Williams Partners 8-K Other Events

Exhibit 99.1

DEFINITIONS

The following is a listing of certain abbreviations, acronyms and other industry terminology used throughout this Exhibit 99.1.

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:

Cardinal: Cardinal Gas Services, L.L.C.

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, as of December 31, 2014, 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

UEOM: Utica East Ohio Midstream LLC

Government and Regulatory:

EPA: Environmental Protection Agency

FERC: Federal Energy Regulatory Commission

IRS: Internal Revenue Service

SEC: Securities and Exchange Commission

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Other:

ACMP: Access Midstream Partners, L.P.

B/B Splitter: Butylene/Butane splitter

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

MVC: Minimum volume commitment

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

RGP Splitter: Refinery grade propylene splitter

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

Williams: The Williams Companies, Inc. and, unless the context otherwise indicates, its subsidiaries (other than Williams Partners L.P. and its subsidiaries)

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PART II

Item 6.Selected Financial Data

The following financial data at December 31, 2014 and 2013 and for each of the three years in the period ended December 31, 2014, should be read in conjunction with Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operationsand Item 8, Financial Statements and Supplementary Data of this Exhibit 99.1. All other financial data has been prepared from our accounting records.

	2014		2013		2012		2011		2010
	(Millions, except per-unit amounts)
Revenues (1)	$	7,409	$	6,835	$	7,471	$	7,916	$	6,625
Net income (1)	1,284		1,119		1,291		1,604		1,234
Net income attributable to controlling interests (1)	1,188		1,116		1,291		1,604		1,218
Net income per common unit (1)	.99		1.76		2.30		4.51		3.26
Total assets at December 31 (1) (3)	49,322		23,571		20,678		15,486		14,295
Commercial paper and long-term debt due within one year at December 31 (2)	802		225		—		324		458
Long-term debt at December 31 (1) (3)	16,326		9,057		8,437		6,913		6,365
Total equity at December 31 (1) (3)	28,685		11,567		9,691		6,122		5,826
Cash distributions declared per common unit	3.642		3.415		3.140		2.900		2.653

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(1) 2014 is impacted by the merger with ACMP. Because ACMP was under the common control of Williams effective July 1, 2014, the merger was accounted for as a common control transaction, whereby ACMP’s assets and liabilities were combined with ours at Williams’ historical carrying values and the historical results of ACMP’s operations were combined with ours beginning with the date (July 1, 2014) Williams obtained control of ACMP. Net income per common unit was recast for years prior to 2014 to reflect the surviving entity’s equity structure. The 2014 increase in Long-term debt reflects $2.8 billion in issuances as well as $4.1 billion in debt assumed as the result of the merger with ACMP.

(2) The increase in 2014 and 2013 reflects borrowings under our commercial paper program, which was initiated in 2013.

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

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

General

We are an energy infrastructure master limited partnership 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. WPZ GP LLC, a Delaware limited liability company wholly owned by Williams, is our general partner.

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 Access Midstream, Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services which are comprised of the following businesses as of December 31, 2014:

• Access Midstream provides domestic gathering, treating, and compression services to producers under long-term, fixed fee contracts. Its primary operating areas are in the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana; the Marcellus Shale region primarily in Pennsylvania and West Virginia, the Niobrara Shale region of eastern Wyoming, the Utica Shale region of eastern Ohio, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware and Permian Basins. Access Midstream also includes a 49 percent equity-method investment in UEOM, a 50 percent equity-method investment interest in the Delaware Basin gas gathering system in the Mid-Continent region, and Appalachia Midstream Services, LLC, which owns an approximate average 45 percent interest in 11 gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).

• Northeast G&P is comprised of midstream gathering and processing businesses in the Marcellus and Utica shale regions, as well as a 69 percent equity investment in Laurel Mountain and a 58 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 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, an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility and B/B splitter facility at Redwater, Alberta. This segment also includes an NGL and natural gas marketing business, storage facilities and an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity investment in OPPL.

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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.

Merger

Pursuant to an Agreement and Plan of Merger dated as of October 24, 2014, the general partners of Williams Partners L.P. and Access Midstream Partners, L.P. agreed to combine those businesses and their general partners, with Williams Partners L.P. merging with and into Access Midstream Partners, L.P. and the Access Midstream Partners, L.P. general partner being the surviving general partner (the Merger). Following the completion of the Merger on February 2, 2015, as further described below, the surviving Access Midstream Partners, L.P. changed its name to Williams Partners L.P., and the surviving general partner changed its name to WPZ GP LLC. For the purpose of this discussion, Williams Partners L.P. (WPZ) refers to the renamed merged partnership, while Pre-merger Access Midstream Partners, L.P. (Pre-merger ACMP) and Pre-merger Williams Partners L.P. (Pre-merger WPZ) refer to the separate partnerships prior to the consummation of the Merger and subsequent name change.

In accordance with the terms of the Merger, each Pre-merger ACMP unitholder received 1.06152 Pre-merger ACMP units for each Pre-merger ACMP unit owned immediately prior to the Merger. In conjunction with the Merger, each Pre-merger WPZ common unit held by the public was exchanged for 0.86672 common units of Pre-merger ACMP. Each Pre-merger WPZ common unit held by Williams was exchanged for 0.80036 common units of Pre-merger ACMP. Prior to the closing of the Merger, the Class D limited partner units of Pre-merger WPZ, all of which were held by Williams, were converted into Pre-merger WPZ common units on a one-for-one basis pursuant to the terms of the partnership agreement of Pre-merger WPZ. All of the general partner interests of Pre-merger WPZ were converted into general partner interests of Pre-merger ACMP such that the general partner interest of Pre-merger ACMP represents 2 percent of the outstanding partnership interest. Following the Merger, Williams owns approximately 60 percent of the merged partnership, including the general partner interest and IDRs.

Because the Merger was between entities under common control, Pre-merger ACMP’s historical financial position, results of operations, and cash flows were combined with those of Pre-merger WPZ for periods during which Pre-merger ACMP was under common control of Williams (periods subsequent to July 1, 2014). Both Pre-merger WPZ and Pre-merger ACMP are reflected at Williams’ historical basis in both partnerships.

Distributions

In January 2015, our general partner’s Board of Directors approved a quarterly distribution to unitholders of $0.85 per unit.

Overview

Net income attributable to controlling interests for the year ended December 31, 2014, improved compared to the prior year. The current year improvement includes contributions from Access Midstream since July 1, 2014. Other significant fluctuations include lower NGL margins driven by lower volumes and lower olefin margins associated with the absence of volumes from our Geismar plant partially offset by related insurance recoveries. Interest expense increased due to higher debt levels, partially offset by higher fee-based revenues. See additional discussion in Results of Operations.

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

Canada Acquisition

On February 28, 2014, we acquired certain of Williams’ Canadian operations for total consideration valued at approximately $1.2 billion. The operations included an oil sands offgas processing plant near Fort McMurray, Alberta, an NGL/olefin fractionation facility and B/B Splitter facility at Redwater, Alberta. We funded the transaction with $56 million of cash including $31 million that was paid in the second quarter, the issuance of 25,577,521 Pre-merger WPZ Class D limited-partner units, and an increase in the capital account of our general partner to allow it to maintain its 2

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percent general partner interest. In lieu of cash distributions, the Class D units received quarterly distributions of additional paid-in-kind Class D units. 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 October 2014, a purchase price adjustment was finalized whereby we received $56 million in cash from Williams in the fourth quarter 2014and Williams waived $2 million in payments on its IDRs with respect to Pre-merger WPZ’s November 2014 distribution.

