, and by all directors and executive officers of our general partner as a group. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all shares shown as beneficially owned by them, subject to community property laws where applicable.

Name of Beneficial Owner	Shares of Common Stock Owned Directly or Indirectly(1)	Shares Underlying Options Exercisable Within 60 Days(2)	Total	Percent of Class
Alan S. Armstrong	459,605	419,571	879,176	*
H. Brent Austin	—	—	—	*
Frank E. Billings	59,954	18,852	78,806	*
Donald R. Chappel	581,948	508,067	1,090,015	*
Rory L. Miller	159,404	77,021	236,425	*
Alice M. Peterson	—	—	—	*
James E. Scheel	89,593	40,070	129,663	*
Laura A. Sugg	17,219	—	17,219	*
All current directors and executive officers as a group (14 persons)	1,746,742	1,295,768	3,042,510	*

Percentage of shares beneficially owned is based on 684,272,147 shares outstanding on February 3, 2014, plus, as to the holder thereof only and no other person, the number of shares (if any) that the person has the right to acquire as of February 3, 2014, or within 60 days from that date, through the exercise of all options and other rights.

______________

* Less than 1%.

(1) Includes Williams restricted stock units held under the terms of Williams incentive and investment plans as follows: Mr. Armstrong, 343,658 restricted stock units; Mr. Billings, 56,037 restricted stock units; Mr. Chappel, 197,890 restricted stock units; Mr. Miller, 123,853 restricted stock units; Mr. Scheel, 89,590 restricted stock units; and Ms. Sugg, 8,806 restricted stock units. Williams restricted stock units do not provide the holder with voting or investment power.

(2) The SEC deems a person to have a beneficial ownership of all shares that the person has the right to acquire within 60 days. The shares indicated represent stock options granted under Williams’ current or previous stock option plans, which are currently exercisable or which will become exercisable within 60 days of February 3, 2014. Shares subject to options cannot be voted.

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The following table sets forth, as of February 3, 2014, the number of our common units beneficially owned by each of the directors of our general partner, by the NEOs of our general partner, and by all directors and executive officers of our general partner as a group. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

Name of Beneficial Owner	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned
Alan S. Armstrong (1)	20,000	*
H. Brent Austin (2)	10,336	*
Frank E. Billings	—	*
Donald R. Chappel	22,584	*
Rory L. Miller	—	*
Alice M. Peterson	4,524	*
James E. Scheel	—	*
Laura A. Sugg	—	*
All current directors and executive officers as a group (14 persons)	67,175	*

Percentage of common units beneficially owned is based on 438,625,699 common units outstanding.

_____________________

* Less than 1%.

(1) Mr. Armstrong is the trustee of the Alan Stuart Armstrong Trust dated June 16, 2010, who has the power to vote or to direct the vote of, the right to receive or the power to direct the receipt of distributions from, the power to dispose or direct the dispositions of, and the right to receive the proceeds from the sale of, 10,000 common units held by the trust. Mr. Armstrong’s spouse is the trustee of the Shelly Stone Armstrong Trust dated June 16, 2010, who has the power to vote or to direct the vote of, the right to receive or the power to direct the receipt of dividends from, the power to dispose or direct the disposition of, and the right to receive the proceeds from the sale of, 10,000 common units held by the trust.

(2) Mr. Austin holds 9,000 common units in a joint tenants-in-common account with his spouse.

Securities Authorized for Issuance Under Equity Compensation Plans

Our general partner maintains the Williams Partners GP LLC Long-Term Incentive Plan (the Plan) for employees, consultants, and directors of our general partner and its affiliates who perform services for us. Initially, the Plan permitted granting of awards covering an aggregate of 700,000 common units, in the form of options, restricted units, phantom units, or unit appreciation rights. Our general partner has not granted any awards under the Plan since 2008. The following table provides information concerning common units that were potentially subject to issuance under the Williams Partners GP LLC Long-Term Incentive Plan as of December 31, 2013.

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a)	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b)	Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plan (Excluding Securities Reflected in Column(a)) (c)
Equity compensation plans approved by security holders	—	—	—
Equity compensation plans not approved by security holders.	—	—	686,597
Total	—	—	686,597

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Item 13.Certain Relationships and Related Transactions, and Director Independence

Transactions with Related Persons

An affiliate of our general partner owns 279,472,244 common units representing a 62 percent limited partner interest in us. Williams also owns 100 percent of our general partner, which allows it to control us. Certain officers and directors of our general partner also serve as officers and/or directors of Williams. Our general partner owns a 2 percent general partner interest and incentive distribution rights in us.

In addition to the related transactions and relationships discussed below, information about such transactions and relationships is included in Note 5 – Related Party Transactions and Note 6 – Investments of our Notes to Consolidated Financial Statements and is incorporated into this Item 13 by reference.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments made or to be made by us to our general partner and its affiliate in connection with our ongoing operation and upon our liquidation, if any. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

	Operational Stage
Distributions of available cash to our general partner and its affiliate	We will generally make cash distributions 98 percent to common unitholders, including an affiliate of our general partner as holder of an aggregate of 279,472,244 common units, and the remaining 2 percent to our general partner.
	In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner will be entitled to increasing percentages of the distributions, up to 50 percent of the distributions above the highest target level. We refer to the rights to the increasing distributions as “incentive distribution rights.” Our general partner agreed to temporarily waive a portion of incentive distributions in connection with certain assets acquired in 2012 and to support our 2013 cash distribution metrics as our large platform of growth projects moves toward completion. For further information about distributions, please read “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities-” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Management’s Discussion and Analysis of Financial Condition and Liquidity.”
Reimbursement of expenses to our general partner and its affiliates	Please read “—Reimbursement of Expenses of Our General Partner” below.
Withdrawal or removal of our general partner	If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
	Liquidation Stage
Liquidation	Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Reimbursement of Expenses of Our General Partner

Our general partner does not receive any management fee or other compensation for its management of our business. However, we reimburse our general partner for expenses incurred on our behalf, including expenses incurred in compensating employees of an affiliate of our general partner who perform services on our behalf. These expenses include all allocable expenses necessary or appropriate to the conduct of our business. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. There is no minimum or maximum amount that may be paid or reimbursed to our general partner for expenses incurred on our behalf.

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For the fiscal year ended December 31, 2013, our general partner allocated approximately $21 million of expense to us for the services performed on our behalf by our executive officers, who are also employees of Williams, and those of our directors, who are also employees of Williams. This allocated expense included our allocable share of salaries, non-equity incentive plan compensation, and other employment-related expenses, including Williams restricted stock unit and stock option awards, retirement plans, health and welfare plans, employer-related payroll taxes, matching contributions made under a Williams defined contribution plan and premiums for life insurance.

Williams affiliates charge us for the costs associated with the employees that operate our assets. These costs totaled $328 million for the year ended December 31, 2013. In addition, general and administrative services are provided to us by employees of Williams, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our operations. 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. These costs totaled $416 million for the year ended December 31, 2013. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of the costs of doing business incurred by Williams. These services are provided to Transco and Northwest Pipeline pursuant to separate administrative service agreements with an affiliate of Williams.

Commodity Purchase Contracts

We purchase olefins and NGLs for resale from Williams Energy Canada ULC, a subsidiary of Williams, at market prices at the time of purchase. These purchases totaled $123 million for the year ended December 31, 2013.

Operating Agreements with Equity Method Investees

We are party to operating agreements with unconsolidated companies where our investment is accounted for using the equity method. These operating agreements typically provide for reimbursement or payment to us for certain direct operational payroll and employee benefit costs, materials, supplies and other charges and also for management services. Williams supplied a portion of these services, primarily those related to employees since we do not have any employees, to the equity method investees. The following amounts were billed to the equity method investments we operate.

	Year Ended
	December 31, 2013
	(Millions)
Cardinal Pipeline Company LLC	$	1
Discovery Producer Services LLC	21
Gulfstream Natural Gas System, L.L.C.	6
Laurel Mountain Midstream, LLC	24
Overland Pass Pipeline Company LLC	13
Pine Needle LNG Company, LLC	2
	$	67

Summary of Other Transactions with Williams and its Affiliates

Quarterly Cash Distributions

For the year ended December 31, 2013, we distributed approximately $1.4 billion to Williams and its affiliates as quarterly distributions on our common units, the 2 percent general partner interest, and the general partner’s incentive distribution rights.

Initial Omnibus Agreement

Upon the closing of our initial public offering (IPO) in 2005, we entered into an omnibus agreement with Williams and its affiliates that was not the result of arm’s-length negotiations. The omnibus agreement continues to govern our relationship with Williams regarding the following matters in connection with our IPO:

• Indemnification for certain environmental liabilities and tax liabilities;

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• Reimbursement for certain expenditures; and

• A license for the use of certain software and intellectual property.

Total amounts received under this agreement for the year ended December 31, 2013, were less than $1 million.

Intellectual Property License

Williams and its affiliates granted a license to us for the use of certain marks, including our logo, for as long as Williams controls our general partner, at no charge.

February 2010 Omnibus Agreement

In connection with Williams’ contribution of ownership interests in certain entities to us in February 2010, we entered into an omnibus agreement with Williams. Pursuant to this omnibus agreement, Williams remains obligated to indemnify us for an amount based on the amortization over time of deferred revenue amounts that relate to cash payments received prior to the closing of the contribution transaction for services to be rendered by us in the future at the Devils Tower floating production platform located in Mississippi Canyon Block 773. Amounts received under this agreement for the year ended December 31, 2013, were $12 million. In 2010, we also entered into a contribution agreement with Williams in connection with this transaction. The contribution agreement continues to govern our relationship with Williams with respect to indemnification for certain tax liabilities.

Equity Issuances

Concurrent with our March 2013 equity issuance, we sold 3,000,000 common units to Williams in a private placement for approximately $143 million. The proceeds were used to repay amounts outstanding under our credit facility.

In connection with both our March and August 2013 equity issuances, our general partner contributed $41 million to maintain its 2 percent general partnership interest.

Canada Dropdown

In February 2014, we entered into a contribution agreement with Williams pursuant to which we agreed to acquire certain of Williams’ Canadian operations, including an oil sands offgas processing plant near Fort McMurray, Alberta, an NGL/olefin fractionation facility and B/B Splitter at Redwater, Alberta and the Boreal pipeline. The transaction is expected to close in February 2014. We expect to fund the transaction with $25 million of cash, the issuance of 25,577,521 Class D limited-partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. In lieu of cash distributions, the Class D units will receive quarterly distributions of additional paid-in-kind Class D units, all of which will be convertible to common units at a future date. The agreement also provides that Williams will agree to waive a portion of its IDR distributions to accommodate certain post-closing adjustments, if necessary.    

As part of this transaction we will become a party to various ancillary agreements with affiliates of Williams related to the transaction, including agreements that provide for:

• Certain rights to access and use the acquired facilities by Williams affiliates so Williams may continue to develop additional projects in the area;

• Development of future projects in the area by the parties;

• Williams employees to operate the acquired assets and the allocation of costs related to the operation of those assets; and

• Construction services by a Williams affiliate to expand and modify the Redwater facilities.

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The agreement also provides that we can issue Class D units to Williams on a quarterly basis through 2015 for up to a total of $200 million in cash for the purpose of funding certain facility expansions. We are also obligated to backstop existing Williams’ guarantees issued to third parties related to the performance of the acquired business until such time these guarantees can be issued directly to third parties by us.

Review, Approval or Ratification of Transactions with Related Persons

Our partnership agreement contains specific provisions that address potential conflicts of interest between our general partner and its affiliates, including Williams, on one hand, and us and our subsidiaries, on the other hand. Whenever such a conflict of interest arises, our general partner will resolve the conflict. Our general partner may, but is not required to, seek the approval of such resolution from the Conflicts Committee of the Board of Directors of our general partner, which is comprised of independent directors. The partnership agreement provides that our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or to our unitholders if the resolution of the conflict is:

• Approved by the Conflicts Committee;

• Approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

• On terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

• Fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

If our general partner does not seek approval from the Conflicts Committee and the Board of Directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the Conflicts Committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of the partnership, unless the context otherwise requires. See “Directors, Executive Officers and Corporate Governance — Governance — Board Committees — Conflicts Committee.”

In addition, our Code of Business Conduct and Ethics requires that all employees, including employees of affiliates of Williams who perform services for us and our general partner, avoid or disclose any activity that may interfere, or have the appearance of interfering, with their responsibilities to us and our unitholders. Conflicts of interest that cannot be avoided must be disclosed to a supervisor who is then responsible for establishing and monitoring procedures to ensure that we are not disadvantaged.

Director Independence

Please read “Directors, Executive Officers and Corporate Governance — Governance — Director Independence” and “ — Board Committees” in Item 10 above for information about the independence of our general partner’s Board of Directors and its committees, which information is incorporated into this Item 13 by reference.

137

Item 14.Principal Accountant Fees and Services

Fees for professional services provided by our independent auditors for each of the last two fiscal years were as follows:

	2013		2012
	(Thousands)
Audit Fees	$	6,446	$	6,868
Audit-Related Fees	13		—
Tax Fees	46		39
All Other Fees	—		—
	$	6,505	$	6,907

Fees for audit services in 2013 and 2012 include fees associated with the annual audit, the reviews of our quarterly reports on Form 10-Q, the audit of our assessment of internal controls as required by Section 404 of the Sarbanes-Oxley Act of 2002 and services provided in connection with other filings with the SEC. The fees for audit services do not include audit costs for stand-alone audits for equity investees. Audit-Related fees include services under certain agreed-upon procedures for other compliance purposes. Tax fees for 2013 and 2012 include fees for review of our federal tax return. Ernst & Young LLP does not provide tax services to our general partner’s executive officers.

The Audit Committee of our general partner’s Board of Directors is responsible for appointing, setting compensation for and overseeing the work of Ernst & Young LLP, our independent auditors. The Audit Committee has established a policy regarding pre-approval of all audit and non-audit services provided by Ernst & Young LLP. On an ongoing basis, our general partner’s management presents specific projects and categories of service to the Audit Committee to request advance approval. The Audit Committee reviews those requests and advises management if the Audit Committee approves the engagement of Ernst & Young LLP. On a quarterly basis, the management of our general partner reports to the Audit Committee regarding the services rendered by, including the fees of, the independent accountant in the previous quarter and on a cumulative basis for the fiscal year. The Audit Committee may also delegate the ability to pre-approve audit and permitted non-audit services, excluding services related to our internal control over financial reporting, to any two committee members, provided that any such pre-approvals are reported at a subsequent Audit Committee meeting. In 2013 and 2012, 100 percent of Ernst & Young LLP’s fees were pre-approved by the Audit Committee.

PART IV

Item 15.Exhibits and Financial Statement Schedules

(a) 1 and 2. Williams Partners L.P. financials

	Page
Covered by reports of independent auditors:
Consolidated statement of comprehensive income for each of the three years ended December 31, 2013	77
Consolidated balance sheet at December 31, 2013 and 2012	78
Consolidated statement of changes in equity for each of the three years ended December 31, 2013	79
Consolidated statement of cash flows for each of the three years ended December 31, 2013	80
Notes to consolidated financial statements	81
Not covered by reports of independent auditors:
Quarterly financial data (unaudited)	115

All other schedules have been omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the financial statements and notes thereto.

(a) 3 and (b). The following documents are included as exhibits to this report:

138

Exhibit Number		Description
§ 2.1	—	Contribution Agreement, dated as of January 15, 2010, by and among Williams Energy Services, LLC, Williams Gas Pipeline Company, LLC, WGP Gulfstream Pipeline Company, L.L.C., Williams Partners GP LLC, Williams Partners L.P., Williams Partners Operating LLC and, for a limited purpose, The Williams Companies, Inc, including exhibits thereto (filed on January 19, 2010 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
3.1	—	Certificate of Limited Partnership of Williams Partners L.P. (filed on May 2, 2005 as Exhibit 3.1 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-124517)) and incorporated herein by reference.
3.2	—	Certificate of Formation of Williams Partners GP LLC (filed on May 2, 2005 as Exhibit 3.3 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-124517)) and incorporated herein by reference.
3.3	—	Amended and Restated Agreement of Limited Partnership of Williams Partners L.P. (including form of common unit certificate), as amended by Amendments Nos. 1, 2, 3, 4, 5, 6, 7, 8, 9, and 10 (filed on October 31, 2013 as Exhibit 3.3 to Williams Partners L.P.'s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
3.4	—	Amended and Restated Limited Liability Company Agreement of Williams Partners GP LLC (filed on August 26, 2005 as Exhibit 3.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
4.1	—	Certificate of Incorporation of Williams Partners Finance Corporation (filed on September 22, 2006 as Exhibit 4.5 to Williams Partners L.P.’s registration statement on Form S-3 (File No. 333-137562)) and incorporated herein by reference.
4.2	—	Bylaws of Williams Partners Finance Corporation (filed on September 22, 2006 as Exhibit 4.6 to Williams Partners L.P.’s registration statement on Form S-3 (File No. 333-137562)) and incorporated herein by reference.
4.3	—	Indenture, dated as of February 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 10, 2010 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
4.4	—	Indenture, dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., as Trustee (filed on June 23, 2006 as Exhibit 4.1 to Northwest Pipeline Corporation’s Form 8-K (File. No. 001-07414)), and incorporated herein by reference.
4.5	—	Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York (filed on April 5, 2007 as Exhibit 4.1 to Northwest Pipeline Corporation’s Form 8-K (File No. 001-07414)) and incorporated herein by reference.
4.6	—	Indenture, dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Northwest Pipeline GP’s Form 8-K File No. 001-07414)) and incorporated herein by reference.
4.7	—	Senior Indenture, dated as of July 15, 1996 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s registration statement on Form S-3 (File No. 333-02155)) and incorporated herein by reference.
4.8	—	Senior Indenture, dated as of November 30, 1995, between Northwest Pipeline Corporation and Chemical Bank Trustee (filed September 14, 1995 as Exhibit 4.1 to Northwest Pipeline Corporation’s registration statement on Form S-3 (File No. 033-62639)) and incorporated herein by reference.
4.9	—	Indenture, dated as of April 11, 2006, between Transcontinental Gas Pipe Line Corporation and JPMorgan Chase Bank, N.A., as Trustee with regard to Transcontinental Gas Pipe Line’s $200 million aggregate principal amount of 6.4% Senior Note due 2016 (filed on April 11, 2006 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form 8-K (File No. 001-07584)) and incorporated herein by reference.

139

Exhibit Number		Description
4.10	—	Indenture, dated May 22, 2008, between Transcontinental Gas Pipe Line Corporation and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form 8-K (File No. 001-07584)) and incorporated herein by reference.
4.11	—	Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
4.12	—	First Supplemental Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010 as Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
4.13	—	Indenture, dated as of August 12, 2011, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 12, 2011 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584)) and incorporated herein by reference.
4.14	—	Second Supplemental Indenture, dated as of November 17, 2011, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed November 18, 2011 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
4.15	—	Indenture, dated as of July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on July 16, 2012 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584)) and incorporated herein by reference.
4.16	—	Third Supplemental Indenture (including Form of 3.35% Senior Notes due 2022), dated as of August 14, 2012, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 14, 2012 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
4.17	—	Fourth Supplemental Indenture, dated as of November 15, 2013, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 18, 2013 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
#10.1	—	Williams Partners GP LLC Long-Term Incentive Plan (filed on August 26, 2005 as Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
# 10.2	—	Amendment to the Williams Partners GP LLC Long-Term Incentive Plan, dated November 28, 2006 (filed on December 4, 2006 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
# 10.3	—	Amendment No. 2 to the Williams Partners GP LLC Long-Term Incentive Plan, dated December 2, 2008 (filed on February 26, 2009, as Exhibit 10.4 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-32599)) and incorporated herein by reference.
10.4	—	Director Compensation Policy dated November 29, 2005, as revised August 27,2013 (filed on October 31, 2013 as Exhibit 10.2 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. (File No. 001-32599)) and incorporated herein by reference.
10.5	—	Contribution Agreement, dated as of March 19, 2012, between Caiman Energy, LLC and Williams Partners L.P. (filed on April 26, 2012 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-32599)) and incorporated herein by reference.
10.6	—	First Amendment to Contribution Agreement, dated as of April 27, 2012, between Caiman Energy, LLC and Williams Partners L.P. (filed on August 2, 2012 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-32599)) and incorporated herein by reference.
10.7	—	Amendments Nos. 2, 3, 4, and 5 to Contribution Agreement between Caiman Energy, LLC and Williams Partners L.P. (filed on May 8, 2013 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-32599)) and incorporated herein by reference.

140

Exhibit Number		Description
10.8	—	Contribution Agreement entered into as of October 29, 2012, by and among The Williams Companies, Inc., Williams Partners GP LLC, Williams Partners L.P., Williams Partners Operating LLC, and Williams Field Services Group, LLC (filed on November 2, 2012 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
10.9	—	First Amended & Restated Credit Agreement dated as of July 31, 2013, by and among Williams Partners L.P., Northwest Pipeline LLC and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (filed on July 31, 2013 as Exhibit 10 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-32599)) and incorporated herein by reference.
* 12	—	Computation of Ratio of Earnings to Fixed Charges.
* 21	—	List of subsidiaries of Williams Partners L.P.
* 23.1	—	Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP.
* 23.2	—	Consent of Independent Registered Public Accounting Firm, Deloitte & Touche LLP.
* 24	—	Power of attorney.
* 31.1	—	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
* 31.2	—	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
** 32	—	Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer.
*101.INS	—	XBRL Instance Document.
*101.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.
§	Pursuant to item 601(b) (2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.
#	Management contract or compensatory plan or arrangement.

141

SIGNATURE

Pursuant to the requirements 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.

WILLIAMS PARTNERS L.P.

