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•	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.

(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.

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(1)	Excludes volumes associated with Partially Owned Entities.

(2)	Annual average Mbbls/d.

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(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.

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(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.

(1)	Excludes volumes associated with Partially Owned Entities.

(2)	Annual average Mbbls/d.

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(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.

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(1)	Annual average Mbbls/d.

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•	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.

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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.

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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.

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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.

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•	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.

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•	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.

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•	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.

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•	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.

•	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.

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•	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.

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

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

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

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

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•	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.

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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;

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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.

•	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.

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•	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.

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

•	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.

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•	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;

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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.

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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;

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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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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.

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•	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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•	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.

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(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.

•	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;

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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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•	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.

•	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.

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(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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•	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.

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•	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.

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•	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.

•	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.

•	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.

•	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.

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•	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.

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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.

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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.

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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.

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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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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.

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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.

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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.

•	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.

•	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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•	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.

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*	+ = 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.

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•	$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.

•	$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.

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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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•	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.

•	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).

•	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.

•	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.

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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).

•	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.

•	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.

•	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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•	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.

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

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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.

•	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.

•	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.

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•	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.

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

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

•	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.

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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.

•	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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•	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.

(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.

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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.

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•	$ 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.

•	$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.

•	$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.

•	$2.933 billion in capital expenditures;

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

•	$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.

•	$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.

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(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.)

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(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.

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•	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.

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

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•	Litigation-related contingencies;

•	Environmental remediation obligations;

•	Asset retirement obligations;

•	Acquisition related purchase price allocations.

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(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.

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(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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•	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.

•	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.

•	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.

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(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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•	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.

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(1)	Estimated useful life and depreciation rates are presented as of December 31, 2013. Depreciation rates for regulated assets are prescribed by the FERC.

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(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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•

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.

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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.

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•	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.

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(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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•	$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).

•	$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).

•	$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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•	$11 million of reorganization-related costs, including consulting costs, allocated to us from Williams (see Note 5 – Related Party Transactions).

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•	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).

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•	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;

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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;

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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.

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(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.

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(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.

*	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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*	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.

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•	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.

•	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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•	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.

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(a)	3 and (b). The following documents are included as exhibits to this report:

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