Geismar Incident

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. This facility is part of our NGL & Petchem Services segment.

At the time of the incident, we had 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.

During the year ended December 31, 2014, we received$246 million of insurance recoveries related to the Geismar Incident and incurred $14 million of related covered insurable expenses in excess of our retentions (deductibles). These amounts are reflected as a net gain in Net insurance recoveries- Geismar Incident within Costs and expenses in our Consolidated Statement of Comprehensive Income.

We expect our total loss to exceed our $500 million policy limit, which would result in a total claim of approximately $72 millionrelated to the repair of the plant and the remainder related to business interruption. Through December 31, 2014, we have received a total of $296 million from insurers. We continue to work with insurers in support of all claims, as submitted, and are vigorously pursuing collection of the remaining $200 million insurance limits.

Further, 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 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.

Our Geismar plant, which restarted in February 2015, is expected to continue to ramp up to expanded capacity through March. Production during February and March is expected to be intermittent, resulting in limited financial contribution for the first quarter.

Northeast G&P

Marcellus Shale

In the first half of 2014, we added: (1) fractionation capacity at our Moundsville fractionator facility bringing the NGL handling capacity to approximately 42.5Mbbls/d, (2) the associated 50-mile ethane pipeline to Houston, Pennsylvania, and (3) the first phase to the condensate stabilization project in the Marcellus Shale. In the third quarter of 2014, we completed the construction of our first deethanizer with a capacity of 40 Mbbls/d; and in the fourth quarter of 2014,we completed our first turbo-expander at our Oak Grove facility to add 200 MMcf/d of processing capacity and the last phase of the condensate stabilization project.

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Caiman II

As a result of contributions made in the first quarter of 2014, our ownership in the Caiman II joint project increased to 58 percent. These contributions are used to fund Caiman II’s 50 percent investment in Blue Racer Midstream LLC (Blue Racer Midstream).

Through capital invested within our Caiman II equity investment, we began construction of the Blue Racer Midstream joint project in 2014. Blue Racer Midstream is an expansion of the gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica Shale, primarily in Ohio and Northwest Pennsylvania. Expansion plans included the addition of Natrium II, a second 200 MMcf/d processing plant at Natrium, West Virginia, which was completed in April 2014. Construction of an additional 200 MMcf/d processing plant is underway at the Berne complex in Monroe County, Ohio. Berne I was placed into service in January 2015.

Atlantic-Gulf

Gulfstar One

During the fourth quarter of 2014, we completed the Gulfstar FPS™, which is a proprietary floating production system that had been under construction since late 2011. It is supported by multiple agreements with two major producers to provide production handling, 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™ ties into our wholly owned oil and gas gathering and gas processing systems in the eastern Gulf of Mexico. Gulfstar FPS™ has 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. We own a 51 percent interest in Gulfstar One. 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 project has a first oil target of the first quarter of 2016, dependent on the producer’s development activities.

New Transco rates effective

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 a 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 became effective March 1, 2014. We paid $118 million of rate refunds on April 18, 2014.

Keathley Canyon Connector™

Discovery constructed a 215-mile, 20-inch deepwater lateral pipeline in the central deepwater Gulf of Mexico that it owns and operates. 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 originates from a third-party floating production facility in the southeast portion of the Keathley Canyon area and connects to Discovery’s existing 30-inch offshore natural gas transmission system. The gas is processed at Discovery’s Larose Plant and the NGLs are 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 was put into service in the first quarter 2015.

NGL & Petchem Services

Williams has announced that it plans to drop-down its remaining NGL & Petchem Services assets. This transaction is expected to take place in the future. The transaction is subject to execution of an agreement, review, and recommendation by the Conflicts Committee of our general partner, and approval of both Williams’ and our Board of Directors.

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Volatile Commodity Prices

NGL margins were approximately25percent lower in 2014 compared to 2013, driven primarily by lower volumes and higher natural gas prices. Volumes declined primarily due to a customer contract in the West that expired in September 2013. Due to unfavorable ethane economics, we further reduced our recoveries of ethane in our domestic plants in 2014 compared to 2013. These reductions are substantially offset by new volumes generated by our Canadian ethane recovery facility which was placed into service in December 2013. Despite the sharp decline in NGL prices during the fourth quarter of 2014, NGL prices on average, were higher in 2014 compared to 2013.

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 margin 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.

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Following the sharp decline in energy commodity prices in fourth quarter 2014, we expect crude oil, NGLs, and olefins prices to remain at lower levels throughout 2015 as compared to 2014, which will have an adverse effect on our operating results and cash flows. Fee-based businesses are a significant component of our portfolio and have further increased as a result of the Merger. This serves to somewhat reduce the influence of commodity price fluctuations on our operating results and cash flows. However, due in part to lower natural gas prices, we anticipate that overall producer drilling economics will decrease slightly. This may reduce our gathering volumes available for both fee-based and keep-whole processing.

Our business plan for 2015 continues to reflect both significant capital investment and growth in distributions as compared to 2014. We continue to manage expenditures as appropriate without compromising safety and compliance. Our planned capital investments for 2015 total between $3.68 billion and $4.23 billion. 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;

• Lower than anticipated energy commodity prices and margins;

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

• 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;

• Downgrade of our investment grade credit rating and associated increase in cost of borrowings;

• Counterparty credit and performance risk;

• 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 2015, we anticipate an overall improvement in operating results compared to 2014 primarily due to increases in olefins volumes associated with the repair and expansion of the Geismar plant and our fee-based businesses primarily a result of the Merger, 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 2015.

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

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impacted by global supply and demand fundamentals. 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. We continue to benefit from our strategic feedstock cost advantage in propylene production from Canadian oil sands offgas.

Following the sharp decline in the fourth quarter of 2014, we anticipate the following trends in overall energy commodity prices in 2015, compared to 2014:

• Natural gas and ethane prices are expected to be at or below 2014 levels primarily due to higher inventory levels.

• Non-ethane prices, including propane, are expected to be lower primarily due to oversupply and the sharp decline in crude oil prices.

• Olefins prices, including propylene, ethylene, and the overall ethylene crack spread, are expected to be lower than 2014 levels due to the volatility in the price of crude oil and correlated products.

Gathering, transportation, 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.

• Following the Merger, Pre-merger ACMP’s results of operations were combined with those of Pre-merger WPZ for periods under common control (periods subsequent to July 1, 2014). As such, we expect an increase in overall results for the Access Midstream segment in 2015 compared to 2014 associated with a full year of results.

• In our Atlantic-Gulf segment, we expect higher production handling volumes compared to 2014, following the completion of Gulfstar FPS™ in the fourth quarter of 2014. We also anticipate higher natural gas transportation revenues compared to 2014, as a result of expansion projects placed into service at Transco in 2014 and anticipated to be placed in service in 2015.

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

• In our Access Midstream segment, we expect an increase in volumes in 2015 as compared to 2014 in the Haynesville area primarily due to an increase in customer rig counts. We also expect an increase in volumes in the Utica area primarily due to the build out of the Cardinal system, relieving compression constraints and adding new well connections.

• Our West segment expects an unfavorable impact in equity NGL volumes in 2015 compared to 2014, primarily due to the sharp decline in NGL prices.