(Registrant)

By: Williams Partners GP LLC, its general partner

/s/ Ted T. Timmermans

Ted T. Timmermans

Vice President, Controller, and Chief Accounting

Officer (Duly Authorized Officer and Principal

    Accounting Officer)

February 26, 2014

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

Signature	Title	Date
/s/ ALAN S. ARMSTRONG	Chief Executive Officer and	February 26, 2014
Alan S. Armstrong	Chairman of the Board (Principal Executive Officer)
/s/ DONALD R. CHAPPEL	Chief Financial Officer and Director	February 26, 2014
Donald R. Chappel	(Principal Financial Officer)
/s/ TED T. TIMMERMANS	Vice President, Controller, and Chief	February 26, 2014
Ted T. Timmermans	Accounting Officer (Principal Accounting Officer)
/s/ H. BRENT AUSTIN*	Director	February 26, 2014
H. Brent Austin
/s/ RORY L. MILLER*	Director	February 26, 2014
Rory L. Miller
/s/ ALICE M. PETERSON*	Director	February 26, 2014
Alice M. Peterson
/s/ JAMES E. SCHEEL *	Director	February 26, 2014
James E. Scheel
/s/ LAURA A. SUGG *	Director	February 26, 2014
Laura A. Sugg
*By:     /s/ WILLIAM H. GAULT		February 26, 2014
William H. Gault Attorney-in-fact

EXHIBIT INDEX

Exhibit Number		Description
§ 2.1	—	Contribution Agreement, dated as of January 15, 2010, by and among Williams Energy Services, LLC, Williams Gas Pipeline Company, LLC, WGP Gulfstream Pipeline Company, L.L.C., Williams Partners GP LLC, Williams Partners L.P., Williams Partners Operating LLC and, for a limited purpose, The Williams Companies, Inc, including exhibits thereto (filed on January 19, 2010 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
3.1	—	Certificate of Limited Partnership of Williams Partners L.P. (filed on May 2, 2005 as Exhibit 3.1 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-124517)) and incorporated herein by reference.
3.2	—	Certificate of Formation of Williams Partners GP LLC (filed on May 2, 2005 as Exhibit 3.3 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-124517)) and incorporated herein by reference.
3.3	—	Amended and Restated Agreement of Limited Partnership of Williams Partners L.P. (including form of common unit certificate), as amended by Amendments Nos. 1, 2, 3, 4, 5, 6, 7, 8, 9, and 10 (filed on October 31, 2013 as Exhibit 3.3 to Williams Partners L.P.'s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
3.4	—	Amended and Restated Limited Liability Company Agreement of Williams Partners GP LLC (filed on August 26, 2005 as Exhibit 3.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
4.1	—	Certificate of Incorporation of Williams Partners Finance Corporation (filed on September 22, 2006 as Exhibit 4.5 to Williams Partners L.P.’s registration statement on Form S-3 (File No. 333-137562)) and incorporated herein by reference.
4.2	—	Bylaws of Williams Partners Finance Corporation (filed on September 22, 2006 as Exhibit 4.6 to Williams Partners L.P.’s registration statement on Form S-3 (File No. 333-137562)) and incorporated herein by reference.
4.3	—	Indenture, dated as of February 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 10, 2010 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
4.4	—	Indenture, dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., as Trustee (filed on June 23, 2006 as Exhibit 4.1 to Northwest Pipeline Corporation’s Form 8-K (File. No. 001-07414)), and incorporated herein by reference.
4.5	—	Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York (filed on April 5, 2007 as Exhibit 4.1 to Northwest Pipeline Corporation’s Form 8-K (File No. 001-07414)) and incorporated herein by reference.
4.6	—	Indenture, dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Northwest Pipeline GP’s Form 8-K File No. 001-07414)) and incorporated herein by reference.
4.7	—	Senior Indenture, dated as of July 15, 1996 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s registration statement on Form S-3 (File No. 333-02155)) and incorporated herein by reference.
4.8	—	Senior Indenture, dated as of November 30, 1995, between Northwest Pipeline Corporation and Chemical Bank Trustee (filed September 14, 1995 as Exhibit 4.1 to Northwest Pipeline Corporation’s registration statement on Form S-3 (File No. 033-62639)) and incorporated herein by reference.

Exhibit Number		Description
4.9	—	Indenture, dated as of April 11, 2006, between Transcontinental Gas Pipe Line Corporation and JPMorgan Chase Bank, N.A., as Trustee with regard to Transcontinental Gas Pipe Line’s $200 million aggregate principal amount of 6.4% Senior Note due 2016 (filed on April 11, 2006 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form 8-K (File No. 001-07584)) and incorporated herein by reference.
4.10	—	Indenture, dated May 22, 2008, between Transcontinental Gas Pipe Line Corporation and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form 8-K (File No. 001-07584)) and incorporated herein by reference.
4.11	—	Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
4.12	—	First Supplemental Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010 as Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
4.13	—	Indenture, dated as of August 12, 2011, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 12, 2011 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584)) and incorporated herein by reference.
4.14	—	Second Supplemental Indenture, dated as of November 17, 2011, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed November 18, 2011 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
4.15	—	Indenture, dated as of July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on July 16, 2012 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584)) and incorporated herein by reference.
4.16	—	Third Supplemental Indenture (including Form of 3.35% Senior Notes due 2022), dated as of August 14, 2012, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 14, 2012 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
4.17	—	Fourth Supplemental Indenture, dated as of November 15, 2013, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 18, 2013 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
# 10.1	—	Williams Partners GP LLC Long-Term Incentive Plan (filed on August 26, 2005 as Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
# 10.2	—	Amendment to the Williams Partners GP LLC Long-Term Incentive Plan, dated November 28, 2006 (filed on December 4, 2006 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
# 10.3	—	Amendment No. 2 to the Williams Partners GP LLC Long-Term Incentive Plan, dated December 2, 2008 (filed on February 26, 2009, as Exhibit 10.4 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-32599)) and incorporated herein by reference.
10.4	—	Director Compensation Policy dated November 29, 2005, as revised August 27, 2013 (filed on October 31, 2013 as Exhibit 10.2 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. (File No. 001-32599)) and incorporated herein by reference.

Exhibit Number		Description
10.5	—	Contribution Agreement, dated as of March 19, 2012, between Caiman Energy, LLC and Williams Partners L.P. (filed on April 26, 2012 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-32599)) and incorporated herein by reference.
10.6	—	First Amendment to Contribution Agreement, dated as of April 27, 2012, between Caiman Energy, LLC and Williams Partners L.P. (filed on August 2, 2012 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-32599)) and incorporated herein by reference.
10.7	__	Amendments Nos. 2, 3, 4, and 5 to Contribution Agreement between Caiman Energy, LLC and Williams Partners L.P. (filed on May 8, 2013 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-32599)) and incorporated herein by reference.
10.8	—	Contribution Agreement entered into as of October 29, 2012, by and among The Williams Companies, Inc., Williams Partners GP LLC, Williams Partners L.P., Williams Partners Operating LLC, and Williams Field Services Group, LLC (filed on November 2, 2012 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
10.9	__	First Amended & Restated Credit Agreement dated as of July 31, 2013, by and among Williams Partners L.P., Northwest Pipeline LLC and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (filed on July 31, 2013 as Exhibit 10 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-32599)) and incorporated herein by reference.
* 12	—	Computation of Ratio of Earnings to Fixed Charges.
* 21	—	List of subsidiaries of Williams Partners L.P.
* 23.1	—	Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP.
* 23.2	—	Consent of Independent Registered Public Accounting Firm, Deloitte & Touche LLP.
* 24	—	Power of attorney.
* 31.1	—	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
* 31.2	—	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
** 32	—	Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer.
*101.INS	—	XBRL Instance Document.
*101.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.
§	Pursuant to item 601(b) (2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.
#	Management contract or compensatory plan or arrangement.

EX-12

Exhibit 12

Williams Partners L.P.

Computation of Ratio of Earnings to Fixed Charges

	Years Ended December 31,
	2013			2012			2011			2010			2009
	(Millions)
Earnings:
Income before income taxes	$	1,087		$	1,243		$	1,514		$	1,190		$	1,065
Less: Equity earnings (1)	(104		)	(111		)	(142		)	(109		)	(81		)
Income before income taxes and equity earnings	983			1,132			1,372			1,081			984
Add:
Fixed charges:
Interest incurred (1)	456			441			426			393			259
Rental expense representative of interest factor	10			8			7			6			8
Total fixed charges	466			449			433			399			267
Distributed income of equity method investees (1)	152			160			167			133			78
Less:
Interest capitalized	(69		)	(36		)	(11		)	(29		)	(58		)
Total earnings as adjusted	$	1,532		$	1,705		$	1,961		$	1,584		$	1,271
Fixed charges	$	466		$	449		$	433		$	399		$	267
Ratio of earnings to fixed charges	3.29			3.80			4.53			3.97			4.76

(1) Prior years have been recast to include the effect of 50%-owned companies.

EX-21

Exhibit 21

ENTITY	JURISDICTION
Aux Sable Liquid Products Inc.	Delaware
Aux Sable Liquid Products LP	Delaware
Aux Sable Midstream LLC	Delaware
Bargath LLC	Delaware
Baton Rouge Fractionators LLC	Delaware
Baton Rouge Pipeline LLC	Delaware
Black Marlin Pipeline LLC	Texas
Caiman Energy II, LLC	Delaware
Carbonate Trend Pipeline LLC	Delaware
Cardinal Operating Company, LLC	Delaware
Cardinal Pipeline Company, LLC	North Carolina
Constitution Pipeline Company, LLC	Delaware
Discovery Gas Transmission LLC	Delaware
Discovery Producer Services LLC	Delaware
DMP NEW YORK, INC.	New York
Gulfstar One LLC	Delaware
Gulfstream Natural Gas System, L.L.C.	Delaware
HI-BOL Pipeline LLC	Delaware
Laurel Mountain Midstream Operating LLC	Delaware
Laurel Mountain Midstream, LLC	Delaware
LNE PIPELINE CORPORATION	New York
Marsh Resources, LLC	Delaware
Mid-Continent Fractionation and Storage, LLC	Delaware
Overland Pass Pipeline Company, LLC	Delaware
Pacific Connector Gas Pipeline, LLC	Delaware
Pacific Connector Gas Pipeline, LP	Delaware
Parachute Pipeline LLC	Delaware
Pine Needle LNG Company, LLC	North Carolina
Pine Needle Operating Company, LLC	Delaware
Three Rivers Midstream LLC	Delaware
TransCardinal Company, LLC	Delaware
TransCarolina LNG Company, LLC	Delaware
Transcontinental Gas Pipe Line Company, LLC	Delaware
Wamsutter LLC	Delaware
WFS - Liquids LLC	Delaware
WFS - Pipeline LLC	Delaware
WFS Enterprises LLC	Delaware
WFS Gathering Company, L.L.C.	Delaware
Williams Blu Operating LLC	Delaware
Williams Energy Resources LLC	Delaware
Williams Energy Solutions LLC	Delaware

ENTITY	JURISDICTION
Williams Field Services - Gulf Coast Company, L.P.	Delaware
Williams Field Services Company, LLC	Delaware
Williams Field Services Group, LLC	Delaware
Williams Flexible Generation, LLC	Delaware
Williams Four Corners LLC	Delaware
Williams Gas Processing - Gulf Coast Company, L.P.	Delaware
Williams Gulf Coast Gathering Company, LLC	Delaware
Williams Laurel Mountain, LLC	Delaware
Williams Mobile Bay Producer Services, L.L.C.	Delaware
Williams Ohio Valley Midstream LLC	Texas
Williams Ohio Valley Pipeline LLC	Delaware
Williams Oil Gathering, L.L.C.	Delaware
Williams Olefins Feedstock Pipelines, L.L.C.	Delaware
Williams Olefins, L.L.C.	Delaware
Williams Pacific Connector Gas Operator, LLC	Delaware
Williams Partners Finance Corporation	Delaware
Williams Partners Operating LLC	Delaware
Williams PERK, LLC	Delaware
Williams Pipeline Services LLC	Delaware

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-187664 and 333-179471) of Williams Partners L.P. and in the related prospectuses and in the Registration Statement on Form S-8 (No. 333-128881) pertaining to the Williams Partners GP LLC Long-Term Incentive Plan of our reports dated February 26, 2014, with respect to the consolidated financial statements of Williams Partners L.P., and the effectiveness of internal control over financial reporting of Williams Partners L.P., included in this Annual Report (Form 10‑K) for the year ended December 31, 2013.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 26, 2014

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-128881 of Williams Partners, L.P., on Form S-8, and Registration Statement Nos. 333-179471, 333-187664 of Williams Partners, L.P., on Form S-3 of our report dated February 24, 2014, relating to the financial statements of Gulfstream Natural Gas System, L.L.C., appearing in this Annual Report on Form 10-K of Williams Partners, L.P. for the year ended December 31, 2013.

/s/ Deloitte & Touche LLP

Houston, Texas

February 26, 2014

EX-24

Exhibit 24

WILLIAMS PARTNERS GP LLC

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that each of the undersigned individuals, in their capacity as a director of Williams Partners GP LLC, a Delaware limited liability company (the “General Partner”), as general partner of Williams Partners L.P. (the “Partnership”), does hereby constitute and appoint CRAIG L. RAINEY, WILLIAM H. GAULT, and SARAH C. MILLER their true and lawful attorneys and each of them (with full power to act without the others) their true and lawful attorneys for them and in their name and in their capacity as a director or officer, or both, of the General Partner, as hereinafter set forth below their signature, to sign the Partnership’s Annual Report to the U.S. Securities and Exchange Commission on Form 10-K for the fiscal year ended December 31, 2013, and any and all amendments thereto or all instruments necessary or incidental in connection therewith; and

Each of said attorneys shall have full power of substitution and resubstitution, and said attorneys or any of them or any substitute appointed by any of them hereunder shall have full power and authority to do and perform in the name and on behalf of each of the undersigned, in any and all capacities, every act whatsoever requisite or necessary to be done in the premises, as fully to all intents and purposes as each of the undersigned might or could do in person, the undersigned hereby ratifying and approving the acts of said attorneys or any of them or of any such substitute pursuant hereto. This instrument may be executed in multiple counterparts but all of such counterparts together shall constitute one and the same instrument.

IN WITNESS WHEREOF, the undersigned have executed this instrument, all as of the 26th day of February 2014.

/s/ H. Brent Austin	/s/ Rory L. Miller
H. Brent Austin	Rory L. Miller
Director	Director
/s/ Alice M. Peterson	/s/ James E. Scheel
Alice M. Peterson	James E. Scheel
Director	Director
/s/ Laura A. Sugg
Laura A. Sugg
Director

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Alan S. Armstrong, certify that:

1. I have reviewed this annual report on Form 10-K of Williams Partners L.P.;

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

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

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

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

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

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

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

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

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

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

Date: February 26, 2014

/s/ Alan S. Armstrong

Alan S. Armstrong

Chief Executive Officer of Williams Partners GP

LLC, general partner of Williams Partners L.P.

(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Donald R. Chappel, certify that:

1. I have reviewed this annual report on Form 10-K of Williams Partners L.P.;

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

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

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

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

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

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

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

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

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

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

Date: February 26, 2014

/s/ Donald R. Chappel

Donald R. Chappel

Chief Financial Officer of Williams Partners

GP LLC, general partner of Williams Partners L.P.

(Principal Financial Officer)

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

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

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

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

/s/ Alan S. Armstrong

Alan S. Armstrong

President and Chief Executive Officer

February 26, 2014

/s/ Donald R. Chappel

Donald R. Chappel

Chief Financial Officer

February 26, 2014

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

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

XML

Variable Interest Entities (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended																3 Months Ended	12 Months Ended			12 Months Ended		12 Months Ended		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 Constitution Pipeline Company LLC [Member]	Dec. 31, 2013 Variable Interest Entity, Primary Beneficiary [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2012 Variable Interest Entity, Primary Beneficiary [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2013 Variable Interest Entity, Primary Beneficiary [Member] Property Plant And Equipment [Member]	Dec. 31, 2012 Variable Interest Entity, Primary Beneficiary [Member] Property Plant And Equipment [Member]	Dec. 31, 2013 Variable Interest Entity, Primary Beneficiary [Member] Accounts payable - trade [Member]	Dec. 31, 2012 Variable Interest Entity, Primary Beneficiary [Member] Accounts payable - trade [Member]	Dec. 31, 2013 Variable Interest Entity, Primary Beneficiary [Member] Other accrued liabilities [Member]	Dec. 31, 2012 Variable Interest Entity, Primary Beneficiary [Member] Other accrued liabilities [Member]	Dec. 31, 2013 Variable Interest Entity, Primary Beneficiary [Member] Other Current Liabilities [Member]	Dec. 31, 2012 Variable Interest Entity, Primary Beneficiary [Member] Other Current Liabilities [Member]	Dec. 31, 2013 Variable Interest Entity, Primary Beneficiary [Member] Regulatory liabilities, deferred income and other [Member]	Dec. 31, 2012 Variable Interest Entity, Primary Beneficiary [Member] Regulatory liabilities, deferred income and other [Member]	Jun. 30, 2013 Variable Interest Entity, Primary Beneficiary [Member] Gulfstar One [Member]	Dec. 31, 2013 Variable Interest Entity, Primary Beneficiary [Member] Gulfstar One [Member]	Dec. 31, 2013 Variable Interest Entity, Primary Beneficiary [Member] Gulfstar One [Member] Estimated Remaining Construction Costs For Variable Interest Entity [Member]	Dec. 31, 2013 Variable Interest Entity, Primary Beneficiary [Member] Gunflint [Member] Estimated Remaining Construction Costs For Variable Interest Entity [Member]	Dec. 31, 2013 Variable Interest Entity, Primary Beneficiary [Member] Constitution Pipeline Company LLC [Member]	Dec. 31, 2013 Variable Interest Entity, Primary Beneficiary [Member] Constitution Pipeline Company LLC [Member] Estimated Remaining Construction Costs For Variable Interest Entity [Member]	Dec. 31, 2013 Variable Interest Entity, Not Primary Beneficiary [Member] Laurel Mountain [Member]	Dec. 31, 2013 Variable Interest Entity, Not Primary Beneficiary [Member] Laurel Mountain [Member] Equity Method Investments [Member]	Dec. 31, 2013 Variable Interest Entity, Not Primary Beneficiary [Member] Caiman Energy II LLC [Member]	Jan. 31, 2014 Variable Interest Entity, Not Primary Beneficiary [Member] Caiman Energy II LLC [Member] Subsequent Event [Member]	Dec. 31, 2013 Variable Interest Entity, Not Primary Beneficiary [Member] Caiman Energy II LLC [Member] Equity Method Investments [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity Ownership Percentage				41.00%														51.00%			41.00%		51.00%		47.50%
Estimated remaining construction costs																			$ 325	$ 134		$ 600
Contributions from noncontrolling interests	398	13	0														187
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners																	49.00%
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Variable Interest Entity, Consolidated, Carrying Amount, Assets					76	8	998	556
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities									(120)	(128)	(3)	0	(10)	0	(115)	(109)
Variable Interest Entity, Nonconsolidated, Comparison of Carrying Amount of Assets and Liabilities to Maximum Loss Exposure [Abstract]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets and Liabilities, Net																								481			256
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount																							$ 481		$ 380	$ 500

XML

Partners' Capital (Details Textuals) (USD $)	1 Months Ended							12 Months Ended			1 Months Ended
	Aug. 31, 2013	Mar. 31, 2013	Aug. 31, 2012	Jun. 30, 2012	Apr. 30, 2012	Feb. 29, 2012	Jan. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Aug. 31, 2013 Option on Securities [Member]	Mar. 31, 2013 Option on Securities [Member]	Aug. 31, 2012 Option on Securities [Member]	Apr. 30, 2012 Option on Securities [Member]	Feb. 29, 2012 Option on Securities [Member]	Nov. 30, 2012 Geismar Acquisition [Member]	Feb. 29, 2012 Laser Acquisition [Member]	Apr. 30, 2012 CaimanAcquisition [Member]
Business Acquisition [Line Items]
Partners' Capital Account, Units, Sold in Public Offering	21,500,000		8,500,000		10,000,000		7,000,000				3,225,000	1,687,500	1,275,000	973,368	1,050,000
Partners' Capital Account, Private Placement of Units																		$ 1,000,000,000
Partners' Capital Account, Units, Acquisitions				238,050												42,778,812	7,531,381	11,779,296
Partners' Capital Account, Units, Sold in Private Placement		3,000,000																16,360,133
Partners' Capital Notes [Abstract]
Percentage of units held by the public								36.00%	30.00%
Percentage of outstanding units voting as a single class to remove general partner								66.67%
Days after the end of each quarter to receive cash distributions								45 days
Business Acquisition, Percentage of Voting Interests Acquired				1.00%												83.30%
Net Proceeds from Issuance of Common Limited Partners Units	$ 1,200,000,000	$ 760,000,000	$ 488,000,000		$ 581,000,000	$ 64,000,000	$ 426,000,000	$ 1,962,000,000	$ 2,559,000,000	$ 0
Partners' Capital Account, Units, Sale of Units		14,250,000