• In 2015, we anticipate a continuation of periods when it will not be economical to recover ethane in our domestic businesses.

Olefin production volumes

• Our NGL & Petchem Services segment anticipates higher ethylene volumes in 2015 compared to 2014 substantially due to the repair and expansion of the Geismar plant, which restarted in February of 2015.

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Other

• In our Atlantic-Gulf segment, we expect higher equity earnings compared to 2014 following the completion of Discovery’s Keathley Canyon Connector™ lateral in the first quarter of 2015.

• In our Access Midstream segment, we anticipate an increase in amounts recognized under minimum volume commitments in 2015 compared to 2014 in the Barnett area.

• We anticipate higher operating expenses in 2015 compared to 2014, including depreciation expense related to our growing operations in our Northeast G&P segment and expansion projects in our Atlantic-Gulf segment.

Expansion Projects

We expect to invest between $3.25 billion and $3.8 billion of capital among our business segments in 2015. Our ongoing major expansion projects include the following:

Northeast G&P

• We plan to expand our processing capacity at our Oak Grove facility by adding a second 200MMcf/d cryogenic natural gas processing plant, which is expected to be placed into service at the end of 2015.

• We will continue to expand the gathering system in the Susquehanna Supply Hub in northeastern Pennsylvania that is needed to meet our customer’s production plans. The expansion of the gathering infrastructure includes additional compression and gathering pipeline to the existing system.

Atlantic-Gulf

• The Atlantic Sunrise Expansion Project involves an expansion of Transco’s 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 December 2014, we received approval from 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 a portion of the project into service in March 2015, which will enable us to begin providing firm transportation service through the mainline portion of the project on an interim basis, until the in-service date of the project as a whole. We plan to place the remainder of the project into service during the fourth quarter of 2015 and expect it to increase capacity by 525 Mdth/d.

• In April 2014, we received approval from the FERC to construct and operate 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 December 2014, we received approval from the FERC to construct and operate the jointly owned Constitution pipeline. We also received a Notice of Complete Application from the New York Department of Environmental Conservation in December 2014. 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 124-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 the second half of 2016, assuming timely receipt of all necessary regulatory approvals, with an expected capacity of 650 Mdth/d. The pipeline is fully subscribed with two shippers.

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• In May 2014, we received FERC approval for Transco’s Northeast Connector project to expand our existing natural gas transmission system from southeastern Pennsylvania to the proposed Rockaway Delivery Lateral. In December 2014, we placed a portion of the project into service, which enabled us to begin providing 65 Mdth/d of firm transportation from Station 195 to the Rockaway Delivery Lateral junction. We plan to place the remainder of the project into service duringthe second quarter of 2015. In total, the project is expected to increase capacity by 100 Mdth/d.

• In May 2014, we received FERC approval 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 quarter of 2015, and the capacity of the lateral is expected to be 647 Mdth/d.

• In November 2013, we received approval from 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 delivery points in North Carolina. In December 2014, we placed a portion of the project into service, which enabled us to begin providing 250 Mdth/d of firm transportation capacity through the mainline portion of the project on an interim basis, until the in-service date of the project as a whole. We plan to place the remainder of the project into service during the third quarter of 2015. In total, the project is expected to increase capacity by 270 Mdth/d.

• In June 2014, we filed an application with the FERC for Transco’s Rock Springs Expansion project to expand our existing natural gas transmission system from New Jersey to a proposed generation facility in Maryland. The project is planned to be placed into service in third quarter 2016, assuming timely receipt of all necessary regulatory approvals, and is expected to increase capacity by 192 Mdth/d.

• In November 2014, we filed an application with the FERC for approval of the initial phases of Transco’s Hillabee Expansion project, which involves an expansion of our existing natural gas transmission system from our Station 85 in Alabama to a proposed new interconnection with Sabal Trail Transmission's system in Alabama. The project will be constructed in phases, and all of the project expansion capacity will be leased to Sabal Trail Transmission. We plan to place the initial phases of the project into service during the second quarter of 2017, assuming timely receipt of all necessary regulatory approvals, and together they are expected to increase capacity by 1,025 Mdth/d.

• In December 2014, we filed an application with the FERC for Transco’s Gulf Trace Expansion Project to expand our existing natural gas transmission system together with greenfield facilities to provide firm transportation from Station 65 in St. Helena Parish, Louisiana westward to a new interconnection with Sabine Pass Liquefaction in Cameron Parish, Louisiana. 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 1,200 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-2018. We will continue to monitor the situation to determine whether a different in-service date is warranted.

NGL & Petchem Services

• In association with Williams’ long-term agreement to provide gas processing to a second bitumen upgrader in Canada’s oil sands near Fort McMurray, Alberta, we have a long-term agreement with Williams to provide NGL transportation and fractionation services and are increasing the capacity of the Redwater facilities where NGL/olefins mixtures will be fractionated into an ethane/ethylene mix, propane, polymer grade propylene, normal butane, an alkylation feed and condensate. This capacity increase at Redwater is expected to be placed into service during the fourth quarter of 2015. We will receive a fee-based payment from Williams for the fractionation service we provide to it.

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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, 2014, our Consolidated Balance Sheet includes $1.1 billion of goodwill, of which $474 million is associated with the reporting units representing the northeast, central, and west regions within our Access Midstream segment and $646 million is associated with our Northeast G&P segment. The goodwill within the Access Midstream segment was recorded in the third quarter of 2014 in conjunction with Williams’ acquisition of Pre-merger ACMP completed on July 1, 2014. (See Note 2 of Notes to Consolidated Financial Statements.) We performed our annual assessment of goodwill for impairment as of October 1 and no impairments were identified or recognized.

Following a significant decline in energy commodity prices in the fourth quarter of 2014, we performed an additional review of our Northeast G&P segment. In our evaluation of our Northeast G&P segment, our estimate of the fair value of the reporting unit exceeded its carrying value by 30 percent, including goodwill, and thus, no impairment was recognized in 2014. The fair value of our Northeast G&P segment was estimated by an income approach utilizing discounted cash flows and corroborated with a market capitalization analysis.

As a result of the decline in energy commodity prices and a decline in the trading price of ACMP's publicly-traded limited partner units, both in the fourth quarter of 2014, we performed an additional impairment evaluation as of December 31, 2014, of the goodwill allocated to the reporting units within the Access Midstream segment. We estimated the fair value of each reporting unit identified above based on an income approach that utilized a discount rate of 7.25 percent, as well as a market approach that considered appropriate peer transactions and companies, all of which was corroborated with a market capitalization analysis. In this evaluation, our estimate of the fair value of each reporting unit exceeded the related carrying value, and thus, no impairment losses were recognized in 2014. We estimate that a 75 basis point increase in the discount rate utilized could result in a partial impairment of this goodwill.

Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and market measures 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.

Equity-method Investments

At December 31, 2014, our Consolidated Balance Sheet includes approximately $8.4 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;

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• 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, 2014.

Impairment of Long-lived Assets

We evaluate our long lived assets for impairment when events or changes in circumstances indicate, in our management's judgment, that the carrying value of such assets may not be recoverable. When an indicator of a potential impairment has occurred, we compare our management's estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred.

In December 2010 we detected a leak in one of the seven underground natural gas storage caverns at our Eminence Storage Field in Covington County, Mississippi. Due to the leak at this cavern, damage to the well at an adjacent cavern, and operating problems at two other caverns constructed at about the same time, we determined that the four caverns should be retired, which was completed in 2014. In addition, further studies have indicated the need for capital improvements over the next several years of the remaining three caverns. As a result, we performed an assessment of our Eminence storage field for impairment as of December 31, 2014. The carrying value at that date was $78 million. These events have not affected the performance of our obligations under our service agreements with our customers. However, judgments and assumptions are inherent in our estimate of future cash flows used to evaluate Eminence. In our evaluation, our estimate of the undiscounted cash flows of Eminence exceeded its carrying value, and thus no impairment loss was recognized in 2014. If our estimates of revenues were to significantly decrease, it could result in a write down of this asset to fair value.

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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, 2014. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

	Years Ended December 31,
	2014			$ Change from 2013*	% Change from 2013*		2013			$ Change from 2012*	% Change from 2012*		2012
	(Millions)
Revenues:
Service revenues	$	3,888		+974	+33	%	$	2,914		+200	+7	%	$	2,714
Product sales	3,521			-400	-10	%	3,921			-836	-18	%	4,757
Total revenues	7,409						6,835						7,471
Costs and expenses:
Product costs	3,016			+11	—	%	3,027			+474	+14	%	3,501
Operating and maintenance expenses	1,277			-197	-18	%	1,080			-61	-6	%	1,019
Depreciation and amortization expenses	1,151			-360	-46	%	791			-57	-8	%	734
Selling, general, and administrative expenses	633			-114	-22	%	519			+64	+11	%	583
Net insurance recoveries – Geismar Incident	(232		)	+192	NM		(40		)	+40	NM		—
Other (income) expense – net	(45		)	+96	NM		51			-27	-113	%	24
Total costs and expenses	5,800						5,428						5,861
Operating income	1,609						1,407						1,610
Equity earnings (losses)	228			+124	+119	%	104			-7	-6	%	111
Interest expense	(562		)	-175	-45	%	(387		)	+17	+4	%	(404		)
Other income (expense) – net	38			+13	+52	%	25			+9	+56	%	16
Income before income taxes	1,313						1,149						1,333
Provision (benefit) for income taxes	29			+1	+3	%	30			+12	+29	%	42
Net income	1,284						1,119						1,291
Less: Net income attributable to noncontrolling interests	96			-93	NM		3			-3	NM		—
Net income attributable to controlling interests	$	1,188					$	1,116					$	1,291

* + = 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.

2014 vs. 2013

Service revenues increased primarily due to contributions from Access Midstream beginning in third quarter 2014, including $167 million of minimum volume commitment fees. Gathering fees increased driven by higher volumes and a net increase in gathering rates primarily in the Susquehanna Supply Hub. Natural gas transportation fee revenues increased primarily associated with expansion projects placed in service at Transco in 2013. In addition, Service revenues increased related to new processing, fractionation, and transportation fees from Ohio Valley Midstream facilities that were placed in service in 2013 and 2014.

Product sales decreased primarily due to lower olefin sales volumes associated with the lack of production in 2014 as a result of the Geismar Incident, partially offset by an increase in olefin sales on the RGP splitter primarily associated with higher volumes. In addition, equity NGL sales decreased primarily reflecting lower non-ethane volumes, partially offset by higher average ethane per-unit sales prices. Crude oil, natural gas, and other marketing revenues decreased

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primarily related to lower volumes, while NGL marketing revenues increased primarily related to higher volumes partially offset by lower NGL prices.

Product costs decreased primarily due to lower olefin feedstock purchases related to the lack of production in 2014 as a result of the Geismar Incident. In addition, natural gas purchases associated with the production of equity NGLs decreased slightly reflecting lower volumes, which were substantially offset by higher natural gas prices. These decreases were partially offset by an increase in lower-of-cost-or-market adjustments due to significant declines in NGL prices during the fourth quarter of 2014 and lower crude oil, natural gas and olefin volumes, partially offset by higher NGL volumes.

Operating and maintenance expenses increased primarilydue to expenses associated with Access Midstream beginning in third quarter 2014, including $15 million of transition-related costs, expenses incurred in 2014 associated with the installation of certain safety equipment at the Geismar plant, and higher maintenance and growth in our Northeast G&P operations. These increases were partially offset due primarily to a net increase in system gains, and reduced gathering fuel expense in the West operations.

Depreciation and amortization expenses increased primarily due to expenses associated with Access Midstream beginning in third quarter 2014 and due to depreciation on new projects placed in service.

Selling, general, and administrative expenses (SG&A) increased primarily due to expenses associated with Access Midstream beginning in third quarter 2014, including $42 million of acquisition, merger, and transition-related costs recognized in 2014. In addition, SG&A increased related to operational growth in our Northeast G&P operations.

The favorable change in Net insurance recoveries — Geismar Incident is primarily due to the receipt of $246 million of insurance recoveries in 2014, compared to the receipt of $50 million of insurance recoveries in 2013. (See Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements.)

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

• $154million of cash proceeds received in 2014 related to a contingency settlement gain;

• The absence of a $25 million accrued loss recognized in 2013 associated with a producer claim against us;

• The absence of $12 million of expense recognized in 2013 and $3 million of expense reversal in 2014, related to the portion of the Eminence abandonment regulatory asset that will not be recovered in rates;

• A $12 million net gain recognized in 2014 related to the settlement of a partial acreage dedication release.

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

• $52 million of impairment charges recognized in 2014 related to certain materials and equipment;

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

• A $10 million loss on the sale of certain assets in 2014;

• $9 million of expenses in excess of the insurable limit associated with the Geismar Incident;

• A $9 million increase in expenses associated with a regulatory liability for certain employee costs;

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

Operating income changed favorably primarily due to increased service revenues of $193 million related to our pre-merger operations, a $192 million increase in net insurance recoveries related to the Geismar Incident, $167 million

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of minimum volume commitment fee revenue at Access Partners, and $154 million of cash proceeds in 2014 related to a contingency gain settlement. These increases are partially offset by $192 million lower olefin margins, $130 million lower NGL margins and $59 million lower marketing margins, as well as higher operating costs and higher impairment charges recognized in 2014.

Equity earnings (losses) changed favorably primarily due to the recognition of $96 million of equity earnings in the second half of 2014 related to equity investments held by Access Midstream, and higher equity earnings from Caiman II and Laurel Mountain.

Interest expense increased due to a $206 million increase in Interest incurred primarily due to new debt issuances in the fourth quarter of 2013 and the first half of 2014, as well as expense associated with Access Midstream’s debt beginning in the third quarter of 2014, and $9 million of Access Midstream acquisition-related financing costs incurred in 2014. The increase in Interest incurred is partially offset by an increase of $31 million in Interest capitalized related to construction projects in progress. (See Note 2 – Acquisitionsand Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)

Other income (expense) – net changed favorably primarily due to the benefit from the allowance for equity funds used for construction associated with ongoing capital projects within our regulated operations.

Provision (benefit) for income taxes changed favorably primarily due to the absence of Texas franchise tax incurred related to a second-quarter 2013 tax law change, partially offset by an unfavorable increase due to higher foreign pre-tax income associated with our Canadian operations.

Net income attributable to noncontrolling interests changed unfavorably due to income allocated to Pre-merger ACMP interests held by the public that is presented within noncontrolling interests for periods prior to consummation of the Merger.

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.