XML

Long-Term Debt (Details 1) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Aug. 31, 2012 3.35% Senior Unsecured Notes due 2022 [Member]	Nov. 30, 2013 4.5% Senior Unsecured Notes due 2023 [Member]	Nov. 30, 2013 5.8% Senior Unsecured Notes due 2043 [Member]	Dec. 31, 2013 Transcontinental Gas Pipe Line Company, LLC [Member] 6.4% Senior Unsecured Notes due 2016 [Member]	Dec. 31, 2012 Transcontinental Gas Pipe Line Company, LLC [Member] 6.4% Senior Unsecured Notes due 2016 [Member]	Dec. 31, 2013 Transcontinental Gas Pipe Line Company, LLC [Member] 6.05% Senior Unsecured Notes due 2018 [Member]	Dec. 31, 2012 Transcontinental Gas Pipe Line Company, LLC [Member] 6.05% Senior Unsecured Notes due 2018 [Member]	Dec. 31, 2013 Transcontinental Gas Pipe Line Company, LLC [Member] 7.08% Debentures due 2026 [Member]	Dec. 31, 2012 Transcontinental Gas Pipe Line Company, LLC [Member] 7.08% Debentures due 2026 [Member]	Dec. 31, 2013 Transcontinental Gas Pipe Line Company, LLC [Member] 7.25% Debentures due 2026 [Member]	Dec. 31, 2012 Transcontinental Gas Pipe Line Company, LLC [Member] 7.25% Debentures due 2026 [Member]	Dec. 31, 2013 Transcontinental Gas Pipe Line Company, LLC [Member] 5.4% Senior Unsecured Notes due 2041 [Member]	Dec. 31, 2012 Transcontinental Gas Pipe Line Company, LLC [Member] 5.4% Senior Unsecured Notes due 2041 [Member]	Dec. 31, 2013 Transcontinental Gas Pipe Line Company, LLC [Member] 4.45% Senior Unsecured Notes due 2042 [Member]	Dec. 31, 2012 Transcontinental Gas Pipe Line Company, LLC [Member] 4.45% Senior Unsecured Notes due 2042 [Member]	Jul. 31, 2012 Transcontinental Gas Pipe Line Company, LLC [Member] 4.45% Senior Unsecured Notes due 2042 [Member]	Dec. 31, 2013 Northwest Pipeline LLC [Member] 7% Senior Unsecured Notes due 2016 [Member]	Dec. 31, 2012 Northwest Pipeline LLC [Member] 7% Senior Unsecured Notes due 2016 [Member]	Dec. 31, 2013 Northwest Pipeline LLC [Member] 5.95% Senior Unsecured Notes due 2017 [Member]	Dec. 31, 2012 Northwest Pipeline LLC [Member] 5.95% Senior Unsecured Notes due 2017 [Member]	Dec. 31, 2013 Northwest Pipeline LLC [Member] 6.05% Senior Unsecured Notes due 2018 [Member]	Dec. 31, 2012 Northwest Pipeline LLC [Member] 6.05% Senior Unsecured Notes due 2018 [Member]	Dec. 31, 2013 Northwest Pipeline LLC [Member] 7.125% Debentures due 2025 [Member]	Dec. 31, 2012 Northwest Pipeline LLC [Member] 7.125% Debentures due 2025 [Member]	Dec. 31, 2013 Williams Partners L.P. [Member] 3.8% Senior Unsecured Notes due 2015 [Member]	Dec. 31, 2012 Williams Partners L.P. [Member] 3.8% Senior Unsecured Notes due 2015 [Member]	Dec. 31, 2013 Williams Partners L.P. [Member] 7.25% Senior Unsecured Notes due 2017 [Member]	Dec. 31, 2012 Williams Partners L.P. [Member] 7.25% Senior Unsecured Notes due 2017 [Member]	Dec. 31, 2013 Williams Partners L.P. [Member] 5.25% Senior Unsecured Notes due 2020 [Member]	Dec. 31, 2012 Williams Partners L.P. [Member] 5.25% Senior Unsecured Notes due 2020 [Member]	Dec. 31, 2013 Williams Partners L.P. [Member] 4.125% Senior Unsecured Notes due 2020 [Member]	Dec. 31, 2012 Williams Partners L.P. [Member] 4.125% Senior Unsecured Notes due 2020 [Member]	Dec. 31, 2013 Williams Partners L.P. [Member] 4% Senior Unsecured Notes due 2021 [Member]	Dec. 31, 2012 Williams Partners L.P. [Member] 4% Senior Unsecured Notes due 2021 [Member]	Dec. 31, 2013 Williams Partners L.P. [Member] 3.35% Senior Unsecured Notes due 2022 [Member]	Dec. 31, 2012 Williams Partners L.P. [Member] 3.35% Senior Unsecured Notes due 2022 [Member]	Dec. 31, 2013 Williams Partners L.P. [Member] 4.5% Senior Unsecured Notes due 2023 [Member]	Dec. 31, 2012 Williams Partners L.P. [Member] 4.5% Senior Unsecured Notes due 2023 [Member]	Dec. 31, 2013 Williams Partners L.P. [Member] 6.3% Senior Unsecured Notes due 2040 [Member]	Dec. 31, 2012 Williams Partners L.P. [Member] 6.3% Senior Unsecured Notes due 2040 [Member]	Dec. 31, 2013 Williams Partners L.P. [Member] 5.8% Senior Unsecured Notes due 2043 [Member]	Dec. 31, 2012 Williams Partners L.P. [Member] 5.8% Senior Unsecured Notes due 2043 [Member]
Debt Instrument [Line Items]
Long-term debt						$ 200	$ 200	$ 250	$ 250	$ 8	$ 8	$ 200	$ 200	$ 375	$ 375	$ 400	$ 400		$ 175	$ 175	$ 185	$ 185	$ 250	$ 250	$ 85	$ 85	$ 750	$ 750	$ 600	$ 600	$ 1,500	$ 1,500	$ 600	$ 600	$ 500	$ 500	$ 750	$ 750	$ 600	$ 0	$ 1,250	$ 1,250	$ 400	$ 0
Long-term debt interest rate			3.35%	4.50%	5.80%	6.40%		6.05%		7.08%		7.25%		5.40%		4.45%		4.45%	7.00%		5.95%		6.05%		7.125%		3.80%		7.25%		5.25%		4.125%		4.00%		3.35%		4.50%		6.30%		5.80%
Credit facility loans	0	375
Unamortized debt discount	(21)	(16)
Long-term debt	$ 9,057	$ 8,437

XML

Partners' Capital Incentive Distributions Quarterly Target Amount (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Minimum Quarterly Distribution Per Unit [Member]
Incentive Distribution Target Amount Per Unit [Line Items]
Unitholders	98.00%
General Partner	2.00%
Quarterly Distribution Target Amount	$ 0.35
First Target Distribution [Member] | Maximum [Member]
Incentive Distribution Target Amount Per Unit [Line Items]
Unitholders	98.00%
General Partner	2.00%
Quarterly Distribution Target Amount	$ 0.4025
Second Target Distribution [Member] | Minimum [Member]
Incentive Distribution Target Amount Per Unit [Line Items]
Unitholders	85.00%
General Partner	15.00%
Quarterly Distribution Target Amount	$ 0.4025
Second Target Distribution [Member] | Maximum [Member]
Incentive Distribution Target Amount Per Unit [Line Items]
Quarterly Distribution Target Amount	$ 0.4375
Third Target Distribution [Member] | Minimum [Member]
Incentive Distribution Target Amount Per Unit [Line Items]
Unitholders	75.00%
General Partner	25.00%
Quarterly Distribution Target Amount	$ 0.4375
Third Target Distribution [Member] | Maximum [Member]
Incentive Distribution Target Amount Per Unit [Line Items]
Quarterly Distribution Target Amount	$ 0.5250
Thereafter [Member] | Minimum [Member]
Incentive Distribution Target Amount Per Unit [Line Items]
Unitholders	50.00%
General Partner	50.00%
Quarterly Distribution Target Amount	$ 0.5250

XML

Property, Plant and Equipment (Details PPE) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment
Property, plant, and equipment, at cost	$ 23,774		$ 21,062
Accumulated depreciation	(7,286)		(6,775)
Property, plant, and equipment - net	16,488		14,287
Depreciation and amortization	697		670	618
Nonregulated [Member] | Natural gas gathering and processing facilities [Member]
Property, Plant and Equipment
Property, plant, and equipment, at cost	8,018		7,000
Nonregulated [Member] | Natural gas gathering and processing facilities [Member] | Minimum [Member]
Property, Plant and Equipment
Property, Plant and Equipment, Useful Life	5 years	[1]
Nonregulated [Member] | Natural gas gathering and processing facilities [Member] | Maximum [Member]
Property, Plant and Equipment
Property, Plant and Equipment, Useful Life	40 years	[1]
Nonregulated [Member] | Construction in Progress [Member]
Property, Plant and Equipment
Property, plant, and equipment, at cost	2,658		1,599
Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant and Equipment
Property, plant, and equipment, at cost	899		745
Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member] | Minimum [Member]
Property, Plant and Equipment
Property, Plant and Equipment, Useful Life	3 years	[1]
Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member] | Maximum [Member]
Property, Plant and Equipment
Property, Plant and Equipment, Useful Life	45 years	[1]
Regulated [Member] | Natural gas transmission facilities [Member]
Property, Plant and Equipment
Property, plant, and equipment, at cost	10,633		9,963
Regulated [Member] | Natural gas transmission facilities [Member] | Minimum [Member]
Property, Plant and Equipment
Regulated Property Plant And Equipment Depreciation Rate1	1.20%	[1]
Regulated [Member] | Natural gas transmission facilities [Member] | Maximum [Member]
Property, Plant and Equipment
Regulated Property Plant And Equipment Depreciation Rate1	6.97%	[1]
Regulated [Member] | Construction in Progress [Member]
Property, Plant and Equipment
Property, plant, and equipment, at cost	273		337
Regulated [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant and Equipment
Property, plant, and equipment, at cost	1,293		1,418
Regulated [Member] | Other Capitalized Property Plant and Equipment [Member] | Minimum [Member]
Property, Plant and Equipment
Regulated Property Plant And Equipment Depreciation Rate1	1.35%	[1]
Regulated [Member] | Other Capitalized Property Plant and Equipment [Member] | Maximum [Member]
Property, Plant and Equipment
Regulated Property Plant And Equipment Depreciation Rate1	33.33%	[1]
Regulated [Member] | Excess Of Original Cost Of Regulated Facilities [Member]
Property, Plant and Equipment
Property, plant, and equipment - net	$ 785		$ 825
Period of straight-line amortization	40 years

[1] Estimated useful life and depreciation rates are presented as of December 31, 2013. Depreciation rates for regulated assets are prescribed by the FERC.

XML

Debt, Banking Arrangements, and Leases (Tables)

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Schedule of Long-term Debt Instruments [Table Text Block]

Long-Term Debt

	December 31,
	2013			2012
	(Millions)
Unsecured:
Transco:
6.4% Notes due 2016	$	200		$	200
6.05% Notes due 2018	250			250
7.08% Debentures due 2026	8			8
7.25% Debentures due 2026	200			200
5.4% Notes due 2041	375			375
4.45% Notes due 2042	400			400
Northwest Pipeline:
7% Notes due 2016	175			175
5.95% Notes due 2017	185			185
6.05% Notes due 2018	250			250
7.125% Debentures due 2025	85			85
Williams Partners L.P.:
3.8% Notes due 2015	750			750
7.25% Notes due 2017	600			600
5.25% Notes due 2020	1,500			1,500
4.125% Notes due 2020	600			600
4% Notes due 2021	500			500
3.35% Notes due 2022	750			750
4.5% Notes due 2023	600			—
6.3% Notes due 2040	1,250			1,250
5.8% Notes due 2043	400			—
Credit facility loans	—			375
Unamortized debt discount	(21		)	(16		)
Long-term debt	$	9,057		$	8,437

Schedule of Maturities of Long-term Debt [Table Text Block]

The following table presents aggregate minimum maturities of long-term debt (excluding unamortized discount) for each of the next five years:

	December 31, 2013
	(Millions)
2014	$	—
2015	750
2016	375
2017	785
2018	500

Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]

The future minimum annual rentals under noncancelable operating leases, are payable as follows:

	December 31, 2013
	(Millions)
2014	$	41
2015	35
2016	33
2017	30
2018	29
Thereafter	123
Total	$	291

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Contingent Liabilities (Details) (USD $)	Dec. 31, 2013	Dec. 11, 2013
Contingent Liabilities [Line Items]
Accrued environmental loss liabilities	$ 20,000,000
Commitments For Construction And Acquisition Of Property Plant And Equipment	1,400,000,000
Customer Refund Liability, Current	98,000,000
Notice of Penalty		99,000
Environmental Protection Agency [Member]
Contingent Liabilities [Line Items]
Accrued environmental loss liabilities	13,000,000
Natural gas underground storage facilities [Member]
Contingent Liabilities [Line Items]
Accrued environmental loss liabilities	$ 7,000,000

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Acquisitions Goodwill and Other Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

Schedule of Business Acquisitions, by Acquisition [Table Text Block]

The following table presents the allocation of the acquisition-date fair value of the major classes of the net assets, which are included in the Northeast G&P segment:

	Laser			Caiman
	(Millions)
Assets held-for-sale	$	18		$	—
Other current assets	3			16
Property, plant, and equipment	158			656
Intangible assets:
Customer contracts	316			1,141
Customer relationships	—			250
Other	2			2
Current liabilities	(21		)	(94		)
Noncurrent liabilities	—			(3		)
Identifiable net assets acquired	476			1,968
Goodwill	290			356
	$	766		$	2,324

Schedule of Finite-Lived Intangible Assets [Table Text Block]

The gross carrying amount and accumulated amortization of Other intangible assetsat December 31 are as follows:

	2013					2012
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
	(Millions)
Customer contracts	$	1,493	$	(88	)	$	1,493	$	(38	)
Customer relationships	250		(14		)	250		(6		)
Other	4		(3		)	4		(1		)
Total	$	1,747	$	(105	)	$	1,747	$	(45	)

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Long-Term Debt Issuances and Retirements (Details 3) (USD $) In Millions, unless otherwise specified						1 Months Ended
	Aug. 31, 2012 3.35% Senior Unsecured Notes due 2022 [Member]	Nov. 30, 2013 4.5% Senior Unsecured Notes due 2023 [Member]	Nov. 30, 2013 5.8% Senior Unsecured Notes due 2043 [Member]	Dec. 31, 2013 Transcontinental Gas PipeLine Company, LLC [Member] 4.45% Senior Unsecured Notes due 2042 [Member]	Jul. 31, 2012 Transcontinental Gas PipeLine Company, LLC [Member] 4.45% Senior Unsecured Notes due 2042 [Member]	Jul. 31, 2012 Transcontinental Gas PipeLine Company, LLC [Member] 8.875% Senior Unsecured Notes due 2012 [Member]	Dec. 31, 2013 Williams Partners L. P. [Member] 3.35% Senior Unsecured Notes due 2022 [Member]	Dec. 31, 2013 Williams Partners L. P. [Member] 4.5% Senior Unsecured Notes due 2023 [Member]	Dec. 31, 2013 Williams Partners L. P. [Member] 5.8% Senior Unsecured Notes due 2043 [Member]
Debt Instrument [Line Items]
Repayment of long-term debt						$ 325
Long-term debt face amount	$ 750	$ 600	$ 400		$ 400
Long-term debt interest rate	3.35%	4.50%	5.80%	4.45%	4.45%	8.875%	3.35%	4.50%	5.80%

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Investments (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011	Jun. 30, 2012	May 31, 2011
Investments
Investments	$ 2,187		$ 1,800
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	60
Percentage of Voting Interests Acquired						1.00%
Equity Method Investment, payments to purchase or contributions	439		471		197
Dividends and distributions
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital	154		172		169
Summarized Financial Position of Equity Method Investments
Current assets	412		366
Noncurrent assets	5,956		5,225
Current liabilities	(264)		(247)
Noncurrent liabilities	(1,305)		(1,301)
Summarized Results of Operations of Equity Method Investments
Revenues	1,333		1,213		1,242
Operating income	367		378		535
Net income	291		309		460
Overland Pass Pipeline Company LLC [Member]
Investments
Investments	452		454
Investment, Ownership Percentage	50.00%
Dividends and distributions
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital	27		28		19
Gulfstream Natural Gas System, L.L.C.
Investments
Investments	333		348
Investment, Ownership Percentage	50.00%
Percentage of Voting Interests Acquired						1.00%	24.50%
Dividends and distributions
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital	81		78		60
Discovery Producer Services LLC [Member]
Investments
Investments	527	[1]	350	[1]
Investment, Ownership Percentage	60.00%
Equity Method Investment, payments to purchase or contributions	193		169
Dividends and distributions
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital	12		21		40
Discovery Producer Services LLC [Member] | Proportionate Share Of Amounts Remaining For Capital Projects [Member]
Investments
Proportionate share of amounts remaining for capital projects	244
Laurel Mountain Midstream, LLC
Investments
Investments	481	[1]	444	[1]
Investment, Ownership Percentage	51.00%
Equity Method Investment, payments to purchase or contributions	42		174		137
Laurel Mountain Midstream, LLC | Proportionate Share Of Amounts Remaining For Capital Projects [Member]
Investments
Proportionate share of amounts remaining for capital projects	72
Caiman Energy II LLC [Member]
Investments
Investments	256		67
Investment, Ownership Percentage	47.50%
Equity Method Investment, payments to purchase or contributions	192		69
Caiman Energy II LLC [Member] | Proportionate Share Of Amounts Remaining For Capital Projects [Member]
Investments
Proportionate share of amounts remaining for capital projects	119
Aux Sable Liquid Products LP [Member]
Dividends and distributions
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital	20		28		35
Other [Member]
Investments
Investments	$ 138		$ 137

[1] We account for these investments under the equity method due to the significant participatory rights of our partners such that we do not control or are otherwise not the primary beneficiary of the investments.

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General and Basis of Presentation (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended				1 Months Ended	3 Months Ended	1 Months Ended	5 Months Ended		3 Months Ended	5 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jun. 30, 2012	Nov. 30, 2012 GeismarAcquistion	Mar. 31, 2013 GeismarAcquistion	Nov. 30, 2012 GeismarAcquistion Common units	May 31, 2011 Gulfstream Acquisition	Jun. 30, 2012 Gulfstream Acquisition	Jun. 30, 2012 Gulfstream Acquisition Common units	May 31, 2011 Gulfstream Acquisition Common units	Dec. 31, 2013 Williams	Dec. 31, 2013 Constitution Pipeline Company LLC	Dec. 31, 2013 Geismar	Dec. 31, 2013 Gulfstream Natural Gas System, L.L.C.	Jun. 30, 2012 Gulfstream Natural Gas System, L.L.C.	May 31, 2011 Gulfstream Natural Gas System, L.L.C.	Dec. 31, 2013 Laurel Mountain Midstream, LLC	Dec. 31, 2013 Caiman Energy II, LLC	Dec. 31, 2013 Discovery Producer Services LLC	Dec. 31, 2013 Overland Pass Pipeline Company LLC
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Minimum period of construction for capitalization of interest	3 months
Minimum total project cost for capitalization of interest	$ 1
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage															50.00%			51.00%	47.50%	60.00%	50.00%
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Subsidiary, ownership percentage														83.30%
Parent, limited partner ownership percentage												62.00%
Parent, general partner ownership percentage	2.00%	2.00%	2.00%									2.00%
Variable Interest Entity Ownership Percentage													41.00%
Business Acquisition, Entity Acquired and Reason for Acquisition [Abstract]
Business Acquisition, Percentage of Voting Interests Acquired				1.00%	83.30%			24.50%	1.00%							1.00%	24.50%
Business Acquisition, Cost of Acquired Entity, Purchase Price [Abstract]
Proceeds from Previous Acquisition						25
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares							42,778,812			238,050	632,584
Payments to Acquire Businesses, Net of Cash Acquired	0	2,049	41		25			297
Reduction in the incentive distribution right payment						4
Regulatory Assets [Line Items]
Regulatory Assets, Current	39	39
Regulatory Assets, Noncurrent	315	275
Total regulatory asset	354	314
Regulatory Liability, Current	19	15
Regulatory Liability, Noncurrent	289	250
Total regulatory liabilities	$ 308	$ 265

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Cash Payments For Interest (Net of Amounts Capitalized) (Details 5) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Debt Disclosure [Abstract]
Cash payments for interest (net of amounts capitalized)	$ 366	$ 381	$ 387

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Property, Plant, and Equipment (Details ARO) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 576		$ 570
Liabilities incurred	4		8
Liabilities settled	(30)	[1]	(44)	[1]
Accretion expense	52		43
Revisions	(48)	[2]	(1)	[2]
Ending balance	554		576
Charges Related To Leak At Underground Natural Gas Storage Facility [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liabilities settled	(25)		(31)
Revisions	9		13
Asset Retirement Obligation Costs [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Transco's annual funding commitment for ARO	$ 36

[1] For 2013 and 2012, liabilities settled include $25 million and $31 million, respectively, related to the abandonment of certain of Transco’s natural gas storage caverns that are associated with a leak in 2010.

[2] Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining life of the assets. The 2013 revision primarily reflects increases in the estimated remaining useful life of the assets. The 2012 revision primarily reflects a decrease in removal cost estimates. The 2013 and 2012 revisions also include increases of $9 million and $13 million, respectively, related to changes in the timing and method of abandonment on certain of Transco’s natural gas storage caverns that were associated with a leak in 2010.

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Variable Interest Entities

12 Months Ended

Dec. 31, 2013

Variable Interest Entity Disclosures [Abstract]

Variable Interest Entity Disclosures [Textblock]

Note 3 – Variable Interest Entities

Consolidated VIEs

As of December 31, 2013, we consolidate the following VIEs:

Gulfstar One

During the second quarter of 2013, a third party contributed $187 million to Gulfstar One LLC (Gulfstar One) in exchange for a 49 percent ownership interest in Gulfstar One. This contribution was based on 49 percent of our estimated cumulative net investment at that time. The $187 million was then distributed to us. Following this transaction, we own a 51 percent interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance. We, as construction agent for Gulfstar One, are designing, constructing, and installing a proprietary floating-production system, Gulfstar FPS™, and associated pipelines which will initially provide production handling and gathering services for the Tubular Bells oil and gas discovery in the eastern deepwater Gulf of Mexico. The project is expected to be in service in the third quarter of 2014. We have received certain advance payments from the producer customers and are committed to the producer customers to construct this system. The current estimate of the total remaining construction costs is less than $325 million, which will be funded with capital contributions from us and the other equity partner, proportional to ownership interest. The producer customers will be responsible for the firm price of building the facilities if they do not develop the offshore oil and gas fields to be connected to Gulfstar One. In December 2013, we committed an additional $134 million to Gulfstar One to fund an expansion of the system that will provide production handling, gathering, and processing services for the Gunflint oil and gas discovery in the eastern deepwater Gulf of Mexico. The expansion project is expected to be in service in 2016. The other equity partner has an option to participate in the funding of the expansion project on a proportional basis.