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, scheduled maintenance expenses incurred at our Canadian olefins facility, 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

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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, increased depreciation of certain assets that were decommissioned in the third quarter of 2013 in preparation of the completion of the ethane recovery system, as well as higher depreciation related to the Boreal Pipeline, which was placed into service in 2012. These increases are 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 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 of Notes to Consolidated Financial Statements).

The favorable change in Net insurance recoveries — Geismar Incident is primarily due to the receipt of $50 million of insurance recoveries in 2013 (seeNote 7 – Other Income and Expenses of Notes to Consolidated Financial Statements.)

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.

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

• $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;

• $5 million favorable change in net foreign currency exchange gains.

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

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

Interest expense decreased due to a $36 million increase in Interest capitalized related to construction projects, partially offset by a $19 million increase in Interest incurred primarily due to an increase in borrowings. (See Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)

Provision (benefit) for income taxes changed favorably primarily due to lower foreign pre-tax income associated with our Canadian operations, partially offset by Texas franchise tax incurred related to the impact of a second-quarter 2013 tax law change.

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Year-Over-Year Operating Results – Segments

Access Midstream

	Year Ended December 31, 2014
	(Millions)
Service revenues	$	781
Segment revenues	781
Depreciation and amortization expenses	296
Other segment costs and expenses	316
Equity (earnings) losses	(96		)
Segment profit	$	265

The results of operations for the Access Midstream segment are only presented for periods under common control (periods subsequent to July 1, 2014) and are reflected at Williams’ historical basis in the underlying operations (see Note 2 – Acquisitions).

Segment revenues are supported by minimum volume commitments associated with gas gathering agreements with certain producers in the Barnett Shale and Haynesville Shale areas. In 2014, we recognized $167 millionrelatedto these minimum volume commitment contracts.

Northeast G&P

	Years Ended December 31,
	2014			2013			2012
	(Millions)
Service revenues	$	451		$	335		$	168
Product sales	230			166			2
Segment revenues	681			501			170
Product costs	221			160			4
Depreciation and amortization expenses	170			132			76
Other segment costs and expenses	97			226			104
Equity (earnings) losses	(19		)	7			23
Segment profit (loss)	$	212		$	(24	)	$	(37	)

2014 vs. 2013

Service revenues increased primarily due to $88 million higher gathering fees associated with 30 percent higher volumes driven by new well connections and the completion of various compression projects, and a net increase in gathering rates associated with customer contract modifications, primarily in the Susquehanna Supply Hub. Service revenues also increased $22 million due to contributions from our Ohio Valley Midstream business resulting from the addition of processing, fractionation, and transportation facilities placed in service in 2013 and 2014.

Product sales increased due primarily to growth in the NGL marketing activities attributable to the Ohio Valley Midstream business. The changes in marketing revenues are partially offset by similar changes in marketing purchases, reflected above as Product costs.

Depreciation and amortization expenses increased due to new projects placed in service.

Other segment costs and expenses decreased primarily due to $154 million of cash received in the fourth quarter of 2014 associated with the resolution of a contingent gain related to claims arising from the purchase of a business in a prior period (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements), the absence

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of a $25 million accrued loss incurred in 2013 associated with a producer claim against us, and a $12 million net gain in 2014 related to a partial acreage dedication release. These decreases are partially offset by $30 million of impairment charges related to certain materials and equipment, $6 million of costs resulting from fire damages at a compressor station in the Susquehanna Supply Hub, and higher expenses associated with maintenance and growth in these operations.

Equity (earnings) losses changed favorably due primarily to $14 million higher equity earnings from Caiman II resulting primarily from business interruption insurance proceeds received in 2014 and higher volumes due to assets placed into service in 2014. In addition, Laurel Mountain equity earnings increased $12 million primarily due to 20 percent higher gathering volumes, an 18 percent increased ownership percentage beginning in fourth quarter 2014, and the absence of certain write-offs in 2013.

The favorable change in Segment profit (loss)is primarily due to the cash received from the fourth quarter 2014 settlement discussed previously and an increase in service revenues, partially offset by higher depreciation and higher expenses associated with growth in these operations.

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 loss for 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 loss for a producer claim against us.

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Atlantic-Gulf

	Years Ended December 31,
	2014			2013			2012
	(Millions)
Service revenues	$	1,501		$	1,424		$	1,383
Product sales	853			925			1,072
Segment revenues	2,354			2,349			2,455
Product costs	791			843			956
Depreciation and amortization expenses	379			363			381
Other segment costs and expenses	625			601			636
Equity (earnings) losses	(76		)	(72		)	(92		)
Segment profit	$	635		$	614		$	574
NGL margin	$	57		$	79		$	113

2014 vs. 2013

Service revenues increased primarily due to a $71 million increase in Transco’s natural gas transportation fee revenues primarily associated with expansion projects placed in service and new rates effective in 2013. Additionally, Gulfstar One fees were $19 million in 2014 due to the start-up of operations. Western Gulf Coast fees increased $8 million associated with increased production and a short-term increase in volumes. These increases are partially offset by lower production handling and crude oil transportation fee revenues in the eastern Gulf Coast primarily driven by lower Bass Lite production area volumes, natural declines of other fields, and producers’ operational issues.

Product sales decreased primarily due to:

• A $61 million decrease in marketing revenues reflecting a decrease in crude oil marketing sales, partially offset by an increase in NGL marketing sales. Crude oil marketing sales decreased primarily due to lower crude oil volumes related to natural declines in production areas served by our Mountaineer crude oil pipeline. NGL marketing sales increased primarily due to higher NGL volumes associated with a short-term increase in production in the western Gulf Coast. These changes in marketing revenues are offset by similar changes in marketing purchases;

• A $25 million decrease in revenues from our equity NGLs reflecting lower equity NGL sales volumes. Equity NGL sales volumes are 28 percent lower driven by 25 percent lower non-ethane volumes as a result of customer contract changes and producers’ operational issues;

• An $8 million increase in 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 $60 million decrease in marketing purchases (offset in Product sales);

• An $8 million increase in system management gas costs (offset in Product sales).

Depreciation and amortization expenses increased primarily due to the Gulfstar FPS™ and associated pipelines, which were placed in service in the fourth quarter of 2014.

Other segment costs and expenses increased due to an increase in other materials and supplies cost, miscellaneous contractual services costs primarily due to various repairs and maintenance projects, and impairment charges recognized in 2014 related to certain materials and equipment.

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Segment profit increased primarily due to higher service revenues, partially offset by $22 million lower NGL margins reflecting lower volumes, and higher Other segment costs and expenses and depreciation, as previously discussed.

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 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.

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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.

West

	Years Ended December 31,
	2014		2013		2012
	(Millions)
Service revenues	$	1,034	$	1,054	$	1,072
Product sales	546		772		1,129
Segment revenues	1,580		1,826		2,201
Product costs	270		380		472
Depreciation and amortization expenses	239		236		234
Other segment costs and expenses	440		469		515
Segment profit	$	631	$	741	$	980
NGL margin	$	255	$	369	$	637

2014 vs. 2013

Service revenues decreased primarily due to an $18 million decrease in gathering and processing fees driven by lower volumes associated with natural declines, certain contract changes, and lower margins from commodity-based fees, partially offset by an increase in minimum volume fees.

Product sales decreased primarily due to:

• A $156 million decrease in revenues from our equity NGLs primarily reflecting a decrease of $144 million due to lower volumes and $12 million primarily due to 2 percent lower average non-ethane per-unit sales prices driven by the significant decline in energy commodity prices during the fourth quarter of 2014. Lower volumes are driven by a 24 percent decrease in non-ethane volumes primarily due to a customer contract that expired in September 2013.

• A $74 million decrease in NGL marketing revenues primarily due to lower volumes largely related to the expiration of a customer contract, as well as lower per-unit prices (offset in Product costs).

Product costs decreased primarily due to:

• A $76 million decrease in NGL marketing purchases (offset in Product sales).

• A $42 million decrease in natural gas purchases associated with the production of equity NGLs reflecting a $67 million decrease related to lower volumes, partially offset by a $25 million increase driven by higher per-unit natural gas costs.

The decrease in Other segment costs and expenses is primarily due to a $21 million net increase in system gains and $11 million in reduced gathering fuel expense.

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Segment profit decreased primarily due to $114 million lower NGL margins and lower Service revenues, partially offset by a net increase in system gains and reduced gathering fuel expense. The decrease in NGL margins reflects lower NGL volumes, higher per-unit natural gas costs, and slightly lower average non-ethane sales prices driven by the significant decline in energy commodity prices during the fourth quarter of 2014.

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 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.

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NGL & Petchem Services

	Years Ended December 31,
	2014			2013			2012
	(Millions)
Service revenues	$	126		$	112		$	108
Product sales	2,986			3,155			4,264
Segment revenues	3,112			3,267			4,372
Product costs	2,829			2,753			3,797
Depreciation and amortization expenses	67			60			43
Other segment (income) costs and expenses	(12		)	147			184
Equity (earnings) losses	(37		)	(39		)	(42		)
Segment profit	$	265		$	346		$	390
Olefins margin	$	110		$	302		$	392
Marketing margin	(31		)	21			(11		)
NGL margin	68			64			74

2014 vs. 2013

Product sales decreased primarily due to:

• A $252 million decrease in olefin sales due to $256 million of lower sales volumes, partially offset by $4 million higher per-unit sales prices. Lower sales volumes are primarily due to a $295 million decrease in volumes at our Geismar facility due to the lack of production in 2014 as a result of the Geismar Incident, partially offset by a $32 million increase in volumes at our RGP Splitter primarilydue to a third-party storage facility being back in operation in the fourth quarter of 2014 after an outage during the latter part of 2013 and the first part of 2014, which caused us to reduce production during this period (substantially offset in Product costs). These lower volumes were also offset by a net $4 million in higher per-unit sales prices consisting of a $10 million increase in our RGP Splitter per-unit sales prices partially offset by a $6 million decrease in our Canadian alky feedstock per-unit sales prices (substantially offset in Product costs).

• A $46 million increase in NGL sales revenues primarily due to new Canadian ethane volumes generated by the ethane recovery project placed in service in December 2013. Non-ethane per-unit sales prices were also higher, partially offset by lower non-ethane sales volumes driven primarily by changes in inventory management of propane and unfavorable changes in the composition of off-gas feedstock.

• A $46 million increase in marketing revenues due primarily to higher ethane and non-ethane volumes partially offset by lower non-ethane prices (more than offset in Product Costs).

Product costs increased primarily due to:

• A $98 million increase in marketing purchases primarily due to increased NGL volumes as well as $27 million in lower of cost or market adjustments in 2014 compared to $3 million in lower of cost or market adjustments in 2013 (partially offset in Product Sales).

• A $42 million increase in costs associated with our Canadian NGLs primarily due to new ethane volumes generated by the ethane recovery project and higher natural gas prices, partially offset by lower natural gas volumes associated with the production of non-ethane NGLs.

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• A $60 million decrease in olefin feedstock purchases primarily due to a $99 million decrease in volumes at our Geismar facility due to the lack of production in 2014 as a result of the Geismar Incident. This decrease is partially offset by a $29 million increase in volumes at our RGP Splitter primarilydue to a third-party storage facility being back in operation in the fourth quarter of 2014 after an outage during the latter part of 2013 and the first part of 2014 which caused us to reduce production during this period (more than offset in Product sales), as well as $6 million higher per-unit costs at our RGP Splitter (more than offset in Product sales).

The favorable change in Other segment (income) costs and expenses is primarily due to an increase of $196 million of insurance recoveries in 2014 compared to 2013 related to the Geismar Incident and lower Canadian maintenance expenses. These favorable changes are partially offset by a $16 million increase in 2014 operating expenses primarily associated with the repair of the Geismar plant and the installation of certain safety equipment as well as a $9 million involuntary conversion gain in 2013 related to a 2012 furnace fire at our Geismar plant.

Segment profit decreased primarily due to $192 million lower Olefin product margins including $196 million lower product margins at our Geismar plant as a result of the Geismar Incident and $52 million lower marketing margins primarily due to declines in NGL prices while product was in transit in 2014 compared to gains in 2013. The 2014 losses were driven by significant declines in NGL prices during the fourth quarter of 2014. Partially offsetting this decrease is a $159 million favorable change in Other segment (income) costs and expenses as previously discussed.

2013 vs. 2012

Product sales decreased primarily due to:

• A $794 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 $314 million decrease in olefin sales due to $368 million of lower volumes, partially offset by $54 million associated with higher per-unit sales prices. Olefin production volumes are lower at our facilities in the Gulf Coast area 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. Our Canadian operations experienced lower olefin sales volumes due to a scheduled third-quarter 2013 shutdown to conduct maintenance and to install ethane recovery equipment, as well as the impact of delays associated with resuming production during the fourth quarter of 2013. These decreased volumes were partially offset by the absence of the impact of filling the Boreal Pipeline in June 2012. Ethylene and propylene prices averaged 21 percent and 12 percent higher, respectively, partially offset by 29 percent lower butadiene prices.

Product costs decreased primarily due to:

• An $826 million decrease in NGL marketing purchases partially offset by increased natural gas marketing purchases (substantially offset in Product sales).

• A $224 million decrease in olefin feedstock purchases due to $202 million of lower volumes, as discussed above, the third-party storage facility outage discussed above, and $22 million lower feedstock and fuel costs reflecting 21 percent lower average per-unit ethylene feedstock prices, partially offset by 9 percent higher average per-unit propylene feedstock prices.

• A $9 million increase in costs associated with our equity NGLs primarily due to an 18 percent increase in average natural gas prices.

Depreciation and amortization expenses increased $17 million primarily due to certain assets in Canada that were decommissioned in the third quarter of 2013 in preparation of the completion of the ethane recovery system, in addition to the depreciation related to the Boreal Pipeline which was placed into service in June 2012.

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

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gains related to a 2012 furnace fire at our Geismar olefins plant, a $5 million favorable impact of net foreign currency exchange gains, and the absence of $5 million of furnace repair expenses incurred during 2012. Partially offsetting this favorable impact are $30 million higher Operating and maintenance expenses including $13 million of costs incurred under our insurance deductibles associated with the Geismar Incident and increased maintenance at our Canadian facility related to the scheduled third-quarter 2013 shutdown previously discussed.

Segment profit decreased primarily due to lower olefin product margins, higher maintenance costs, $13 million of costs incurred under our insurance deductibles, lower NGL margins and higher depreciation expenses, as previously discussed. 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, a $5 million favorable impact of net foreign currency exchange gains, and the absence of $5 million of furnace repair expenses incurred during 2012. Olefin margins decreased $91 million at our Geismar plant, including $156 million lower product volumes, 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. NGL margins are $10 million lower due primarily to a higher average natural gas prices and lower non-ethane prices in Canada.