Constitution

We own a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its firm transportation contracts, is a VIE. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Constitution’s economic performance. We, as construction agent for Constitution, are building a pipeline connecting our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. We plan to place the project in service in late 2015 to 2016 and estimate the total remaining construction costs of the project to be less than $600 million, which will be funded with capital contributions from us and the other equity partners, proportional to ownership interest.

The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of these VIEs, which are joint projects in the development and construction phase:

	December 31,
	2013			2012			Classification
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	76		$	8		Cash and cash equivalents
Construction in progress	998			556			Property, plant, and equipment, at cost
Accounts payable	(120		)	(128		)	Accounts payable - trade
Construction retainage	(3		)	—			Other accrued liabilities
Current deferred revenue	(10		)	—			Other accrued liabilities
Noncurrent deferred revenue associated with customer advance payments	(115		)	(109		)	Regulatory liabilities, deferred income, and other

Nonconsolidated VIEs

We have also identified certain interests in VIEs for which we are not the primary beneficiary. These include:

Laurel Mountain

Our 51 percent-owned equity-method investment in Laurel Mountain is considered to be a VIE generally due to contractual provisions that transfer certain risks to customers. As decisions about the activities that most significantly impact the economic performance of this entity require a unanimous vote of all members, we are not the primary beneficiary. Our maximum exposure to loss is limited to the carrying value of this investment, which was $481 million at December 31, 2013.

Caiman II

Our 47.5 percent-owned equity-method investment in Caiman II has been determined to be a VIE because it has insufficient equity to finance activities during the construction stage of the Blue Racer Midstream joint project, which is an expansion to gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale primarily in Ohio and northwest Pennsylvania. We are not the primary beneficiary because we do not have the power to direct the activities of Caiman II that most significantly impact its economic performance. At December 31, 2013, the carrying value of our investment in Caiman II was $256 million, which substantially reflects our contributions to that date. In January 2014, we increased our total commitment for contributions to fund the project from $380 million to $500 million inclusive of contributions made to date which represents our current maximum exposure to loss related to this investment.

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Other Income and Expense (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]
Tax Adjustments, Settlements, and Unusual Provisions	$ 14
Northeast G&P [Member] | Producer claim [Member]
Segment Reporting Information [Line Items]
Settlement in principle of a pending producer claim	25	0	0
Atlantic-Gulf [Member]
Segment Reporting Information [Line Items]
Amortization of regulatory asset associated with asset retirement obligations	30	7	6
Project feasibility costs	4	21	10
Capitalization of project feasibility costs previously expensed	(1)	(19)	(11)
Atlantic-Gulf [Member] | Asset Impairment for Regulatory Action [Member]
Segment Reporting Information [Line Items]
Write-off of the Eminence abandonment regulatory asset not recovered through rates	12	0	0
Insurance recoveries	(16)	0	0
Charges related to leak at storage facility	3	2	15
NGL & Petchem Services [Member] | Geismar Incident [Member]
Segment Reporting Information [Line Items]
Insurance recoveries	(50)
Net insurance recoveries associated with the Geismar Incident	(40)	0	0
Insurance deductible expense	13
Insurable Expenses in Excess of our Deductibles	10
NGL & Petchem Services [Member] | Geismar Incident [Member] | Property Damage And Business Interruption Coverage [Member]
Segment Reporting Information [Line Items]
Maximum insurance recoverable amount	500
NGL & Petchem Services [Member] | Geismar Incident [Member] | Property Damage [Member]
Segment Reporting Information [Line Items]
Insurance deductibles	10
NGL & Petchem Services [Member] | Geismar Incident [Member] | Business Interruption [Member]
Segment Reporting Information [Line Items]
Duration of waiting period before business interruption coverage begins	60 days
NGL & Petchem Services [Member] | Geismar Incident [Member] | General Liability Coverage [Member]
Segment Reporting Information [Line Items]
Maximum insurance recoverable amount	610
Insurance deductibles	2
NGL & Petchem Services [Member] | Geismar Incident [Member] | Workers Compensation Coverage [Member]
Segment Reporting Information [Line Items]
Insurance deductibles	$ 1

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Investments (Tables)

12 Months Ended

Dec. 31, 2013

Investments [Abstract]

Investments [Table Text Block]

Investments accounted for using the equity method consist of:

	December 31,
	2013		2012
	(Millions)
OPPL - 50%	$	452	$	454
Gulfstream - 50%	333		348
Discovery - 60% (1)	527		350
Laurel Mountain - 51% (1)	481		444
Caiman II - 47.5%	256		67
Other	138		137
	$	2,187	$	1,800

____________

(1) We account for these investments under the equity method due to the significant participatory rights of our partners such that we do not control or are otherwise not the primary beneficiary of the investments.

Dividends and distributions [Table Text Block]

	Years Ended December 31,
	2013		2012		2011
	(Millions)
Gulfstream	$	81	$	78	$	60
Discovery	12		21		40
Aux Sable Liquid Products L.P.	20		28		35
OPPL	27		28		19

Summarized Financial Position and Results of Operations of Equity Method Investments [Table Text Block]

Summarized Financial Position and Results of Operations of All Equity-Method Investments

	December 31,
	2013			2012
	(Millions)
Assets (liabilities):
Current assets	$	412		$	366
Noncurrent assets	5,956			5,225
Current liabilities	(264		)	(247		)
Noncurrent liabilities	(1,305		)	(1,301		)

	Years Ended December 31,
	2013		2012		2011
	(Millions)
Gross revenue	$	1,333	$	1,213	$	1,242
Operating income	367		378		535
Net income	291		309		460

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2013

Related Party Transactions [Abstract]

Schedule of Related Party Transactions [Table Text Block]

Summary of the related party transactions discussed in all sections above. 

	Years Ended December 31,
	2013		2012		2011
	(Millions)
Revenues	$	—	$	—	$	310
Product costs	270		300		802
Operating and maintenance expenses:
Employee costs	328		269		236
Other	—		—		305
Selling, general, and administrative expenses:
Employee direct costs	256		287		232
Employee allocated costs	160		184		118

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Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Additional disclosures:
Fair Value, Assets, Level 1 to Level 2 Transfers, Amount	$ 0	$ 0
Fair Value, Assets, Level 2 to Level 1 Transfers, Amount	0	0
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables by product or service	523	562
Customer Concentration Risk [Member] | Sales Revenue, Net [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Consolidated revenue, major customer, percentage	10.00%	14.00%	17.00%
Customer accounted for ten percent of consolidated revenues	1	1	1
NGLs, natural gas, and related products and services [member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables by product or service	327	393
Transportation of natural gas and related products [member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables by product or service	193	169
Other Receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables by product or service	3	0
Carrying Amount [Member]
Additional disclosures:
Notes receivable and other	7	11
Long-term debt	(9,057)	(8,437)
Fair Value [Member]
Additional disclosures:
Notes receivable and other	7	10
Long-term debt	(9,581)	(9,624)
Level 1 [Member]
Additional disclosures:
Notes receivable and other	1	2
Long-term debt	0	0
Level 2 [Member]
Additional disclosures:
Notes receivable and other	6	8
Long-term debt	(9,581)	(9,624)
Level 3 [Member]
Additional disclosures:
Notes receivable and other	0	0
Long-term debt	0	0
Fair Value, Measurements, Recurring [Member] | Carrying Amount [Member]
Measured on a recurring basis:
ARO Trust investments	33	18
Fair Value, Measurements, Recurring [Member] | Carrying Amount [Member] | Not Designated as Hedging Instrument [Member]
Measured on a recurring basis:
Energy derivative assets	3	5
Energy derivative liabilities	(3)	(1)
Fair Value, Measurements, Recurring [Member] | Fair Value [Member]
Measured on a recurring basis:
ARO Trust investments	33	18
Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Not Designated as Hedging Instrument [Member]
Measured on a recurring basis:
Energy derivative assets	3	5
Energy derivative liabilities	(3)	(1)
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Measured on a recurring basis:
ARO Trust investments	33	18
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Not Designated as Hedging Instrument [Member]
Measured on a recurring basis:
Energy derivative assets	0	0
Energy derivative liabilities	0	0
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Measured on a recurring basis:
ARO Trust investments	0	0
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Not Designated as Hedging Instrument [Member]
Measured on a recurring basis:
Energy derivative assets	0	0
Energy derivative liabilities	(1)	0
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Measured on a recurring basis:
ARO Trust investments	0	0
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Not Designated as Hedging Instrument [Member]
Measured on a recurring basis:
Energy derivative assets	3	5
Energy derivative liabilities	$ (2)	$ (1)

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Benefit Plans (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Pension Expense	$ 44	$ 41	$ 32
Defined Contribution Plan, Cost Recognized	15	18	16
Allocated Share-based Compensation Expense	11	12	10
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation	1,400	1,500
Defined Benefit Plan, Funded Status of Plan	(143)	(478)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation	213	331
Defined Benefit Plan, Funded Status of Plan	(12)	(156)
Defined Benefit Plan, Net Periodic Benefit Cost	$ (4)	$ 4	$ (2)

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Other Income and Expense (Tables)

12 Months Ended

Dec. 31, 2013

Other Income and Expenses [Abstract]

Schedule of Other Operating Cost and Expense, by Component [Table Text Block]

The following table presents significant gains or losses reflected in Other (income) expense – netwithin Costs and expenses:

	Years Ended December 31,
	2013			2012			2011
	(Millions)
Northeast G&P
Settlement in principle of a producer claim	$	25		$	—		$	—
Atlantic-Gulf
Amortization of regulatory asset associated with asset retirement obligations	30			7			6
Write-off of the Eminence abandonment regulatory asset not recoverable through rates	12			—			—
Insurance recoveries associated with the Eminence abandonment	(16		)	—			—
Project feasibility costs	4			21			10
Capitalization of project feasibility costs previously expensed	(1		)	(19		)	(11		)
NGL & Petchem Services
Net insurance recoveries associated with the Geismar Incident	(40		)	—			—

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Inventories (Tables)

12 Months Ended

Dec. 31, 2013

Inventory Disclosure [Abstract]

Inventories

	December 31,
	2013		2012
	(Millions)
Natural gas liquids, olefins, and natural gas in underground storage	$	112	$	96
Materials, supplies, and other	81		77
	$	193	$	173

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Acquisitions Goodwill and Other Intangible Assets

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

Acquisitions Goodwill and Other Intangible Assets [Text Block]

Note 2 – Acquisitions, Goodwill, and Other Intangible Assets

Business Combinations

In addition to the entities and assets acquired in the common control transactions described in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies, we note the following additional acquisitions.

On February 17, 2012, we completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC, in exchange for $325 million in cash, net of cash acquired in the transaction, and 7,531,381 of our common units valued at $441 million (Laser Acquisition). The fair value of the common units issued as part of the consideration paid was determined on the basis of the closing market price of our common units on the acquisition date, adjusted to reflect certain time-based restrictions on resale. The acquired entities primarily own the Laser Gathering System, which is comprised of a natural gas pipeline and associated gathering facilities in the Marcellus Shale in Susquehanna County, Pennsylvania, as well as gathering lines in southern New York.

On April 27, 2012, we completed the acquisition of 100 percent of the ownership interests in Caiman Eastern Midstream, LLC, from Caiman Energy, LLC in exchange for $1.72 billion in cash and 11,779,296 of our common units valued at $603 million (Caiman Acquisition). The fair value of the common units issued as part of the consideration paid was determined on the basis of the closing market price of our common units on the acquisition date, adjusted to reflect certain time-based restrictions on resale. The acquired entity operates a gathering and processing business in northern West Virginia, southwestern Pennsylvania, and eastern Ohio. Acquisition transaction costs of $16 million were incurred during 2012 by Northeast G&P related to the Caiman Acquisition and are reported in Selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income.

The following table presents the allocation of the acquisition-date fair value of the major classes of the net assets, which are included in the Northeast G&P segment:

	Laser			Caiman
	(Millions)
Assets held-for-sale	$	18		$	—
Other current assets	3			16
Property, plant, and equipment	158			656
Intangible assets:
Customer contracts	316			1,141
Customer relationships	—			250
Other	2			2
Current liabilities	(21		)	(94		)
Noncurrent liabilities	—			(3		)
Identifiable net assets acquired	476			1,968
Goodwill	290			356
	$	766		$	2,324

Revenues and earnings related to the Laser and Caiman Acquisitions included within the Consolidated Statement of Comprehensive Income in 2012 are not material. Supplemental pro forma revenue and earnings for the pre-acquisition periods reflecting these acquisitions as if they had occurred as of January 1, 2011, are not materially different from the information presented in our accompanying Consolidated Statement of Comprehensive Income (since the historical operations of these acquisitions were insignificant relative to our historical operations) and are, therefore, not presented.

Goodwill and Other Intangible Assets

Goodwill

The Laser and Caiman Acquisitions were accounted for as business combinations which, among other things, require assets acquired and liabilities assumed to be measured at their acquisition-date fair values. The excess of cost over those fair values was recorded as goodwill and allocated to our Northeast G&P segment (the reporting unit). Goodwill recognized in the acquisitions relates primarily to enhancing our strategic platform for expansion in the Marcellus and Utica shale plays in the Appalachian basin area. Our annual goodwill impairment review did not result in a goodwill impairment in 2013.

Other Intangible Assets

Other intangible assets primarily relate to gas gathering, processing and fractionation contracts and relationships with customers recognized in the Laser and Caiman Acquisitions. The basis for determining the value of these intangible assets was estimated future net cash flows to be derived from acquired customer contracts and relationships, which were offset with appropriate charges for the use of contributory assets and discounted using a risk-adjusted discount rate. The intangible assets are being amortized on a straight-line basis over an initial period of 30 years which represents a portion of the term over which the customer contracts and relationships are expected to contribute to our cash flows.

The gross carrying amount and accumulated amortization of Other intangible assetsat December 31 are as follows:

	2013					2012
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
	(Millions)
Customer contracts	$	1,493	$	(88	)	$	1,493	$	(38	)
Customer relationships	250		(14		)	250		(6		)
Other	4		(3		)	4		(1		)
Total	$	1,747	$	(105	)	$	1,747	$	(45	)

We expense costs incurred to renew or extend the terms of our gas gathering, processing and fractionation contracts with customers. Based on the estimated future revenues during the contract periods (as estimated at the time of the respective acquisition), the weighted-average periods prior to the next renewal or extension of the customer contracts associated with the Laser and Caiman Acquisitions were approximately 9 years and 18 years, respectively. Although a significant portion of the expected future cash flows associated with these contracts are dependent on our ability to renew or extend the arrangements beyond the initial contract periods, these expected future cash flows are significantly influenced by the scope and pace of our producer customers’ drilling programs. Once producer customers’ wells are connected to our gathering infrastructure, their likelihood of switching to another provider before the wells are abandoned is reduced due to the significant capital investments required.

The aggregate amortization expense related to Other intangible assets was $60 million, $43 million and $2 million in 2013, 2012 and 2011, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $60 million.

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Propertyl, Plant, and Equipment [Table Text Block]

	Estimated	Depreciation
	Useful Life (1)	Rates (1)	December 31,
	(Years)	(%)	2013			2012
			(Millions)
Nonregulated:
Natural gas gathering and processing facilities	5 - 40		$	8,018		$	7,000
Construction in progress	Not applicable		2,658			1,599
Other	3 - 45		899			745
Regulated:
Natural gas transmission facilities		1.2 - 6.97	10,633			9,963
Construction in progress		Not applicable	273			337
Other		1.35 - 33.33	1,293			1,418
Total property, plant, and equipment, at cost			$	23,774		$	21,062
Accumulated depreciation and amortization			(7,286		)	(6,775		)
Property, plant, and equipment — net			$	16,488		$	14,287

______________________

(1) Estimated useful life and depreciation rates are presented as of December 31, 2013. Depreciation rates for regulated assets are prescribed by the FERC.

Asset Retirement Obligation [Table Text Block]

	December 31,
	2013			2012
	(Millions)
Beginning balance	$	576		$	570
Liabilities incurred	4			8
Liabilities settled (1)	(30		)	(44		)
Accretion expense	52			43
Revisions (2)	(48		)	(1		)
Ending balance	$	554		$	576

______________

(1) For 2013 and 2012, liabilities settled include $25 million and $31 million, respectively, related to the abandonment of certain of Transco’s natural gas storage caverns that are associated with a leak in 2010.

(2) Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining life of the assets. The 2013 revision primarily reflects increases in the estimated remaining useful life of the assets. The 2012 revision primarily reflects a decrease in removal cost estimates. The 2013 and 2012 revisions also include increases of $9 million and $13 million, respectively, related to changes in the timing and method of abandonment on certain of Transco’s natural gas storage caverns that were associated with a leak in 2010.

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Allocation of Net Income and Distributions (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended												12 Months Ended						21 Months Ended	1 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011		Feb. 13, 2014	Feb. 28, 2014 Subsequent Event [Member]	Feb. 13, 2014 Subsequent Event [Member]
Allocation of net income to general partner:
Net income													$ 1,070		$ 1,232		$ 1,511
Net income applicable to pre-partnership operations allocated to general partner													0		(185)		(133)
Net income applicable to noncontrolling interests													(3)		0		0
Net costs charged directly to general partner													1		1		(2)
Income subject to 2% allocation of general partner interest													1,068		1,048		1,376
General partner's share of net income													2.00%		2.00%		2.00%			2.00%
General partner's allocated share of net income before items directly allocable to general partner interest													21		21		28
Priority allocations, including incentive distributions, paid to general partner													387	[1]	355	[1]	260	[1]
Net costs charged directly to general partner													(1)		(1)		2
Pre-partnership net income allocated to general partner interest													0		185		133
Net income allocated to general partner													407		560		423
Net income													1,070		1,232		1,511
Net income allocated to general partner													407		560		423
Net income applicable to noncontrolling interests													3		0		0
Net income allocated to common limited partners													660		672		1,088
Distributions Made to Members or Limited Partners [Abstract]
Payment Date	Nov. 12, 2013	Aug. 09, 2013	May 10, 2013	Feb. 08, 2013	Nov. 09, 2012	Aug. 10, 2012	May 11, 2012	Feb. 10, 2012	Nov. 11, 2011	Aug. 12, 2011	May 13, 2011	Feb. 11, 2011									Feb. 13, 2014	[2]
Per Unit Distribution (Paid)	$ 0.8775	$ 0.8625	$ 0.8475	$ 0.8275	$ 0.8075	$ 0.7925	$ 0.7775	$ 0.7625	$ 0.7475	$ 0.7325	$ 0.7175	$ 0.7025									$ 0.8925	[2]
Common Units Cash Distribution	385	357	351	329	287	274	268	227	217	213	208	204									392	[2]
2% General Partner Cash Distribution	11	11	10	9	8	7	8	6	6	6	5	5									11	[2]
Priority allocations, including incentive distributions, paid to general partner	46	121	112	104	99	92	86	78	71	67	63	59									153	[2]
Total Cash Distributions	442	489	473	442	394	373	362	311	294	286	276	268	1,846		1,440		1,124				556	[2]
Reduction in incentive distribution rights payment													$ 90						$ 147

[1] The net income allocated to the general partner’s capital account reflects IDRs paid during the current reporting period. In the calculation of basic and diluted net income per common unit, the net income allocated to the general partner includes IDRs pertaining to the current reporting period but paid in the subsequent period

[2] On February 13, 2014, we paid a cash distribution of $0.8925 per unit on our outstanding common units to unitholders of record at the close of business on February 6, 2014

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Leases-Lessee (Details 6) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Future minimum annual rentals under noncancelable operating leases
2014	$ 41
2015	35
2016	33
2017	30
2018	29
Thereafter	123
Total	291
Operating Leased Assets [Line Items]
Total rent expense	50	45	37
Jicarilla Apache Nation [Member]
Operating Leased Assets [Line Items]
Future minimum annual rental payment of a certain significant lease	$ 8

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Consolidated Statement of Comprehensive Income (USD $) In Millions, except Share data in Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues:
Service revenues	$ 2,910	$ 2,709	$ 2,517
Product sales	3,775	4,611	5,197
Total revenues	6,685	7,320	7,714
Costs and expenses:
Product costs	3,048	3,526	3,951
Operating and maintenance expenses	1,029	987	948
Depreciation and amortization expenses	758	714	621
Selling, general, and administrative expenses	493	553	406
Other (income) expense - net	15	23	13
Total costs and expenses	5,343	5,803	5,939
Operating income	1,342	1,517	1,775
Equity earnings (losses)	104	111	142
Interest incurred	(456)	(441)	(426)
Interest capitalized	69	36	11
Other income (expense) - net	11	9	9
Net income	1,070	1,232	1,511
Less: Net income attributable to noncontrolling interests	3	0	0
Net Income attributable to controlling interests	1,067	1,232	1,511
Allocation of net income for calculation of earnings per common unit:
Net income attributable to controlling interests	1,067	1,232	1,511
Allocation of net income to general partner	456	587	441
Allocation of net income to common units	611	645	1,070
Basic net income per common unit	$ 1.45	$ 1.89	$ 3.69
Diluted net income per common unit	$ 1.45	$ 1.89	$ 3.69
Basic weighted average number of common units outstanding (thousands)	420,916	341,981	290,255
Diluted weighted average number of common units outstanding (thousands)	420,916	341,981	290,255
Cash distributions per common unit	$ 3.480	$ 3.205	$ 2.96
Other Comprehensive Income (Loss):
Net unrealized gain (loss) from derivative instruments	1	30	(17)
Reclassifications into earnings of net derivative instruments (gain) loss	0	(30)	18
Other comprehensive income (loss)	1	0	1
Comprehensive income	1,071	1,232	1,512
Less: Comprehensive income attributable to noncontrolling interests	3	0	0
Comprehensive income attributable to controlling interests	$ 1,068	$ 1,232	$ 1,512

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Inventories (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Inventory Net [Abstract]
Natural gas liquids, olefins, and natural gas in underground storage	$ 112	$ 96
Other Inventory, Net of Reserves	81	77
Total Inventories	$ 193	$ 173

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Consolidated Statement of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
OPERATING ACTIVITIES:
Net income	$ 1,070	$ 1,232	$ 1,511
Adjustments to reconcile to net cash provided by operations:
Depreciation and amortization	758	714	621
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable	39	19	(92)
Inventories	(19)	7	56
Other current assets and deferred charges	25	25	(7)
Accounts payable	(40)	(89)	138
Accrued liabilities	171	(8)	60
Affiliate accounts receivable and payable - net	(25)	49	(97)
Other, including changes in noncurrent assets and liabilities	82	69	100
Net cash provided by operating activities	2,061	2,018	2,290
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper - net	224	0	0
Proceeds from long-term debt	2,699	2,639	1,596
Payments of long-term debt	(2,080)	(1,440)	(1,184)
Proceeds from sales of common units	1,962	2,559	0
General partner contributions	53	93	31
Distributions to limited partners and general partner	(1,846)	(1,440)	(1,124)
Contributions from noncontrolling interests	398	13	0
Excess of purchase price over contributed basis of business and investment	0	0	(123)
Distributions to The Williams Companies, Inc. - net	0	(17)	(99)
Other - net	(36)	5	(15)
Net cash provided (used) by financing activities	1,374	2,412	(918)
Property, plant and equipment:
Capital expenditures	(2,933)	(2,112)	(1,005)
Net proceeds from dispositions	3	22	5
Purchases of businesses	0	(2,049)	(41)
Purchase of businesses and investments from affiliates	25	(25)	(174)
Purchases of and contributions to equity method investments	(439)	(471)	(197)
Purchase of ARO trust investments	(58)	(34)	(41)
Proceeds from sale of ARO trust investments	46	43	56
Other - net	3	53	1
Net cash used by investing activities	(3,353)	(4,573)	(1,396)
Increase (decrease) in cash and cash equivalents	82	(143)	(24)
Cash and cash equivalents at beginning of year	20	163	187
Cash and cash equivalents at end of year	$ 102	$ 20	$ 163

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Subsequent Event (Details) (USD $)	1 Months Ended	12 Months Ended			1 Months Ended
	Jun. 30, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Feb. 28, 2014 Subsequent Event [Member]	Feb. 25, 2014 Subsequent Event [Member]
Subsequent Event [Line Items]
Commercial Paper		$ 225,000,000	$ 0			$ 900,000,000
Business Combination, Consideration Transferred					1,200,000,000
Payments to Acquire Businesses, Gross					25,000,000
Partners' Capital Account, Units, Acquisitions	238,050				25,577,521
Parent, general partner ownership percentage		2.00%	2.00%	2.00%	2.00%
Dollar amount of potential future sales of Class D units to our general partner					$ 200,000,000

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

							Fair Value Measurements Using
	Carrying  Amount			Fair Value			Quoted Prices In Active  Markets for  Identical Assets (Level 1)		Significant  Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at December 31, 2013:
Measured on a recurring basis:
ARO Trust investments	$	33		$	33		$	33	$	—		$	—
Energy derivatives assets not designated as hedging instruments	3			3			—		—			3
Energy derivatives liabilities not designated as hedging instruments	(3		)	(3		)	—		(1		)	(2		)
Additional disclosures:
Notes receivable and other	7			7			1		6			—
Long-term debt	(9,057		)	(9,581		)	—		(9,581		)	—
Assets (liabilities) at December 31, 2012:
Measured on a recurring basis:
ARO Trust investments	$	18		$	18		$	18	$	—		$	—
Energy derivatives assets not designated as hedging instruments	5			5			—		—			5
Energy derivatives liabilities not designated as hedging instruments	(1		)	(1		)	—		—			(1		)
Additional disclosures:
Notes receivable and other	11			10			2		8			—
Long-term debt	(8,437		)	(9,624		)	—		(9,624		)	—

Concentration of receivables, net of allowances, by product or service

The following table summarizes concentration of receivables, net of allowances.

	December 31,
	2013		2012
	(Millions)
NGLs, natural gas, and related products and services	$	327	$	393
Transportation of natural gas and related products	193		169
Other	3		—
Total	$	523	$	562

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Subsequent Event (Notes)

12 Months Ended

Dec. 31, 2013

Subsequent Events [Abstract]

Subsequent Events [Text Block]

Note 16 – Subsequent Events

Commercial Paper Outstanding Balance

As of February 25, 2014, $900 million is outstanding under our commercial paper program.

Canada Dropdown

In February 2014, we agreed to acquire certain Canadian operations from Williams for total consideration valued at approximately $1.2 billion. The transaction is expected to close in February 2014. We expect to fund the purchase with $25 million of cash, the issuance of 25,577,521 Class D limited-partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. In lieu of cash distributions, the Class D units will receive quarterly distributions of additional paid-in-kind Class D units, all of which will be convertible to common units at a future date. The acquired Canadian operations will be included in our NGL & Petchem Services segment. The agreement also provides that we can issue additional Class D units to Williams on a quarterly basis through 2015 for up to a total of $200 million in cash for the purpose of funding certain facility expansions.

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Segment Disclosures (Tables)

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Reconciliation of segment revenues and segment profit (loss) [Table Text Block]

The following table reflects the reconciliation of Segment revenues and Segment profit (loss) to Total revenues and Operating income as reported in the Consolidated Statement of Comprehensive Income. It also presents other financial information related to long-lived assets.

	Northeast G&P			Atlantic- Gulf		West		NGL & Petchem Services		Eliminations			Total
	(Millions)
2013
Segment revenues:
Service revenues
External	$	335		$	1,414	$	1,053	$	108	$	—		$	2,910
Internal	—			10		1		—		(11		)	—
Total service revenues	335			1,424		1,054		108		(11		)	2,910
Product sales
External	166			830		64		2,715		—			3,775
Internal	—			95		708		294		(1,097		)	—
Total product sales	166			925		772		3,009		(1,097		)	3,775
Total revenues	$	501		$	2,349	$	1,826	$	3,117	$	(1,108	)	$	6,685
Segment profit (loss)	$	(24	)	$	614	$	741	$	275				$	1,606
Less equity earnings (losses)	(7		)	72		—		39					104
Segment operating income (loss)	$	(17	)	$	542	$	741	$	236				1,502
General corporate expenses													(160		)
Operating income													$	1,342
Other financial information:
Depreciation and amortization	$	132		$	363	$	236	$	27	$	—		$	758
2012
Segment revenues:
Service revenues
External	$	168		$	1,371	$	1,067	$	103	$	—		$	2,709
Internal	—			12		5		—		(17		)	—
Total service revenues	168			1,383		1,072		103		(17		)	2,709
Product sales
External	2			709		40		3,860		—			4,611
Internal	—			363		1,089		258		(1,710		)	—
Total product sales	2			1,072		1,129		4,118		(1,710		)	4,611
Total revenues	$	170		$	2,455	$	2,201	$	4,221	$	(1,727	)	$	7,320
Segment profit (loss)	$	(37	)	$	574	$	980	$	295				$	1,812
Less equity earnings (losses)	(23		)	92		—		42					111
Segment operating income (loss)	$	(14	)	$	482	$	980	$	253				1,701
General corporate expenses													(184		)
Operating income													$	1,517
Other financial information:
Depreciation and amortization	$	76		$	381	$	234	$	23	$	—		$	714

	Northeast G&P			Atlantic- Gulf		West		NGL & Petchem Services		Eliminations			Total
	(Millions)
2011
Segment revenues:
Service revenues
External	$	49		$	1,332	$	1,053	$	83	$	—		$	2,517
Internal	—			—		4		—		(4		)	—
Total service revenues	49			1,332		1,057		83		(4		)	2,517
Product sales
External	—			606		11		4,580		—			5,197
Internal	—			531		1,622		56		(2,209		)	—
Total product sales	—			1,137		1,633		4,636		(2,209		)	5,197
Total revenues	$	49		$	2,469	$	2,690	$	4,719	$	(2,213	)	$	7,714
Segment profit (loss)	$	23		$	585	$	1,181	$	246				$	2,035
Less equity earnings (losses)	(1		)	90		—		53					142
Segment operating income (loss)	$	24		$	495	$	1,181	$	193				1,893
General corporate expenses													(118		)
Operating income													$	1,775
Other financial information:
Depreciation and amortization	$	5		$	365	$	236	$	15	$	—		$	621

Total assets and investments by reporting segment [Table Text Block]

The following table reflects Total assets, Investments, and Additions to long-lived assets by reportable segment:  

	Total Assets at December 31,						Investments at December 31,				Additions to Long-Lived Assets at December 31,
	2013			2012			2013		2012		2013		2012		2011
	(Millions)
Northeast G&P (1)	$	6,229		$	4,745		$	737	$	511	$	1,376	$	3,909	$	204
Atlantic-Gulf	10,007			8,734			930		774		1,072		1,002		650
West	4,767			4,688			—		—		210		360		301
NGL & Petchem Services	1,822			1,500			520		515		392		282		103
Other corporate assets	147			409			—		—		5		16		25
Eliminations (2)	(614		)	(367		)	—		—		—		—		—
Total	$	22,358		$	19,709		$	2,187	$	1,800	$	3,055	$	5,569	$	1,283

(1) 2012 Additions to long-lived assets includes the Caiman and Laser Acquisitions. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)

(2) Eliminations primarily relate to the intercompany accounts receivable generated by our cash management program.

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General, Description of Business, Basis of Presentation and Summary of Significant Accounting Policies General, Description of Business, Basis of Presentation and Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Regulatory Assets and Liabilities [Text Block]

Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2013 and 2012 are as follows:

	December 31,
	2013		2012
	(Millions)
Current assets reported within Other current assets	$	39	$	39
Noncurrent assets reported within Regulatory assets, deferred charges, and other	315		275
Total regulated assets	$	354	$	314
Current liabilities reported within Other accrued liabilities	$	19	$	15
Noncurrent liabilities reported within Regulatory liabilities, deferred income and other	289		250
Total regulated liabilities	$	308	$	265

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General and Basis of Presentation

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization, Basis of Presentation, and Description of Business

Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies

General

We are a publicly traded Delaware limited partnership. Williams Partners GP LLC, a Delaware limited liability company wholly owned by The Williams Companies, Inc. (Williams), serves as our general partner. As of December 31, 2013, Williams owns an approximate 62 percent limited partner interest, a 2 percent general partner interest and incentive distribution rights (IDRs) in us. All of our activities are conducted through Williams Partners Operating LLC (OLLC), an operating limited liability company (wholly owned by us). Our operations are located in the United States.

Description of Business

Our operations are located in North America and are organized into the following reportable segments: Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services.

Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus and Utica shale regions, as well as a 51 percent equity investment in Laurel Mountain Midstream, LLC (Laurel Mountain) and a 47.5 percent equity investment in Caiman Energy II, LLC (Caiman II).

Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transcontinental Gas Pipe Line Company, LLC (Transco), and significant natural gas gathering and processing and crude oil production handling and transportation in the Gulf Coast region, as well as a 50 percent equity investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), and a 60 percent equity investment in Discovery Producer Services LLC (Discovery).

West is comprised of our gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming and our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline).

NGL & Petchem Services is comprised of our natural gas liquid (NGL) and natural gas marketing business, an NGL fractionator and storage facilities near Conway, Kansas, a 50 percent equity investment in Overland Pass Pipeline, LLC (OPPL), and an 83.3 percent undivided interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf Coast region.

Basis of Presentation

In May 2011, we acquired a 24.5 percent equity interest in Gulfstream from a subsidiary of Williams in exchange for aggregate consideration of $297 million of cash, 632,584 of our limited partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. In June 2012, we acquired an additional 1 percent interest in Gulfstream from a subsidiary of Williams in exchange for 238,050 of our limited partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. The equity interests acquired in these transactions were affiliates of Williams at the time of the acquisitions; therefore, each was accounted for as a common control transaction. The equity interests acquired were combined with our investments as of the date of transfer such that our historical results of operations for periods prior to the acquisitions were unchanged. These transactions are collectively referred to as the Gulfstream Acquisitions and the investment is reported in our Atlantic-Gulf segment.

In November 2012, we acquired an entity that holds an 83.3 percent undivided interest in an olefins-production facility in Geismar, Louisiana, and associated assets from Williams for total consideration of 42,778,812 of our limited partner units, $25 million in cash, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest (Geismar Acquisition). The acquired entity was an affiliate of Williams at the time of the acquisition; therefore, the acquisition was accounted for as a common control transaction, whereby the acquired assets and liabilities were combined with ours at their historical amounts. This common control acquisition was treated similar to a pooling of interests whereby the historical results of operations were combined with ours for all periods presented. In first-quarter 2013, we received $25 million in cash from Williams and Williams waived $4 million in payments on its IDRs with respect to our May 2013 distribution related to a working capital adjustment associated with the acquisition.

Summary of Significant Accounting Policies

Principles of consolidation

The consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of ventures in which we own an undivided interest. Management judgment is required to evaluate whether we control an entity. Key areas of that evaluation include:

• Determining whether an entity is a variable interest entity (VIE);

• Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that we and our related parties have over those activities through our variable interests;

• Identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether we are a VIE’s primary beneficiary;

• Evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant decisions that would be expected to be made in the ordinary course of business such that we do not have the power to control such entities.

We apply the equity method of accounting to investments in entities over which we exercise significant influence but do not control.

Common control transactions

Entities and assets acquired from Williams and its affiliates are accounted for as common control transactions whereby the net assets acquired are combined with ours at their historical amounts. If any cash consideration transferred in such a transaction exceeds the carrying value of the net assets acquired, the excess is treated as a capital transaction with our general partner, similar to a dividend. If the carrying value of the net assets acquired exceeds any cash consideration transferred and limited partner units are also issued as consideration, then the limited partner units are recorded at an amount equal to the excess of the carrying value of the net assets acquired over any cash consideration transferred. To the extent that such transactions require prior periods to be recast, historical net equity amounts prior to the transaction date are reflected in the account of the general partner. Cash consideration up to the carrying value of net assets acquired is presented as an investing activity in our Consolidated Statement of Cash Flows. Cash consideration in excess of the carrying value of net assets acquired is presented as a financing activity in our Consolidated Statement of Cash Flows.

Use of estimates

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

Significant estimates and assumptions include:

• Impairment assessments of investments, property, plant, and equipment, goodwill and other identifiable intangible assets;

• Litigation-related contingencies;

• Environmental remediation obligations;

• Asset retirement obligations;

• Acquisition related purchase price allocations.

These estimates are discussed further throughout these notes.

Regulatory accounting

Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC). Their rates, which are established by the FERC, are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, our management has determined that it is appropriate to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are established. Accounting for these operations that are regulated can differ from the accounting requirements for non regulated operations. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, and postretirement benefits. Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2013 and 2012 are as follows:

	December 31,
	2013		2012
	(Millions)
Current assets reported within Other current assets	$	39	$	39
Noncurrent assets reported within Regulatory assets, deferred charges, and other	315		275
Total regulated assets	$	354	$	314
Current liabilities reported within Other accrued liabilities	$	19	$	15
Noncurrent liabilities reported within Regulatory liabilities, deferred income and other	289		250
Total regulated liabilities	$	308	$	265

Cash and cash equivalents

Cash and cash equivalents in the Consolidated Balance Sheet includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.

Accounts receivable

Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted.

Inventory valuation

All Inventories in the Consolidated Balance Sheet are stated at the lower of cost or market. The cost of inventories is primarily determined using the average-cost method.

Property, plant, and equipment

Property, plant, and equipment is recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values.

As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply a declining balance method. (SeeNote 10 – Property, Plant and Equipment.)

Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation; other gains or losses are recorded in Other (income) expense – net included in Operating income in the Consolidated Statement of Comprehensive Income.

Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment.

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. As regulated entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that is attributable to capitalized ARO cost to a regulatory asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income, except for regulated entities, for which the liability is offset by a regulatory asset as management expects to recover amounts in future rates. The regulatory asset is amortized commensurate with the collection of those costs in rates.

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.

Goodwill

Goodwill in the Consolidated Balance Sheet represents the excess cost over fair value of the net assets of businesses acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount. As part of the evaluation, we compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess.

Other intangible assets

Our identifiable intangible assets are primarily related to gas gathering, processing and fractionation contracts, and relationships with customers. Our intangible assets are amortized on a straight-line basis over the period in which these assets contribute to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining useful life.

Impairment of property, plant, and equipment, other identifiable intangible assets, and investments

We evaluate our property, plant, and equipment and other identifiable intangible 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 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 and we may 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. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.

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

We evaluate our investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal.

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.

Cash flows from revolving credit facility and commercial paper program

Proceeds and payments related to borrowings under our credit facility are reflected in the financing activities in the Consolidated Statement of Cash Flows on a gross basis. Proceeds and payments related to borrowings under our commercial paper program are reflected in the financing activities in the Consolidated Statement of Cash Flows on a net basis, as the outstanding notes generally have maturity dates less than three months from the date of issuance. (See Note 11 – Debt, Banking Arrangements, and Leases.)

Derivative instruments and hedging activities

We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of physical energy commodities. We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Other current assets; Regulatory assets, deferred charges, and other; Other accrued liabilities; or Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis. See Note 13 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.

The accounting for the changes in fair value of a commodity derivative can be summarized as follows:

Derivative Treatment	Accounting Method
Normal purchases and normal sales exception	Accrual accounting
Designated in a qualifying hedging relationship	Hedge accounting
All other derivatives	Mark-to-market accounting

We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.

We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income.

For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in Accumulated other comprehensive income (loss) (AOCI) in the Consolidated Balance Sheet and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in Product sales or Product costs in the Consolidated Statement of Comprehensive Income at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by management.

For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income.

Certain gains and losses on derivative instruments included in the Consolidated Statement of Comprehensive Income are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception.

Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives for NGL processing activities and which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.

Revenues

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.

Service revenues

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

Certain revenues from our midstream operations include those derived from natural gas gathering and processing services and are performed under volumetric-based fee contracts. These revenues are recorded when services have been performed.

Crude oil gathering and transportation revenues and offshore production handling fees are recognized when the services have been performed. Certain offshore production handling contracts contain fixed payment terms that result in the deferral of revenues until such services have been performed.

Storage revenues from our midstream operations associated with prepaid contracted storage capacity contracts are recognized on a straight-line basis over the life of the contract as services are provided.

Product sales

In the course of providing transportation services to customers of our interstate natural gas pipeline businesses, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided for in our FERC tariffs. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances.

We market NGLs, crude oil, natural gas, and olefins that we purchase from our producer customers as part of the overall service provided to producers. Revenues from marketing NGLs are recognized when the products have been sold and delivered.

Under our keep-whole and percent-of-liquids processing contracts, we retain the rights to all or a portion of the NGLs extracted from the producers’ natural gas stream and recognize revenues when the extracted NGLs are sold and delivered.

Our olefins business produces olefins from purchased or produced feedstock and we recognize revenues when the olefins are sold and delivered.

Interest capitalized

We capitalize interest during construction on major projects with construction periods of at least 3 months and a total project cost in excess of $1 million. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds. The latter is included in Other income (expense) – net below Operating incomein the Consolidated Statement of Comprehensive Income. The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by nonregulated companies are based on our average interest rate on debt.

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 individual partners. Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregated difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available to us.

Earnings per unit

We use the two-class method to calculate basic and diluted earnings per unit whereby net income, adjusted for items specifically allocated to our general partner, is allocated on a pro-rata basis between unitholders and our general partner. Basic and diluted earnings per unit are based on the average number of common units outstanding. Basic and diluted earnings per unit are equivalent as there are no dilutive securities outstanding.

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 8 – Benefit Plans.) 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.