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Management’s Discussion and Analysis of Financial Condition and Liquidity

Overview

In 2014, 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;

• Compared to 2013, total per-unit distributions in 2014 grew 7 percent for Pre-merger WPZ and 21 percent for Pre-merger ACMP.

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

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 2015 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 that each of our businesses is capital-intensive, requiring investment to upgrade or enhance existing operations and comply with safety and environmental regulations. We expect capital and investment expenditures to total between $3.68 billion and $4.23 billion in 2015. Of this total, 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, (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 are expected to total $430 million in 2015 and 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 are expected to total between $3.25 billion and $3.80 billion in 2015. See Company Outlook - Expansion Projects for discussions describing the general nature of these expenditures. 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 2015. Our internal and external sources of consolidated liquidity to fund working capital requirements, capital and investment expenditures, debt service payments, and distributions to unitholders include:

• Cash and cash equivalents on hand;

• Cash generated from operations, including cash distributions from our equity-method investees;

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

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

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, 2014, we had a working capital deficit (current liabilities, inclusive of commercial paper issuances and long-term debt due within one year, in excess of current assets) of $889 million. However, we note the following about our available liquidity.

Available Liquidity	December 31, 2014
	(Millions)
Cash and cash equivalents	$	171
Capacity available to Pre-merger WPZ under its $2.5 billion credit facility, less amounts outstanding under its $2 billion commercial paper program (1)(3)	1,702
Capacity available to Pre-merger ACMP under its $1.75 billion credit facility (2)(3)	1,108
	$	2,981

__________

(1) In managing our available liquidity, we do not expect a maximum outstanding amount under Pre-merger WPZ’s commercial paper program in excess of the capacity available under Pre-merger WPZ’s credit facility. During 2014, Pre-merger WPZ borrowed under its commercial paper program and the highest amount outstanding during the year was $1 billion.

(2) The highest amount outstanding during the six months ended December 31, 2014 was $728 million.

(3) On February 2, 2015, in conjunction with the Merger, these credit facilities were terminated and replaced with a $3.5 billion credit facility with a maturity date of February 2, 2020 with an option to extend the maturity date up to February 2, 2022 subject to certain circumstances. We also amended and restated the commercial paper program to allow a maximum outstanding of $3 billion. On February 3, 2015, we also entered into a $1.5 billion short-term credit facility with a maturity date of August 3, 2015 with an option to extend the maturity date to February 2, 2016. We are in compliance with the financial covenants as measured at December 31, 2014. See Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements for further discussion. At February 24, 2015, $1.3 billion is outstanding under our credit facilities and $1.8 billion is outstanding under our commercial paper program.

Debt Issuances and Retirements

We retired $750 million of 3.8 percent senior unsecured notes that matured on February 15, 2015.

On June 27, 2014, Pre-merger WPZ completed a public offering of $750 million of 3.9 percent senior unsecured notes due 2025 and $500 million of 4.9 percent senior unsecured notes due 2045. We used the net proceeds to repay amounts outstanding under our commercial paper program, to fund capital expenditures, and for general partnership purposes.

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On March 4, 2014, Pre-merger WPZ completed a public offering of $1 billion of 4.3 percent senior unsecured notes due 2024 and $500 million of 5.4 percent senior unsecured notes due 2044. We used the net proceeds to repay amounts outstanding under our commercial paper program, to fund capital expenditures, and for general partnership purposes.

Shelf Registrations

In April 2013, Pre-merger WPZ filed a shelf registration statement for the offer and sale from time to time of common units representing limited partner interests having an aggregate offering price of up to $600 million. During 2014, 1,080,448 common units were issued under this registration. The net proceeds of $55 million were used for general partnership purposes. Pre-merger WPZ’s shelf registration statement was terminated on February 2, 2015 in conjunction with the Merger.

In July 2013, Pre-merger ACMP filed a shelf registration statement under which it may offer and sell common units representing limited partner interests having an aggregate offering price of up to $300 million. During the last six months of 2014, no common units were issued under this registration. On February 24, 2015, we filed a post-effective amendment to terminate the effectiveness of this shelf registration statement pertaining to sales of common units and to deregister the offer and sale of all unsold common units thereunder.  We anticipate filing a new registration statement on Form S-3 concerning the sale, on a continuous offering basis, of our common units.

Distributions from Equity-Method Investees

The organizational documents of entities in which we have an equity-method interest generally 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 businesses. See Note 6 – Investments of Notes to Consolidated Financial Statements for our more significant equity-method investees.

Credit Ratings

Our ability to borrow money is impacted by our credit ratings. On February 24, 2015, our credit ratings are as follows:

	Rating Agency	Outlook	Senior Unsecured Debt Rating	Corporate Credit Rating
WPZ:	Standard & Poor’s	Stable	BBB	BBB
	Moody’s Investors Service	Stable	Baa2	N/A
	Fitch Ratings	Negative	BBB	N/A

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, 2014, we estimate that a downgrade to a rating below investment grade could require us to post up to $262 million in additional collateral with third parties.

Cash Distributions to Unitholders

We paid a cash distribution of $0.85 per unit on February 13, 2015, on our outstanding common units to unitholders of record at the close of business on February 9, 2015. (See Note 4 – Allocation of Net Income and Distributions of Notes to Consolidated Financial Statements.)

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Sources (Uses) of Cash

	Years Ended December 31,
	2014			2013			2012
	(Millions)
Net cash provided (used) by:
Operating activities	$	2,345		$	2,169		$	2,133
Financing activities	1,585			1,595			2,438
Investing activities	(3,869		)	(3,736		)	(4,827		)
Increase (decrease) in cash and cash equivalents	$	61		$	28		$	(256	)

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 and Provision (benefit) for deferred income taxes. Our Net cash provided by operating activities in 2014 increased from 2013 primarily due to increased proceeds from insurance recoveries on the Geismar Incident, proceeds from a contingency settlement in 2014, and contributions from consolidating ACMP for the second half of 2014. These changes were partially offset by net unfavorable changes in operating working capital, lower olefins production margins, and increased interest payments of debt.

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.

Financing activities

Significant transactions include:

2014

• $572 million net proceeds received from commercial paper issuances;

• $2.74 billion net proceeds received from our debt offerings;

• $1.646 billion received from credit facility borrowings;

• $1.156 billion paid on credit facility borrowings;

• $2.691 billion, including $1.867 billion to Williams, related to quarterly cash distributions paid to limited partner unitholders and our general partner;

• $334 million received in contributions from noncontrolling interests.

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;

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• $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;

• $221 million in net contributions from Williams related to the Canada Acquisition.

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.

Investing activities

Significant transactions include:

2014

• $3.692 billion in capital expenditures;

• Purchases of and contributions to our equity-method investments of $468 million.

2013

• $3.316 billion in capital expenditures;

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

2012

• $2.366 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.

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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 11 – Property, Plant and Equipment, Note 13 – Debt, Banking Arrangements, and Leases, Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk, and Note 17 – 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.