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Consolidated Balance Sheet (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 102	$ 20
Trade accounts and notes receivable, net	523	562
Inventories	193	173
Other current assets	96	95
Total current assets	914	850
Investments	2,187	1,800
Property, plant, and equipment - net	16,488	14,287
Goodwill	646	649
Other intangible assets	1,642	1,702
Regulatory assets, deferred charges, and other	481	421
Total assets	22,358	19,709
Accounts payable:
Trade	828	851
Affiliate	93	117
Accrued interest	115	110
Asset retirement obligations	63	68
Other accrued liabilities	370	203
Commercial Paper	225	0
Total current liabilities	1,694	1,349
Long-term debt	9,057	8,437
Asset retirement obligations	491	508
Regulatory liabilities, deferred income, and other	557	518
Contingent liabilities and commitments (Note 14)
Partners' equity
Common units (438,625,699 units outstanding at December 31, 2013 and 397,963,199 units outstanding at December 31, 2012)	11,596	10,372
General partner	(1,451)	(1,487)
Accumulated other comprehensive income (loss)	(1)	(2)
Total partners' equity	10,144	8,883
Noncontrolling interests in consolidated subsidiaries	415	14
Total equity	10,559	8,897
Total liabilities and equity	$ 22,358	$ 19,709

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Debt, Banking Arrangements, and Leases

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Debt Disclosure [Text Block]

Note 11 – Debt, Banking Arrangements, and Leases

Long-Term Debt

	December 31,
	2013			2012
	(Millions)
Unsecured:
Transco:
6.4% Notes due 2016	$	200		$	200
6.05% Notes due 2018	250			250
7.08% Debentures due 2026	8			8
7.25% Debentures due 2026	200			200
5.4% Notes due 2041	375			375
4.45% Notes due 2042	400			400
Northwest Pipeline:
7% Notes due 2016	175			175
5.95% Notes due 2017	185			185
6.05% Notes due 2018	250			250
7.125% Debentures due 2025	85			85
Williams Partners L.P.:
3.8% Notes due 2015	750			750
7.25% Notes due 2017	600			600
5.25% Notes due 2020	1,500			1,500
4.125% Notes due 2020	600			600
4% Notes due 2021	500			500
3.35% Notes due 2022	750			750
4.5% Notes due 2023	600			—
6.3% Notes due 2040	1,250			1,250
5.8% Notes due 2043	400			—
Credit facility loans	—			375
Unamortized debt discount	(21		)	(16		)
Long-term debt	$	9,057		$	8,437

The terms of our senior unsecured notes are governed by indentures that contain covenants that, among other things, limit: (1) our ability and the ability of our subsidiaries to create liens securing indebtedness and (2) mergers, consolidations, and sales of assets. The indentures also contain customary events of default, upon which the trustee or the holders of the senior unsecured notes may declare all outstanding senior unsecured notes to be due and payable immediately.

The following table presents aggregate minimum maturities of long-term debt (excluding unamortized discount) for each of the next five years:

	December 31, 2013
	(Millions)
2014	$	—
2015	750
2016	375
2017	785
2018	500

Issuances and retirements

In November 2013, we completed a public offering of $600 million of 4.5 percent senior unsecured notes due 2023 and $400 million of 5.8 percent senior unsecured notes due 2043. We used the net proceeds to repay amounts outstanding under our commercial paper program, to fund capital expenditures, and for general partnership purposes.

In August 2012, we completed a public offering of $750 million of 3.35 percent senior unsecured notes due 2022. We used the net proceeds to repay outstanding borrowings on our senior unsecured revolving credit facility and for general partnership purposes.

In July 2012, Transco issued $400 million of 4.45 percent senior unsecured notes due 2042 to investors in a private debt placement. An offer to exchange these unregistered notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended, was commenced in November 2012 and completed in December 2012. A portion of the proceeds from the issuance of these notes was used to repay Transco’s $325 million of 8.875 percent senior unsecured notes that matured on July 15, 2012.

Credit Facility

In July 2013, we amended our $2.4 billion credit facility to increase the aggregate commitments to $2.5 billion and extend the maturity date to July 31, 2018. Additionally, Transco and Northwest Pipeline are each able to borrow up to $500 million under the amended credit facility to the extent not otherwise utilized by the other co-borrowers. Our credit facility may also, under certain conditions, be increased up to an additional $500 million. As a result of the modifications, the previously deferred fees and costs related to these facilities are being amortized over the term of the new arrangements. At December 31, 2013, letter of credit capacity under our $2.5 billion credit facility is $1.3 billion, no letters of credit have been issued, and no loans are outstanding under our credit facility.

Our significant financial covenants require our ratio of debt to EBITDA (each as defined in the credit facility) must be no greater than 5 to 1. For the fiscal quarter and the two following fiscal quarters in which one or more acquisitions for a total aggregate purchase price equal to or greater than $50 million has been executed, we are required to maintain a ratio of debt to EBITDA of no greater than 5.5 to 1. In addition, the ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for each of Transco and Northwest Pipeline. At December 31, 2013, we are in compliance with these financial covenants.

The credit agreement governing our credit facility contains the following terms and conditions:

• Each time funds are borrowed, the applicable borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.’s alternate base rate plus an applicable margin or a periodic fixed rate equal to LIBOR plus an applicable margin. The applicable borrower is required to pay a commitment fee (currently 0.175 percent) based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings.

• 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, make investments, and allow any material change in the nature of its business.

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

Commercial Paper Program

In March 2013, we initiated a commercial paper program. The program allows a maximum outstanding amount at any time of $2 billion of unsecured commercial paper notes. The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. Proceeds from these notes are used for general partnership purposes, including funding capital expenditures, working capital, and partnership distributions.  We classify commercial paper outstanding in Current liabilities in the Consolidated Balance Sheet, as the outstanding notes at December 31, 2013, have maturity dates less than three months from the date of issuance. At December 31, 2013, $225 million of Commercial paper is outstanding at a weighted average interest rate of 0.42 percent.

Cash Payments for Interest (Net of Amounts Capitalized)

Cash payments for interest (net of amounts capitalized) were $366 million in 2013, $381 million in 2012, and $387 million in 2011.

Leases-Lessee

The future minimum annual rentals under noncancelable operating leases, are payable as follows:

	December 31, 2013
	(Millions)
2014	$	41
2015	35
2016	33
2017	30
2018	29
Thereafter	123
Total	$	291

Under our right-of-way agreement with the Jicarilla Apache Nation, we make annual payments of approximately $8 million and an additional annual payment which varies depending on the prior year’s per-unit NGL margins and the volume of gas gathered by our gathering facilities subject to the agreement. Depending primarily on the per-unit NGL margins for any given year, the additional annual payments could exceed the fixed amount. This agreement expires March 31, 2029.

Total rent expense was $50 million in 2013, $45 million in 2012, and $37 million in 2011.

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 25, 2014	Jun. 30, 2013
Document and Entity Information [Abstract]
Entity Registrant Name	Williams Partners L.P.
Entity Central Index Key	0001324518
Document Type	10-K
Document Period End Date	Dec. 31, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 6,919,922,129
Entity Common Stock, Shares Outstanding		438,625,699

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Partners' Capital

12 Months Ended

Dec. 31, 2013

Partners' Capital [Abstract]

Unit Transactions Disclosure [Text Block]

Note 12 – Partners’ Capital

At December 31, 2013 and 2012, the public held 36 percent and 30 percent, respectively, of our total units outstanding, and affiliates of Williams held the remaining units. Transactions which occurred during 2013 and 2012 are summarized below.

In March 2013, we completed an equity issuance of 14,250,000 common units, including 3,000,000 common units sold to Williams in a private placement. Subsequently, the underwriters exercised their option to purchase an additional 1,687,500 common units. The net proceeds of approximately $760 million were used to repay amounts outstanding under our credit facility.

In August 2013, we completed an equity issuance of 21,500,000 common units. Subsequently, the underwriters exercised their option to purchase an additional 3,225,000 common units. The net proceeds of approximately $1.2 billion were used to repay amounts outstanding under our commercial paper program, to fund capital expenditures and for general partnership purposes.

In January 2012, we issued 7,000,000 common units. The net proceeds of approximately $426 million were used to fund capital expenditures and for other partnership purposes.

In February 2012, we closed the Laser Acquisition. In connection with this transaction, we issued 7,531,381 of our common units. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)

In February 2012, the underwriters exercised their option to purchase an additional 1,050,000 common units pursuant to our common unit offering in January 2012. The net proceeds of approximately $64 million were used for general partnership purposes.

In April 2012, we issued 10,000,000 common units. Subsequently, the underwriters exercised their option to purchase an additional 973,368 common units. The net proceeds of approximately $581 million were used for general partnership purposes, including the funding of a portion of the cash purchase price of the Caiman Acquisition. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.) We also used $1 billion in proceeds from an April 2012 sale of 16,360,133 common units to Williams to partially fund the Caiman Acquisition.

In April 2012, we closed the Caiman Acquisition. In connection with this transaction, we issued 11,779,296 of our common units. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)

In June 2012, we acquired a 1 percent interest in Gulfstream from a subsidiary of Williams. In connection with this transaction, we issued 238,050 of our common units. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)

In August 2012, we completed an equity issuance of 8,500,000 common units. Subsequently, the underwriters exercised their option to purchase an additional 1,275,000 common units. The net proceeds of approximately $488 million were used to repay amounts outstanding under our revolving credit facility and for general partnership purposes.

In November 2012, we closed the Geismar Acquisition with Williams. In connection with this transaction, we issued 42,778,812 of our common units. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)

Limited Partners’ Rights

Significant rights of the limited partners include the following:

• Right to receive distributions of available cash within 45 days after the end of each quarter.

• No limited partner shall have any management control over our business and affairs; the general partner shall conduct, direct and manage our activities.

• The general partner may be removed if such removal is approved by the unitholders holding at least 66 2/3 percent of the outstanding units voting as a single class, including units held by our general partner and its affiliates.

Incentive Distribution Rights

Our general partner is entitled to incentive distributions if the amount we distribute to unitholders with respect to any quarter exceeds specified target levels shown below:

Quarterly Distribution Target Amount (per unit)	Unitholders	General Partner
Minimum quarterly distribution of $0.35	98%	2%
Up to $0.4025	98	2
Above $0.4025 up to $0.4375	85	15
Above $0.4375 up to $0.5250	75	25
Above $0.5250	50	50

See Note 4 – Allocation of Net Income and Distributions for information regarding IDR waivers.

In the event of liquidation, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and our general partner in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

Issuances of Additional Partnership Securities

Our partnership agreement allows us to issue additional partnership securities for any partnership purpose at any time and from time to time for consideration and on terms and conditions as our general partner determines, all without the approval of any limited partners.

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Consolidated Balance Sheet (Parenthetical)	Dec. 31, 2013	Dec. 31, 2012
Equity:
Limited partners capital account units outstanding	438,625,699	397,963,199

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Investments

12 Months Ended

Dec. 31, 2013

Investments [Abstract]

Investments [Text Block]

Note 6 – Investments

Investments accounted for using the equity method consist of:

	December 31,
	2013		2012
	(Millions)
OPPL - 50%	$	452	$	454
Gulfstream - 50%	333		348
Discovery - 60% (1)	527		350
Laurel Mountain - 51% (1)	481		444
Caiman II - 47.5%	256		67
Other	138		137
	$	2,187	$	1,800

____________

(1) We account for these investments under the equity method due to the significant participatory rights of our partners such that we do not control or are otherwise not the primary beneficiary of the investments.

The difference between the carrying value of our equity-method investments and the underlying equity in the net assets of the investees is $60 million at December 31, 2013, primarily related to impairments we previously recognized. These differences are amortized over the expected remaining life of the investees’ underlying assets.

We generally fund our portion of significant expansion or development projects of these investees through additional capital contributions. As of December 31, 2013, our proportionate share of amounts remaining to be spent for specific capital projects already in progress for Discovery, Laurel Mountain, and Caiman II totaled $244 million, $72 million, and $119 million, respectively.

We acquired a 1 percent and 24.5 percent interest in Gulfstream from a subsidiary of Williams in June 2012 and May 2011, respectively. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.) We contributed $193 million and $169 million to Discovery in 2013 and 2012, respectively; $42 million, $174 million and $137 million to Laurel Mountain in 2013, 2012, and 2011, respectively; and $192 million and $69 million to Caiman II in 2013 and 2012, respectively.

Our equity-method investees’ organizational documents generally require distribution of available cash to equity holders on a quarterly basis. Dividends and distributions, including those presented below, received from companies accounted for by the equity method were $154 million, $172 million, and $169 million in 2013, 2012, and 2011, respectively. These transactions reduced the carrying value of our investments. These dividends and distributions primarily included:

	Years Ended December 31,
	2013		2012		2011
	(Millions)
Gulfstream	$	81	$	78	$	60
Discovery	12		21		40
Aux Sable Liquid Products L.P.	20		28		35
OPPL	27		28		19

Summarized Financial Position and Results of Operations of All Equity-Method Investments

	December 31,
	2013			2012
	(Millions)
Assets (liabilities):
Current assets	$	412		$	366
Noncurrent assets	5,956			5,225
Current liabilities	(264		)	(247		)
Noncurrent liabilities	(1,305		)	(1,301		)

	Years Ended December 31,
	2013		2012		2011
	(Millions)
Gross revenue	$	1,333	$	1,213	$	1,242
Operating income	367		378		535
Net income	291		309		460

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Related Party Transactions

12 Months Ended

Dec. 31, 2013

Related Party Transactions [Abstract]

Related Party Transactions Disclosure [Text Block]

Note 5 – Related Party Transactions

Reimbursement of Expenses of Our General Partner

The employees of our operated assets are employees of Williams. Williams directly charges us for the payroll and benefit costs associated with operations employees and carries the obligations for many employee-related benefits in its financial statements, including the liabilities related to employee retirement, medical plans, and paid time off. Our share of the costs is charged to us through affiliate billings and reflected in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income.

In addition, employees of Williams provide general and administrative 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. Our share of direct and allocated administrative expenses is reflected in Selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income. 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.

In 2012, Williams engaged a consulting firm to assist in better aligning resources to support their business strategy following the December 31, 2011, spin-off of WPX Energy, Inc. (WPX). Our share of the allocated reorganization-related costs, included in Selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income, is $2 million and $25 million for the years ended December 31, 2013, and December 31, 2012, respectively.

Transactions with Affiliates and Equity-Method Investees

Product costs, in the Consolidated Statement of Comprehensive Income, include charges for the following types of transactions with affiliates and equity-method investees:

• Purchases of olefin and NGL products for resale from Williams Energy Canada ULC, a subsidiary of Williams, at market prices at the time of purchase.

• Purchases of NGLs for resale from Discovery at market prices at the time of purchase.

• Payments to OPPL for transportation of NGLs from certain natural gas processing plants.

Transactions with WPX

We consider WPX an affiliate prior to its spin-off from Williams. Revenues, in the Consolidated Statement of Comprehensive Income, for the year ended December 31, 2011 include the following types of transactions we have with WPX prior to this separation:

• Revenues from transportation and exchange service and rental of communication facilities with WPX. The rates charged to provide sales and services to affiliates are comparable to those that are charged to similarly situated nonaffiliated customers.

• Revenues from gathering, treating, and processing services for WPX under several contracts. We believe that the rates charged to provide these services are reasonable as compared to those that are charged to similarly situated nonaffiliated customers. 

Product costs and Operating and maintenance expenses, in the Consolidated Statement of Comprehensive Income, for the year ended December 31, 2011 include charges for the following types of transactions we have with WPX prior to this separation:

• Purchases of NGLs for resale from WPX at market prices at the time of purchase.

• Purchases of natural gas for shrink replacement and fuel from WPX at market prices at the time of purchase or contract execution.

• Costs related to a transportation capacity agreement transferred to WPX in a prior year. To the extent that WPX did not utilize this transportation capacity for its needs (primarily transporting third-party gas volumes), we reimbursed WPX for these transportation costs.

Historically, we periodically entered into derivative contracts with WPX to hedge forecasted NGL sales and natural gas purchases. These contracts were priced based on market rates at the time of execution.

Summary of the related party transactions discussed in all sections above. 

	Years Ended December 31,
	2013		2012		2011
	(Millions)
Revenues	$	—	$	—	$	310
Product costs	270		300		802
Operating and maintenance expenses:
Employee costs	328		269		236
Other	—		—		305
Selling, general, and administrative expenses:
Employee direct costs	256		287		232
Employee allocated costs	160		184		118

The Accounts payable — affiliate in the Consolidated Balance Sheet represents the payable positions that result from the transactions with affiliates discussed above. We also have $13 million and $15 million in Accounts payable — trade in the Consolidated Balance Sheet with our equity-method investees at December 31, 2013 and December 31, 2012, respectively.

Operating Agreements with Equity-Method Investees

We have operating agreements with certain equity-method investees. These operating agreements typically provide for reimbursement or payment to us for certain direct operational payroll and employee benefit costs, materials, supplies, and other charges and also for management services. Williams supplied a portion of these services, primarily those related to employees since we do not have any employees, to certain equity-method investees. The total gross charges to equity-method investees for these fees included in the Consolidated Statement of Comprehensive Income are $67 million, $75 million and $57 million for the years ended December 31, 2013, 2012, and 2011, respectively.

Omnibus Agreement

In February 2010, we entered into an omnibus agreement with Williams. Under this agreement, Williams is obligated to reimburse us for (i) amounts incurred by us or our subsidiaries for repair or abandonment costs for damages to certain facilities caused by Hurricane Ike, up to a maximum of $10 million, (ii) maintenance capital expenditure amounts incurred by us or our subsidiaries for certain U.S. Department of Transportation projects, up to a maximum of $50 million, and (iii) an amount based on the amortization over time of deferred revenue amounts that relate to cash payments received by Williams prior to the closing of the contribution transaction for services to be rendered by us in the future at the Devils Tower floating production platform. In addition, we will be obligated to pay to Williams the proceeds of certain sales of natural gas recovered from the Hester storage field pursuant to the FERC order dated March 7, 2008, approving a settlement agreement. Net amounts received under this agreement for the years ended December 31, 2013, 2012 and 2011 were $12 million, $15 million, and $31 million, respectively.

We have a contribution receivable from our general partner of $3 million and $4 million at December 31, 2013 and December 31, 2012, respectively, for amounts reimbursable to us under omnibus agreements. We net this receivable against Total partners’ equity in the Consolidated Balance Sheet.

Acquisitions and Equity Issuances

Basis of Presentation in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies includes related party transactions for the Geismar and Gulfstream Acquisitions. Prior to the acquisition, Geismar operations were included in Williams’ cash management program under an unsecured promissory note agreement with Williams for both advances to and from Williams. In connection with the Geismar Acquisition, the outstanding advances were distributed to Williams at the close of the transaction. The distribution had no impact on our assets or liabilities. Changes in the advances to Williams are presented as Distributions to The Williams Companies, Inc.- net in the Consolidated Statement of Changes in Equity.

Note 12 – Partners’ Capital includes related party transactions for the sale of limited partner units to Williams in March 2013 and April 2012.

Board of Directors

A member of Williams’ Board of Directors, who was elected in 2013, is also the current chairman, president, and chief executive officer of an energy services company that is a customer of ours. We recorded $131 million inService revenues in Consolidated Statement of Comprehensive Income from this company for transportation and storage of natural gas for the year ended December 31, 2013. This board member does not have any material interest in any transactions between the energy services company and us and he had no role in any such transactions.

Mr. H. Michael Krimbill, a member of our Board of Directors until his term completion in August 2012, has served as the Chief Executive Officer of NGL Energy Partners LP, formerly Silverthorne Energy Partners LP, and as a director of its general partner since 2010. We recorded $61 million and $62 million in Product sales in the Consolidated Statement of Comprehensive Income from NGL Energy Partners LP primarily for the sale of propane at market prices and $13 million and $9 million in Product costs in the Consolidated Statement of Comprehensive Income for the purchase of propane at market prices for the years ended December 31, 2012 and 2011, respectively.

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Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Principles of consolidation

Principles of consolidation

The consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of ventures in which we own an undivided interest. Management judgment is required to evaluate whether we control an entity. Key areas of that evaluation include:

• Determining whether an entity is a variable interest entity (VIE);

• Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that we and our related parties have over those activities through our variable interests;

• Identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether we are a VIE’s primary beneficiary;

• Evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant decisions that would be expected to be made in the ordinary course of business such that we do not have the power to control such entities.

We apply the equity method of accounting to investments in entities over which we exercise significant influence but do not control.

Common control transactions

Common control transactions

Entities and assets acquired from Williams and its affiliates are accounted for as common control transactions whereby the net assets acquired are combined with ours at their historical amounts. If any cash consideration transferred in such a transaction exceeds the carrying value of the net assets acquired, the excess is treated as a capital transaction with our general partner, similar to a dividend. If the carrying value of the net assets acquired exceeds any cash consideration transferred and limited partner units are also issued as consideration, then the limited partner units are recorded at an amount equal to the excess of the carrying value of the net assets acquired over any cash consideration transferred. To the extent that such transactions require prior periods to be recast, historical net equity amounts prior to the transaction date are reflected in the account of the general partner. Cash consideration up to the carrying value of net assets acquired is presented as an investing activity in our Consolidated Statement of Cash Flows. Cash consideration in excess of the carrying value of net assets acquired is presented as a financing activity in our Consolidated Statement of Cash Flows.

Use of estimates

Use of estimates

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

Significant estimates and assumptions include:

• Impairment assessments of investments, property, plant, and equipment, goodwill and other identifiable intangible assets;

• Litigation-related contingencies;

• Environmental remediation obligations;

• Asset retirement obligations;

• Acquisition related purchase price allocations.

These estimates are discussed further throughout these notes.

Regulatory Accounting

Regulatory accounting

Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC). Their rates, which are established by the FERC, are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, our management has determined that it is appropriate to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are established. Accounting for these operations that are regulated can differ from the accounting requirements for non regulated operations. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, and postretirement benefits. Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2013 and 2012 are as follows:

	December 31,
	2013		2012
	(Millions)
Current assets reported within Other current assets	$	39	$	39
Noncurrent assets reported within Regulatory assets, deferred charges, and other	315		275
Total regulated assets	$	354	$	314
Current liabilities reported within Other accrued liabilities	$	19	$	15
Noncurrent liabilities reported within Regulatory liabilities, deferred income and other	289		250
Total regulated liabilities	$	308	$	265

Cash and cash equivalents

Cash and cash equivalents

Cash and cash equivalents in the Consolidated Balance Sheet includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.

Accounts receivable

Accounts receivable

Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted.

Inventory valuation

Inventory valuation

All Inventories in the Consolidated Balance Sheet are stated at the lower of cost or market. The cost of inventories is primarily determined using the average-cost method.

Property, plant, and equipment

Property, plant, and equipment

Property, plant, and equipment is recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values.

As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply a declining balance method. (SeeNote 10 – Property, Plant and Equipment.)

Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation; other gains or losses are recorded in Other (income) expense – net included in Operating income in the Consolidated Statement of Comprehensive Income.

Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment.

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. As regulated entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that is attributable to capitalized ARO cost to a regulatory asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income, except for regulated entities, for which the liability is offset by a regulatory asset as management expects to recover amounts in future rates. The regulatory asset is amortized commensurate with the collection of those costs in rates.

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.

Goodwill

Goodwill

Goodwill in the Consolidated Balance Sheet represents the excess cost over fair value of the net assets of businesses acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount. As part of the evaluation, we compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess.

Other intangible assets

Other intangible assets

Our identifiable intangible assets are primarily related to gas gathering, processing and fractionation contracts, and relationships with customers. Our intangible assets are amortized on a straight-line basis over the period in which these assets contribute to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining useful life.

Impairment of property, plant, and equipment, other identifiable intangible assets and investments

Impairment of property, plant, and equipment, other identifiable intangible assets, and investments

We evaluate our property, plant, and equipment and other identifiable intangible 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 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 and we may 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. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.

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

We evaluate our investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal.

Contingent liabilities

Contingent liabilities

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

Cash flows from revolving credit facilities and commercial paper program

Cash flows from revolving credit facility and commercial paper program

Proceeds and payments related to borrowings under our credit facility are reflected in the financing activities in the Consolidated Statement of Cash Flows on a gross basis. Proceeds and payments related to borrowings under our commercial paper program are reflected in the financing activities in the Consolidated Statement of Cash Flows on a net basis, as the outstanding notes generally have maturity dates less than three months from the date of issuance. (See Note 11 – Debt, Banking Arrangements, and Leases.)

Derivative instruments and hedging activities

Derivative instruments and hedging activities

We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of physical energy commodities. We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Other current assets; Regulatory assets, deferred charges, and other; Other accrued liabilities; or Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis. See Note 13 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.

The accounting for the changes in fair value of a commodity derivative can be summarized as follows:

Derivative Treatment	Accounting Method
Normal purchases and normal sales exception	Accrual accounting
Designated in a qualifying hedging relationship	Hedge accounting
All other derivatives	Mark-to-market accounting

We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.

We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income.

For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in Accumulated other comprehensive income (loss) (AOCI) in the Consolidated Balance Sheet and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in Product sales or Product costs in the Consolidated Statement of Comprehensive Income at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by management.

For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income.

Certain gains and losses on derivative instruments included in the Consolidated Statement of Comprehensive Income are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception.

Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives for NGL processing activities and which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.

Revenues

Revenues

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.

Service revenues

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

Certain revenues from our midstream operations include those derived from natural gas gathering and processing services and are performed under volumetric-based fee contracts. These revenues are recorded when services have been performed.

Crude oil gathering and transportation revenues and offshore production handling fees are recognized when the services have been performed. Certain offshore production handling contracts contain fixed payment terms that result in the deferral of revenues until such services have been performed.

Storage revenues from our midstream operations associated with prepaid contracted storage capacity contracts are recognized on a straight-line basis over the life of the contract as services are provided.

Product sales

In the course of providing transportation services to customers of our interstate natural gas pipeline businesses, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided for in our FERC tariffs. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances.

We market NGLs, crude oil, natural gas, and olefins that we purchase from our producer customers as part of the overall service provided to producers. Revenues from marketing NGLs are recognized when the products have been sold and delivered.

Under our keep-whole and percent-of-liquids processing contracts, we retain the rights to all or a portion of the NGLs extracted from the producers’ natural gas stream and recognize revenues when the extracted NGLs are sold and delivered.

Our olefins business produces olefins from purchased or produced feedstock and we recognize revenues when the olefins are sold and delivered.

Interest capitalized

Interest capitalized

We capitalize interest during construction on major projects with construction periods of at least 3 months and a total project cost in excess of $1 million. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds. The latter is included in Other income (expense) – net below Operating incomein the Consolidated Statement of Comprehensive Income. The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by nonregulated companies are based on our average interest rate on debt.

Income taxes

Income taxes

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

Earnings per unit

Earnings per unit

We use the two-class method to calculate basic and diluted earnings per unit whereby net income, adjusted for items specifically allocated to our general partner, is allocated on a pro-rata basis between unitholders and our general partner. Basic and diluted earnings per unit are based on the average number of common units outstanding. Basic and diluted earnings per unit are equivalent as there are no dilutive securities outstanding.

Pension and other postretirement benefits

Pension and other postretirement benefits

We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 8 – Benefit Plans.) 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.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurements

Note 13 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, commercial paper, 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, 2013:
Measured on a recurring basis:
ARO Trust investments	$	33		$	33		$	33	$	—		$	—
Energy derivatives assets not designated as hedging instruments	3			3			—		—			3
Energy derivatives liabilities not designated as hedging instruments	(3		)	(3		)	—		(1		)	(2		)
Additional disclosures:
Notes receivable and other	7			7			1		6			—
Long-term debt	(9,057		)	(9,581		)	—		(9,581		)	—
Assets (liabilities) at December 31, 2012:
Measured on a recurring basis:
ARO Trust investments	$	18		$	18		$	18	$	—		$	—
Energy derivatives assets not designated as hedging instruments	5			5			—		—			5
Energy derivatives liabilities not designated as hedging instruments	(1		)	(1		)	—		—			(1		)
Additional disclosures:
Notes receivable and other	11			10			2		8			—
Long-term debt	(8,437		)	(9,624		)	—		(9,624		)	—

Fair Value Methods

We use the following methods and assumptions in estimating the fair value of our financial instruments:

Assets and liabilities measured at fair value on a recurring basis

ARO Trust investments:  Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust that 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, is classified as available-for-sale, and is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.

Energy derivatives:  Energy derivatives include commodity based exchange-traded contracts and over-the-counter (OTC) contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives assets are reported in Other current assets and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Energy derivatives liabilities are reported in Other accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.

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 years ended December 31, 2013 or 2012.

Additional fair value disclosures

Notes receivable and other: The disclosed fair value of our notes receivable is primarily determined by an income approach which considers the underlying contract amounts and our assessment of our ability to recover these amounts. The current portion is reported in Trade accounts and notes receivable, net, and the noncurrent portion is reported in Regulatory assets, deferred charges, and otherin 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.

Guarantees

We are required by our revolving credit agreement to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.

Concentration of Credit Risk

Cash equivalents

Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.

Accounts and notes receivable

The following table summarizes concentration of receivables, net of allowances.

	December 31,
	2013		2012
	(Millions)
NGLs, natural gas, and related products and services	$	327	$	393
Transportation of natural gas and related products	193		169
Other	3		—
Total	$	523	$	562

Customers include producers, distribution companies, industrial users, gas marketers and pipelines primarily located in the continental United States. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.

Revenues

In 2013, 2012 and 2011, we had one customer in our NGL & Petchem Services segment that accounted for 10 percent, 14 percent, and 17 percent of our consolidated revenues, respectively.

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Inventories

12 Months Ended

Dec. 31, 2013

Inventory Disclosure [Abstract]

Inventories

Note 9 – Inventories

	December 31,
	2013		2012
	(Millions)
Natural gas liquids, olefins, and natural gas in underground storage	$	112	$	96
Materials, supplies, and other	81		77
	$	193	$	173

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Other Income and Expense

12 Months Ended

Dec. 31, 2013

Other Income and Expenses [Abstract]

Other Income and Expense

Note 7 – Other Income and Expenses

The following table presents significant gains or losses reflected in Other (income) expense – netwithin Costs and expenses:

	Years Ended December 31,
	2013			2012			2011
	(Millions)
Northeast G&P
Settlement in principle of a producer claim	$	25		$	—		$	—
Atlantic-Gulf
Amortization of regulatory asset associated with asset retirement obligations	30			7			6
Write-off of the Eminence abandonment regulatory asset not recoverable through rates	12			—			—
Insurance recoveries associated with the Eminence abandonment	(16		)	—			—
Project feasibility costs	4			21			10
Capitalization of project feasibility costs previously expensed	(1		)	(19		)	(11		)
NGL & Petchem Services
Net insurance recoveries associated with the Geismar Incident	(40		)	—			—

The reversals of project feasibility costs from expense to capital are associated with natural gas pipeline expansion projects. These reversals were made upon determining that the related projects were probable of development. These costs are now included in the capital costs of the projects, which we believe are probable of recovery through the project rates.

On June 13, 2013, an explosion and fire occurred at our Geismar olefins plant. The fire was extinguished on the day of the incident. The incident (Geismar Incident) rendered the facility temporarily inoperable and resulted in significant human, financial and operational effects.

We have substantial insurance coverage for repair and replacement costs, lost production, and additional expenses related to the incident as follows:

• Property damage and business interruption coverage with a combined per-occurrence limit of $500 million and retentions (deductibles) of $10 million per occurrence for property damage and a waiting period of 60 days per occurrence for business interruption;

• General liability coverage with per-occurrence and aggregate annual limits of $610 million and retentions (deductibles) of $2 million per occurrence;

• Workers’ compensation coverage with statutory limits and retentions (deductibles) of $1 million total per occurrence.

We have expensed $13 million at NGL & Petchem Services during 2013 of costs under our insurance deductibles in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income. Recoveries under our business interruption policy will be recognized upon resolution of any contingencies with the insurer associated with the claim. Through December 31, 2013, we have recognized $50 million of insurance recoveries related to this incident as a gain to Other (income) expense – net within Costs and expenses in our Consolidated Statement of Comprehensive Income. During the fourth quarter of 2013, we incurred $10 million of covered insurable expenses in excess of our retentions (deductibles) which partially offset the $50 million gain included in Other (income) expense – net within Costs and expenses in our Consolidated Statement of Comprehensive Income.

Additional Items

We detected a leak in an underground cavern at our Eminence Storage Field in Mississippi on December 28, 2010. We recorded $3 million, $2 million, and $15 million of charges to Operating and maintenance expenses at Atlantic-Gulf during 2013, 2012, and 2011, respectively, primarily related to assessment and monitoring costs incurred to ensure the safety of the surrounding area.

Other income (expense) – net below Operating income for 2013, includes a charge of $14 million associated with the impact of a second quarter Texas franchise tax law change.

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Benefit Plans

12 Months Ended

Dec. 31, 2013

Employee Benefits and Share-based Compensation [Abstract]

Pension and Other Postretirement Benefits Disclosure [Text Block]

Note 8 – 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 plans

Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible employees. Pension costs charged to us by Williams for 2013, 2012, and 2011 totaled $44 million, $41 million, and $32 million, respectively. At the total Williams plan level, the pension plans had a projected benefit obligation of $1.4 billion and $1.5 billion at December 31, 2013 and 2012, respectively. The plans were underfunded by $143 million and $478 million at December 31, 2013 and 2012, respectively.

Postretirement benefits other than pensions

Williams provides certain retiree health care and life insurance benefits for eligible participants. Generally, employees that 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 are eligible for subsidized retiree medical benefits. The cost charged to us for the plans anticipates future cost-sharing that is consistent with Williams’ expressed intent to increase the retiree contribution level, generally in line with health care cost increases. We recognized a net periodic postretirement benefit credited to us by Williams of $4 million in 2013 and $2 million in 2011, and a net periodic postretirement benefit cost charged to us by Williams of $4 million in 2012. At the total Williams plan level, the postretirement benefit plans had an accumulated postretirement benefit obligation of $213 million and $331 million at December 31, 2013 and 2012, respectively. The plans were underfunded by $12 million and $156 million at December 31, 2013 and 2012, respectively.

Any differences between the annual expense and amounts currently being recovered in rates by our FERC-regulated gas pipelines are recorded as an adjustment to expense and collected or refunded through future rate adjustments.

Defined contribution plan

Williams charged us compensation expense of $15 million, $18 million, and $16 million in 2013, 2012, and 2011, respectively, for Williams’ matching contributions to this plan.

Employee Stock-Based Compensation Plan information

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

Williams bills us directly for compensation expense related to stock-based compensation awards based on the fair value of the awards.

Total stock-based compensation expense for the years ended December 31, 2013, 2012, and 2011 was $11 million, $12 million and $10 million, respectively.

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Textblock]

Note 10 – Property, Plant and Equipment

	Estimated	Depreciation
	Useful Life (1)	Rates (1)	December 31,
	(Years)	(%)	2013			2012
			(Millions)
Nonregulated:
Natural gas gathering and processing facilities	5 - 40		$	8,018		$	7,000
Construction in progress	Not applicable		2,658			1,599
Other	3 - 45		899			745
Regulated:
Natural gas transmission facilities		1.2 - 6.97	10,633			9,963
Construction in progress		Not applicable	273			337
Other		1.35 - 33.33	1,293			1,418
Total property, plant, and equipment, at cost			$	23,774		$	21,062
Accumulated depreciation and amortization			(7,286		)	(6,775		)
Property, plant, and equipment — net			$	16,488		$	14,287

______________________

(1) Estimated useful life and depreciation rates are presented as of December 31, 2013. Depreciation rates for regulated assets are prescribed by the FERC.

Depreciation and amortization expense for Property, plant, and equipment – net was $697 million, $670 million and $618 million in 2013, 2012, and 2011, respectively.

Regulated Property, plant, and equipment – net includes approximately $785 million and $825 million at December 31, 2013 and 2012, respectively, related to amounts in excess of the original cost of the regulated facilities within our gas pipeline businesses as a result of our prior acquisitions. This amount is being amortized over 40 years using the straight-line amortization method. Current FERC policy does not permit recovery through rates for amounts in excess of original cost of construction.

Asset Retirement Obligations

Our accrued obligations relate to underground storage caverns, offshore platforms, fractionation and compression facilities, gas gathering well connections and 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 restore land and remove surface equipment at gas processing, fractionation and compression facilities, 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.

The following table presents the significant changes to our asset retirement obligations (ARO):

	December 31,
	2013			2012
	(Millions)
Beginning balance	$	576		$	570
Liabilities incurred	4			8
Liabilities settled (1)	(30		)	(44		)
Accretion expense	52			43
Revisions (2)	(48		)	(1		)
Ending balance	$	554		$	576

______________

(1) For 2013 and 2012, liabilities settled include $25 million and $31 million, respectively, related to the abandonment of certain of Transco’s natural gas storage caverns that are associated with a leak in 2010.

(2) Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining life of the assets. The 2013 revision primarily reflects increases in the estimated remaining useful life of the assets. The 2012 revision primarily reflects a decrease in removal cost estimates. The 2013 and 2012 revisions also include increases of $9 million and $13 million, respectively, related to changes in the timing and method of abandonment on certain of Transco’s natural gas storage caverns that were associated with a leak in 2010.

Transco is entitled to collect in rates the amounts necessary to fund its ARO. All funds received for such retirements are deposited into an external trust account dedicated to funding its ARO (ARO Trust). (See Note 13 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) Under its current rate settlement Transco’s annual funding obligation is approximately $36 million, with installments to be deposited monthly.

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Partners' Capital (Tables)

12 Months Ended

Dec. 31, 2013

Partners Capital Notes Table [Abstract]

Incentive Distribution Percentage By Specified Target Level [Table Text Block]

Incentive Distribution Rights

Our general partner is entitled to incentive distributions if the amount we distribute to unitholders with respect to any quarter exceeds specified target levels shown below:

Quarterly Distribution Target Amount (per unit)	Unitholders	General Partner
Minimum quarterly distribution of $0.35	98%	2%
Up to $0.4025	98	2
Above $0.4025 up to $0.4375	85	15
Above $0.4375 up to $0.5250	75	25
Above $0.5250	50	50

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Credit Facility and Commercial Paper (Details 4) (USD $) In Millions, unless otherwise specified	12 Months Ended									12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Northwest Pipeline LLC [Member]	Dec. 31, 2013 Transcontinental Gas PipeLine Company, LLC [Member]	Jul. 31, 2013 $2.4 Billion Unsecured Credit Facility terminated July 2013 [Member]	Dec. 31, 2013 $2.5 Billion Unsecured Credit Facility [Member]	Dec. 31, 2013 $2.5 Billion Unsecured Credit Facility [Member] Northwest Pipeline LLC [Member]	Dec. 31, 2013 $2.5 Billion Unsecured Credit Facility [Member] Transcontinental Gas PipeLine Company, LLC [Member]	Dec. 31, 2013 $2.5 Billion Unsecured Credit Facility Letter of Credit [Member]	Dec. 31, 2013 Commercial Paper [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity					$ 2,400	$ 2,500	$ 500	$ 500	$ 1,300	$ 2,000
Credit facility, loans outstanding	0	375				0
Credit facility, letters of credit outstanding									0
Commercial paper, outstanding	225	0								225
Commercial paper, weighted average interest rate										0.42%
Commercial paper, maximum maturity										397 days
Additional amount by which credit facility can be increased						500
Maximum ratio of debt to EBITDA	500.00%
Minimum aggregate purchase price of acquisitions impacting maximum ratio of debt to EBITDA	$ 50
Maximum ratio of debt to EBITDA after acquisition	550.00%
Maximum ratio of debt to capitalization			65.00%	65.00%
Commitment fee	0.175%

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Segment Disclosures

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Segment Disclosures

Note 15 – Segment Disclosures

Our reportable segments are Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)

Performance Measurement

We currently evaluate segment operating performance based on Segment profit (loss) from operations, which includes Segment revenues from external and internal customers, segment costs and expenses, and Equity earnings (losses). General corporate expenses represent Selling, general, and administrative expenses that are not allocated to our segments. The accounting policies of the segments are the same as those described in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies. Intersegment revenues primarily represent the sale of NGLs from our natural gas processing plants to our marketing business and are generally accounted for at current market prices as if the sales were to unaffiliated third parties.

The following table reflects the reconciliation of Segment revenues and Segment profit (loss) to Total revenues and Operating income as reported in the Consolidated Statement of Comprehensive Income. It also presents other financial information related to long-lived assets.

	Northeast G&P			Atlantic- Gulf		West		NGL & Petchem Services		Eliminations			Total
	(Millions)
2013
Segment revenues:
Service revenues
External	$	335		$	1,414	$	1,053	$	108	$	—		$	2,910
Internal	—			10		1		—		(11		)	—
Total service revenues	335			1,424		1,054		108		(11		)	2,910
Product sales
External	166			830		64		2,715		—			3,775
Internal	—			95		708		294		(1,097		)	—
Total product sales	166			925		772		3,009		(1,097		)	3,775
Total revenues	$	501		$	2,349	$	1,826	$	3,117	$	(1,108	)	$	6,685
Segment profit (loss)	$	(24	)	$	614	$	741	$	275				$	1,606
Less equity earnings (losses)	(7		)	72		—		39					104
Segment operating income (loss)	$	(17	)	$	542	$	741	$	236				1,502
General corporate expenses													(160		)
Operating income													$	1,342
Other financial information:
Depreciation and amortization	$	132		$	363	$	236	$	27	$	—		$	758
2012
Segment revenues:
Service revenues
External	$	168		$	1,371	$	1,067	$	103	$	—		$	2,709
Internal	—			12		5		—		(17		)	—
Total service revenues	168			1,383		1,072		103		(17		)	2,709
Product sales
External	2			709		40		3,860		—			4,611
Internal	—			363		1,089		258		(1,710		)	—
Total product sales	2			1,072		1,129		4,118		(1,710		)	4,611
Total revenues	$	170		$	2,455	$	2,201	$	4,221	$	(1,727	)	$	7,320
Segment profit (loss)	$	(37	)	$	574	$	980	$	295				$	1,812
Less equity earnings (losses)	(23		)	92		—		42					111
Segment operating income (loss)	$	(14	)	$	482	$	980	$	253				1,701
General corporate expenses													(184		)
Operating income													$	1,517
Other financial information:
Depreciation and amortization	$	76		$	381	$	234	$	23	$	—		$	714

	Northeast G&P			Atlantic- Gulf		West		NGL & Petchem Services		Eliminations			Total
	(Millions)
2011
Segment revenues:
Service revenues
External	$	49		$	1,332	$	1,053	$	83	$	—		$	2,517
Internal	—			—		4		—		(4		)	—
Total service revenues	49			1,332		1,057		83		(4		)	2,517
Product sales
External	—			606		11		4,580		—			5,197
Internal	—			531		1,622		56		(2,209		)	—
Total product sales	—			1,137		1,633		4,636		(2,209		)	5,197
Total revenues	$	49		$	2,469	$	2,690	$	4,719	$	(2,213	)	$	7,714
Segment profit (loss)	$	23		$	585	$	1,181	$	246				$	2,035
Less equity earnings (losses)	(1		)	90		—		53					142
Segment operating income (loss)	$	24		$	495	$	1,181	$	193				1,893
General corporate expenses													(118		)
Operating income													$	1,775
Other financial information:
Depreciation and amortization	$	5		$	365	$	236	$	15	$	—		$	621

The following table reflects Total assets, Investments, and Additions to long-lived assets by reportable segment:  

	Total Assets at December 31,						Investments at December 31,				Additions to Long-Lived Assets at December 31,
	2013			2012			2013		2012		2013		2012		2011
	(Millions)
Northeast G&P (1)	$	6,229		$	4,745		$	737	$	511	$	1,376	$	3,909	$	204
Atlantic-Gulf	10,007			8,734			930		774		1,072		1,002		650
West	4,767			4,688			—		—		210		360		301
NGL & Petchem Services	1,822			1,500			520		515		392		282		103
Other corporate assets	147			409			—		—		5		16		25
Eliminations (2)	(614		)	(367		)	—		—		—		—		—
Total	$	22,358		$	19,709		$	2,187	$	1,800	$	3,055	$	5,569	$	1,283

(1) 2012 Additions to long-lived assets includes the Caiman and Laser Acquisitions. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)

(2) Eliminations primarily relate to the intercompany accounts receivable generated by our cash management program.

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Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2013

Variable Interest Entity Disclosures [Abstract]

Schedule of Variable Interest Entities [Table Text Block]

The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of these VIEs, which are joint projects in the development and construction phase:

	December 31,
	2013			2012			Classification
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	76		$	8		Cash and cash equivalents
Construction in progress	998			556			Property, plant, and equipment, at cost
Accounts payable	(120		)	(128		)	Accounts payable - trade
Construction retainage	(3		)	—			Other accrued liabilities
Current deferred revenue	(10		)	—			Other accrued liabilities
Noncurrent deferred revenue associated with customer advance payments	(115		)	(109		)	Regulatory liabilities, deferred income, and other

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Long-Term Debt Maturities (Details 2) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Long-term Debt, by Maturity [Abstract]
2014	$ 0
2015	750
2016	375
2017	785
2018	$ 500

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Related Party Transactions (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Summary Of Related Party Transactions
Revenue	$ 0	$ 0	$ 310
Product costs	270	300	802
Accounts payable - trade	93	117
Proceeds	12	15	31
Contribution receivable	3	4
Employee costs [Member]
Summary Of Related Party Transactions
Operating and maintenance expenses	328	269	236
Other [Member]
Summary Of Related Party Transactions
Operating and maintenance expenses	0	0	305
Employee direct costs [Member]
Summary Of Related Party Transactions
Selling, general, and administrative expenses	256	287	232
Employee allocated costs [Member]
Summary Of Related Party Transactions
Selling, general, and administrative expenses	160	184	118
Reorganization-related allocated costs [Member]
Summary Of Related Party Transactions
Selling, general, and administrative expenses	2	25
Equity method investees [Member]
Summary Of Related Party Transactions
Accounts payable - trade	13	15
Service costs	67	75	57
Common management [Member]
Summary Of Related Party Transactions
Revenue	131	61	62
Product costs		13	9
Reimbursable hurricane damage costs [Member]
Summary Of Related Party Transactions
Maximum potential obligation	10
Reimbursable maintenance costs for certain government projects [Member]
Summary Of Related Party Transactions
Maximum potential obligation	$ 50

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Consolidated Statement of Changes in Equity (USD $) In Millions	Total	Common Units	General Partner	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests
Beginning Balance at Dec. 31, 2010	$ 5,248	$ 6,564	$ (1,313)	$ (3)	$ 0
Net income	1,511	1,088	423	0	0
Other comprehensive income (loss)	1	0	0	1	0
Cash distributions (Note 4)	(1,124)	(842)	(282)	0	0
Distributions to The Williams Companies, Inc - net	(99)	0	(99)	0	0
Excess of purchase price over contributed basis of investment purchase from affiliate	(123)	0	(123)	0	0
Contributions from general partner	31	0	31	0	0
Other	(12)	0	(12)	0	0
Ending Balance at Dec. 31, 2011	5,433	6,810	(1,375)	(2)	0
Net income	1,232	672	560	0	0
Other comprehensive income (loss)	0
Cash distributions (Note 4)	(1,440)	(1,056)	(384)	0	0
Distributions to The Williams Companies, Inc - net	(42)	0	(42)	0	0
Sales of common units (Note 12)	2,559	2,559	0	0	0
Issuances of common units related to acquisitions (Note 12)	1,044	1,044	0	0	0
Issuances Of Common Units In Common Control Transactions (Note 12)	7	345	(338)	0	0
Excess of purchase price over contributed basis of investment purchase from affiliate	0
Contributions from general partner	93	0	93	0	0
Contributions from noncontrolling interests	14	0	0	0	14
Other	(3)	(2)	(1)	0	0
Ending Balance at Dec. 31, 2012	8,897	10,372	(1,487)	(2)	14
Net income	1,070	660	407	0	3
Other comprehensive income (loss)	1	0	0	1	0
Cash distributions (Note 4)	(1,846)	(1,422)	(424)	0	0
Sales of common units (Note 12)	1,962	1,962	0	0	0
Excess of purchase price over contributed basis of investment purchase from affiliate	0
Contributions from general partner	78	0	78	0	0
Contributions from noncontrolling interests	398	0	0	0	398
Other	(1)	24	(25)	0	0
Ending Balance at Dec. 31, 2013	$ 10,559	$ 11,596	$ (1,451)	$ (1)	$ 415

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Allocation of Net Income and Distributions

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

Allocation of Net Income and Distributions

Note 4 – Allocation of Net Income and Distributions

The allocation of net income among our general partner, limited partners, and noncontrolling interests as reflected in the Consolidated Statement of Changes in Equity is as follows:

	Years Ended December 31,
	2013			2012			2011
	(Millions)
Allocation of net income to general partner:
Net income	$	1,070		$	1,232		$	1,511
Net income applicable to pre-partnership operations allocated to general partner	—			(185		)	(133		)
Net income applicable to noncontrolling interests	(3		)	—			—
Net costs charged directly to general partner	1			1			(2		)
Income subject to 2% allocation of general partner interest	1,068			1,048			1,376
General partner’s share of net income	2		%	2		%	2		%
General partner’s allocated share of net income before items directly allocable to general partner interest	21			21			28
Priority allocations, including incentive distributions, paid to general partner (1)	387			355			260
Net costs charged directly to general partner	(1		)	(1		)	2
Pre-partnership net income allocated to general partner interest	—			185			133
Net income allocated to general partner	$	407		$	560		$	423
Net income	$	1,070		$	1,232		$	1,511
Net income allocated to general partner	407			560			423
Net income allocated to noncontrolling interests	3			—			—
Net income allocated to common limited partners	$	660		$	672		$	1,088

____________

(1) The net income allocated to the general partner’s capital account reflects IDRs paid during the current reporting period. In the calculation of basic and diluted net income per common unit, the net income allocated to the general partner includes IDRs pertaining to the current reporting period but paid in the subsequent period.

The Net costs charged directly to general partner may include the net of both income and expense items. Under the terms of omnibus agreements, we are reimbursed by our general partner for certain expense items and are required to distribute certain income items to our general partner.

The following table sets forth the partnership cash distributions paid on the dates indicated, related to the preceding quarter (in millions, except for per unit amounts):

					General Partner
Payment Date	Per Unit Distribution		Common Units		2%		Incentive Distribution Rights		Total Cash Distribution
2/11/2011	$	0.7025	$	204	$	5	$	59	$	268
5/13/2011	0.7175		208		5		63		276
8/12/2011	0.7325		213		6		67		286
11/11/2011	0.7475		217		6		71		294
2/10/2012	0.7625		227		6		78		311
5/11/2012	0.7775		268		8		86		362
8/10/2012	0.7925		274		7		92		373
11/9/2012	0.8075		287		8		99		394
2/8/2013	0.8275		329		9		104		442
5/10/2013	0.8475		351		10		112		473
8/09/2013	0.8625		357		11		121		489
11/12/2013	0.8775		385		11		46		442
2/13/2014 (1)	0.8925		392		11		153		556

____________

(1) On February 13, 2014, we paid a cash distribution of $0.8925 per unit on our outstanding common units to unitholders of record at the close of business on February 6, 2014.

The 2012, 2013, and 2014 cash distributions paid to our general partner in the table above have been reduced by $147 million resulting from the temporary waiver of IDRs associated with certain assets acquired in 2012 and an additional $90 million in IDRs waived by our general partner related to the third quarter 2013 distributions, to support our cash distribution metrics as our large platform of growth projects moves toward completion.

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Segment Disclosures (Details 1) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Reconciliation of segment revenues and segment profit (loss)
Total revenues	$ 6,685		$ 7,320		$ 7,714
Segment profit (loss)	1,606		1,812		2,035
Less equity earnings (losses)	104		111		142
Operating income	1,342		1,517		1,775
Other financial information:
Depreciation and amortization	758		714		621
Total assets, investments and additions to long-lived assets by reporting segment
Total assets	22,358		19,709
Investments	2,187		1,800
Additions to long-lived assets	3,055		5,569		1,283
Service [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	2,910		2,709		2,517
Product [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	3,775		4,611		5,197
Northeast G&P [Member] | Service [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	335		168		49
Northeast G&P [Member] | Product [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	166		2		0
Atlantic-Gulf [Member] | Service [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	1,414		1,371		1,332
Atlantic-Gulf [Member] | Product [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	830		709		606
West [Member] | Service [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	1,053		1,067		1,053
West [Member] | Product [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	64		40		11
NGL & Petchem Services [Member] | Service [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	108		103		83
NGL & Petchem Services [Member] | Product [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	2,715		3,860		4,580
Operating Segments [Member]
Reconciliation of segment revenues and segment profit (loss)
Operating income	1,502		1,701		1,893
Operating Segments [Member] | Northeast G&P [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	501		170		49
Segment profit (loss)	(24)		(37)		23
Less equity earnings (losses)	(7)		(23)		(1)
Operating income	(17)		(14)		24
Other financial information:
Depreciation and amortization	132		76		5
Total assets, investments and additions to long-lived assets by reporting segment
Total assets	6,229		4,745
Investments	737		511
Additions to long-lived assets	1,376		3,909	[1]	204
Operating Segments [Member] | Northeast G&P [Member] | Service [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	335		168		49
Operating Segments [Member] | Northeast G&P [Member] | Product [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	166		2		0
Operating Segments [Member] | Atlantic-Gulf [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	2,349		2,455		2,469
Segment profit (loss)	614		574		585
Less equity earnings (losses)	72		92		90
Operating income	542		482		495
Other financial information:
Depreciation and amortization	363		381		365
Total assets, investments and additions to long-lived assets by reporting segment
Total assets	10,007		8,734
Investments	930		774
Additions to long-lived assets	1,072		1,002		650
Operating Segments [Member] | Atlantic-Gulf [Member] | Service [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	1,424		1,383		1,332
Operating Segments [Member] | Atlantic-Gulf [Member] | Product [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	925		1,072		1,137
Operating Segments [Member] | West [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	1,826		2,201		2,690
Segment profit (loss)	741		980		1,181
Less equity earnings (losses)	0		0		0
Operating income	741		980		1,181
Other financial information:
Depreciation and amortization	236		234		236
Total assets, investments and additions to long-lived assets by reporting segment
Total assets	4,767		4,688
Investments	0		0
Additions to long-lived assets	210		360		301
Operating Segments [Member] | West [Member] | Service [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	1,054		1,072		1,057
Operating Segments [Member] | West [Member] | Product [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	772		1,129		1,633
Operating Segments [Member] | NGL & Petchem Services [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	3,117		4,221		4,719
Segment profit (loss)	275		295		246
Less equity earnings (losses)	39		42		53
Operating income	236		253		193
Other financial information:
Depreciation and amortization	27		23		15
Total assets, investments and additions to long-lived assets by reporting segment
Total assets	1,822		1,500
Investments	520		515
Additions to long-lived assets	392		282		103
Operating Segments [Member] | NGL & Petchem Services [Member] | Service [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	108		103		83
Operating Segments [Member] | NGL & Petchem Services [Member] | Product [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	3,009		4,118		4,636
Intersegment Eliminations [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	(1,108)		(1,727)		(2,213)
Other financial information:
Depreciation and amortization	0		0		0
Total assets, investments and additions to long-lived assets by reporting segment
Total assets	(614)	[2]	(367)	[2]
Investments	0		0
Additions to long-lived assets	0		0		0
Intersegment Eliminations [Member] | Service [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	(11)		(17)		(4)
Intersegment Eliminations [Member] | Product [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	(1,097)		(1,710)		(2,209)
Intersegment Eliminations [Member] | Northeast G&P [Member] | Service [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	0		0		0
Intersegment Eliminations [Member] | Northeast G&P [Member] | Product [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	0		0		0
Intersegment Eliminations [Member] | Atlantic-Gulf [Member] | Service [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	(10)		(12)		0
Intersegment Eliminations [Member] | Atlantic-Gulf [Member] | Product [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	(95)		(363)		(531)
Intersegment Eliminations [Member] | West [Member] | Service [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	(1)		(5)		(4)
Intersegment Eliminations [Member] | West [Member] | Product [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	(708)		(1,089)		(1,622)
Intersegment Eliminations [Member] | NGL & Petchem Services [Member] | Service [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	0		0		0
Intersegment Eliminations [Member] | NGL & Petchem Services [Member] | Product [Member]
Reconciliation of segment revenues and segment profit (loss)
Total revenues	(294)		(258)		(56)
Corporate Non-Segment [Member]
Reconciliation of segment revenues and segment profit (loss)
Operating income	(160)		(184)		(118)
Total assets, investments and additions to long-lived assets by reporting segment
Total assets	147		409
Investments	0		0
Additions to long-lived assets	$ 5		$ 16		$ 25

[1] 2012 Additions to long-lived assets includes the Caiman and Laser Acquisitions. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)

[2] Eliminations primarily relate to the intercompany accounts receivable generated by our cash management program.

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Allocation of Net Income and Distributions (Tables)

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

Allocation of net income among our general partner, limited partners, and noncontrolling interests

The allocation of net income among our general partner, limited partners, and noncontrolling interests as reflected in the Consolidated Statement of Changes in Equity is as follows:

	Years Ended December 31,
	2013			2012			2011
	(Millions)
Allocation of net income to general partner:
Net income	$	1,070		$	1,232		$	1,511
Net income applicable to pre-partnership operations allocated to general partner	—			(185		)	(133		)
Net income applicable to noncontrolling interests	(3		)	—			—
Net costs charged directly to general partner	1			1			(2		)
Income subject to 2% allocation of general partner interest	1,068			1,048			1,376
General partner’s share of net income	2		%	2		%	2		%
General partner’s allocated share of net income before items directly allocable to general partner interest	21			21			28
Priority allocations, including incentive distributions, paid to general partner (1)	387			355			260
Net costs charged directly to general partner	(1		)	(1		)	2
Pre-partnership net income allocated to general partner interest	—			185			133
Net income allocated to general partner	$	407		$	560		$	423
Net income	$	1,070		$	1,232		$	1,511
Net income allocated to general partner	407			560			423
Net income allocated to noncontrolling interests	3			—			—
Net income allocated to common limited partners	$	660		$	672		$	1,088

____________

(1) The net income allocated to the general partner’s capital account reflects IDRs paid during the current reporting period. In the calculation of basic and diluted net income per common unit, the net income allocated to the general partner includes IDRs pertaining to the current reporting period but paid in the subsequent period.

Authorized payment of cash distributions

The following table sets forth the partnership cash distributions paid on the dates indicated, related to the preceding quarter (in millions, except for per unit amounts):

					General Partner
Payment Date	Per Unit Distribution		Common Units		2%		Incentive Distribution Rights		Total Cash Distribution
2/11/2011	$	0.7025	$	204	$	5	$	59	$	268
5/13/2011	0.7175		208		5		63		276
8/12/2011	0.7325		213		6		67		286
11/11/2011	0.7475		217		6		71		294
2/10/2012	0.7625		227		6		78		311
5/11/2012	0.7775		268		8		86		362
8/10/2012	0.7925		274		7		92		373
11/9/2012	0.8075		287		8		99		394
2/8/2013	0.8275		329		9		104		442
5/10/2013	0.8475		351		10		112		473
8/09/2013	0.8625		357		11		121		489
11/12/2013	0.8775		385		11		46		442
2/13/2014 (1)	0.8925		392		11		153		556

____________

(1) On February 13, 2014, we paid a cash distribution of $0.8925 per unit on our outstanding common units to unitholders of record at the close of business on February 6, 2014

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Acquisitions Goodwill and Other Intangible Assets (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended										2 Months Ended				4 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jun. 30, 2012	Dec. 31, 2013 Customer Contracts [Member]	Dec. 31, 2012 Customer Contracts [Member]	Dec. 31, 2013 Customer Relationships [Member]	Dec. 31, 2012 Customer Relationships [Member]	Dec. 31, 2013 Other Intangible Assets [Member]	Dec. 31, 2012 Other Intangible Assets [Member]	Feb. 17, 2012 Laser Acquisition [Member] Northeast G&P [Member]	Feb. 17, 2012 Laser Acquisition [Member] Northeast G&P [Member] Customer Contracts [Member]	Feb. 17, 2012 Laser Acquisition [Member] Northeast G&P [Member] Customer Relationships [Member]	Feb. 17, 2012 Laser Acquisition [Member] Northeast G&P [Member] Other Intangible Assets [Member]	Apr. 27, 2012 Caiman Acquisition [Member] Northeast G&P [Member]	Dec. 31, 2012 Caiman Acquisition [Member] Northeast G&P [Member]	Apr. 27, 2012 Caiman Acquisition [Member] Northeast G&P [Member] Customer Contracts [Member]	Apr. 27, 2012 Caiman Acquisition [Member] Northeast G&P [Member] Customer Relationships [Member]	Apr. 27, 2012 Caiman Acquisition [Member] Northeast G&P [Member] Other Intangible Assets [Member]
Business Acquisition, Entity Acquired and Reason for Acquisition [Abstract]
Business Acquisition, Percentage of Voting Interests Acquired				1.00%							100.00%				100.00%
Business Acquisition, Cost of Acquired Entity, Purchase Price [Abstract]
Business Acquisition, Cost of Acquired Entity, Cash Paid											$ 325				$ 1,720
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares											7,531,381				11,779,296
Business Acquisition, Cost of Acquired Entity, Equity Interests Issued and Issuable											441				603
Business Combination, Acquisition Related Costs																16
Business Acquisition, Purchase Price Allocation [Abstract]
Assets held-for-sale											18				0
Other current assets											3				16
Property, plant and equipment											158				656
Intangible assets												316	0	2			1,141	250	2
Current liabilities											(21)				(94)
Noncurrent liabilities											0				(3)
Identifiable net assets acquired											476				1,968
Goodwill	646	649									290				356
Total											766				2,324
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Finite-Lived Intangible Assets, Gross	1,747	1,747			1,493	1,493	250	250	4	4
Finite-Lived Intangible Assets, Accumulated Amortization	(105)	(45)			(88)	(38)	(14)	(6)	(3)	(1)
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life											30 years				30 years
Acquired Finite-lived Intangible Asset, Weighted-Average Period before Renewal or Extension											9 years				18 years
Amortization of Intangible Assets	60	43	2
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	60
Finite-Lived Intangible Assets, Amortization Expense, Year Two	60
Finite-Lived Intangible Assets, Amortization Expense, Year Three	60
Finite-Lived Intangible Assets, Amortization Expense, Year Four	60
Finite-Lived Intangible Assets, Amortization Expense, Year Five	$ 60

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Contingent Liabilities

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Contingent Liabilities

Note 14 – Contingent Liabilities and Commitments

Environmental Matters

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), and other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of December 31, 2013, we have accrued liabilities totaling $20 million for these matters, as discussed below. Our accrual reflects the most likely costs of cleanup, which are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. Certain assessment studies are still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty about the actual number of contaminated sites ultimately identified, the actual amount and extent of contamination discovered and the final cleanup standards mandated by the EPA and other governmental authorities.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. More recent rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, new air quality standards for ground level ozone, one hour nitrogen dioxide emission limits, and new air quality standards impacting storage vessels, pressure valves, and compressors. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.

Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At December 31, 2013, we have accrued liabilities of $13 million for these costs. We expect that these costs will be recoverable through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December 31, 2013, we have accrued liabilities totaling $7 million for these costs.

Geismar Incident

As a result of the previously discussed Geismar Incident, there were two fatalities and numerous individuals (including affiliate employees and contractors) reported injuries, which varied from minor to serious. We are cooperating with the Chemical Safety Board and the EPA regarding their investigations of the Geismar Incident. On October 21, 2013, the EPA issued an Inspection Report pursuant to the Clean Air Act’s Risk Management Program following its inspection of the facility on June 24 through 28, 2013. The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating procedures, employee training, and other matters.  We and the EPA continue to discuss such preliminary determinations, and the EPA could issue penalties pertaining to final determinations.  On December 11, 2013, the Occupational Safety and Health Administration (OSHA) issued Citations for the June 13, 2013 incident, which included a Notice of Penalty for $99,000. Although we and OSHA continue settlement negotiations, we are contesting the citation. On June 28, 2013, the Louisiana Department of Environmental Quality (LDEQ) issued a Consolidated Compliance Order & Notice of Potential Penalty to Williams Olefins, L.L.C. that consolidates claims of unpermitted emissions and other deviations under the Clean Air Act that the parties had been negotiating since 2010 and alleged unpermitted emissions arising from the Geismar Incident. Negotiations with the LDEQ are ongoing. Any potential fines and penalties from these agencies would not be covered by our insurance policy. Additionally, multiple lawsuits, including class actions for alleged offsite impacts, property damage, and personal injury, have been filed against various of our subsidiaries.

Due to the ongoing investigation into the cause of the incident, and the limited information available associated with the filed lawsuits, which do not specify any amounts for claimed damages, we cannot reasonably estimate a range of potential loss related to these contingencies at this time.

Rate Matters

On August 31, 2012, Transco submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in its prior rate proceedings. The new rates became effective March 1, 2013, subject to refund and the outcome of the hearing. On August 27, 2013, Transco filed a stipulation and agreement with the FERC proposing to resolve all issues in this proceeding without the need for a hearing (Agreement). On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement will become effective March 1, 2014. We have provided a reserve for rate refunds of $98 million, in Other accrued liabilities, which we believe is adequate for required refunds as of December 31, 2013, under the Agreement. Refunds will be made on or before April 30, 2014.

Other

In addition to the foregoing, various other proceedings are pending against us which are 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 disclose all significant matters for which we are unable to reasonably estimate a range of possible loss.

Commitments

Commitments for construction and acquisition of property, plant and equipment are approximately $1.4 billion at December 31, 2013.