Contractual Obligations

The table below summarizes the maturity dates of our contractual obligations at December 31, 2014:

	2015		2016 - 2017		2018 - 2019		Thereafter		Total
	(Millions)
Long-term debt:
Principal	$	—	$	1,160	$	1,140	$	13,818	$	16,118
Interest	791		1,502		1,357		5,508		9,158
Commercial paper	798		—		—		—		798
Capital leases	4		1		—		—		5
Operating leases	77		111		70		129		387
Purchase obligations (1)	1,185		338		320		533		2,376
Other obligations (2)	2		1		—		—		3
Total	$	2,857	$	3,113	$	2,887	$	19,988	$	28,845

____________

(1) Includes approximately $541 million in open property, plant, and equipment purchase orders. Includes an estimated $389 million long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2014 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 $600 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, 2014 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.)

(2) We have not included income tax liabilities in the table above. See Note 8 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of income taxes.

Effects of Inflation

Our operations have historically not been materially affected by inflation. Approximately 36 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 17 – 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 $19 million, all of which are included in Other accrued liabilities and Regulatory liabilities, deferred income, and other on the Consolidated Balance Sheet at December 31, 2014. We will seek recovery of approximately $11 million of these accrued costs through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2014, we paid approximately $8 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $4 million in 2015 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, 2014, 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.

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 the credit facilities and any issuances under the 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 13 – 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, 2014 and 2013. 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.

	2015			2016			2017			2018			2019			Thereafter(1)			Total		Fair Value December 31, 2014
	(Millions)
Long-term debt, including current portion: (2)
Fixed rate	$	750	(*)	$	375		$	785		$	500		$	—		$	13,275		$	15,685	$	15,967
Interest rate	5.1		%	5.1		%	5.0		%	5.0		%	4.9		%	5.1		%
Variable rate	$	—		$	—		$	—		$	640		$	—		$	—		$	640	$	640
Interest rate (3)
Commercial paper
Variable rate	$	798		$	—		$	—		$	—		$	—		$	—		$	798	$	798
Interest rate (4)
_____________
(*) Presented as long-term debt at December 31, 2014 due to our intent and ability to refinance.
	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		%
Commercial paper
Variable rate	$	225		$	—		$	—		$	—		$	—		$	—		$	225	$	225
Interest rate (4)

______________

(1) Includes unamortized discount and premium.

(2) Excludes capital leases.

(3) The weighted average interest rate at December 31, 2014 was 2.42 percent.

(4) The weighted average interest rate was 0.92 percent and 0.42 percent at December 31, 2014 and 2013, 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.

35

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, 2014 and 2013, our derivative activity was not material. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)

Foreign Currency Risk

Our foreign operations, whose functional currency is the local currency, are located in Canada. Net assets of our foreign operations were approximately $992 million and $1 billion at December 31, 2014 and 2013, respectively. These investments have the potential to impact our financial position due to fluctuations in the local currency arising from the process of translating the local functional currency into the U.S. dollar. As an example, a 20 percent change in the functional currency against the U.S. dollar would have changed Total partners’ equity by approximately$198 million at December 31, 2014.

36

Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

The Board of Directors of WPZ 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, 2014 and 2013, 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, 2014. 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). In the consolidated financial statements, the Partnership’s investment in Gulfstream constituted one percent of the Partnership’s assets as of each of December 31, 2014 and 2013, and the Partnership’s equity earnings in the net income of Gulfstream constituted five, six and five percent, respectively, of the Partnership’s income before income taxes for each of the three years in the period ended December 31, 2014. 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, 2014 and 2013, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 25, 2015, except for the matters described in Note 1 in the third paragraph under the caption “General” and Note 19, as to which the date is May 6, 2015

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

37

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, 2014 and 2013, 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, 2014. 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, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Houston, Texas

February 23, 2015

38

Williams Partners L.P.

Consolidated Statement of Comprehensive Income

		Years Ended December 31,
		2014			2013			2012
	(Millions, except per-unit amounts)
Revenues:
Service revenues		$	3,888		$	2,914		$	2,714
Product sales		3,521			3,921			4,757
Total revenues		7,409			6,835			7,471
Costs and expenses:
Product costs		3,016			3,027			3,501
Operating and maintenance expenses		1,277			1,080			1,019
Depreciation and amortization expenses		1,151			791			734
Selling, general, and administrative expenses		633			519			583
Net insurance recoveries – Geismar Incident		(232		)	(40		)	—
Other (income) expense – net		(45		)	51			24
Total costs and expenses		5,800			5,428			5,861
Operating income		1,609			1,407			1,610
Equity earnings (losses)		228			104			111
Interest incurred		(683		)	(477		)	(458		)
Interest capitalized		121			90			54
Other income (expense) – net		38			25			16
Income before income taxes		1,313			1,149			1,333
Provision (benefit) for income taxes		29			30			42
Net income		1,284			1,119			1,291
Less: Net income attributable to noncontrolling interests		96			3			—
Net income attributable to controlling interests		$	1,188		$	1,116		$	1,291
Allocation of net income for calculation of earnings per common unit:
Net income attributable to controlling interests		$	1,188		$	1,116		$	1,291
Allocation of net income to general partner		756			505			646
Allocation of net income to Class D units		73			—			—
Allocation of net income to common units		$	359		$	611		$	645
Basic and diluted net income per common unit		$	.99		$	1.76		$	2.30
Weighted average number of common units outstanding (thousands)		361,968			346,307			280,806
Cash distributions per common unit		$	3.5995		$	3.4800		$	3.2050
Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments		$	(1	)	$	1		$	30
Reclassifications into earnings of net derivative instruments (gain) loss		—			—			(30		)
Foreign currency translation adjustments		(89		)	(56		)	20
Other comprehensive income (loss)		(90		)	(55		)	20
Comprehensive income		1,194			1,064			1,311
Less: Comprehensive income attributable to noncontrolling interests		96			3			—
Comprehensive income attributable to controlling interests		$	1,098		$	1,061		$	1,311

See accompanying notes.

39

Williams Partners L.P.

Consolidated Balance Sheet

	December 31,
	2014		2013
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	171	$	110
Trade accounts and notes receivable – net	905		568
Inventories	231		194
Other current assets	198		96
Total current assets	1,505		968
Investments	8,399		2,187
Property, plant, and equipment – net	27,322		17,625
Goodwill	1,120		646
Other intangible assets – net of accumulated amortization	10,451		1,642
Regulatory assets, deferred charges, and other	525		503
Total assets	$	49,322	$	23,571
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	808	$	889
Affiliate	137		104
Accrued interest	215		115
Asset retirement obligations	40		64
Other accrued liabilities	392		375
Long-term debt due within one year	4		—
Commercial paper	798		225
Total current liabilities	2,394		1,772
Long-term debt	16,326		9,057
Asset retirement obligations	791		497
Deferred income taxes	133		117
Regulatory liabilities, deferred income, and other	993		561
Contingent liabilities and commitments (Note 17)
Equity:
Partners’ equity:
Common units (362,556,333 and 361,619,888 units outstanding at December 31, 2014 and 2013, respectively)	10,367		11,596
Class D units (21,574,035 units outstanding at December 31, 2014)	1,011		—
General partner	9,214		(536		)
Accumulated other comprehensive income (loss)	2		92
Total partners’ equity	20,594		11,152
Noncontrolling interests in consolidated subsidiaries	8,091		415
Total equity	28,685		11,567
Total liabilities and equity	$	49,322	$	23,571

See accompanying notes.

40

Williams Partners L.P.

Consolidated Statement of Changes in Equity

	Williams Partners L.P.
	Limited Partners
	Common Units			Class D Units			General Partner			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total Equity
	(Millions)
Balance – December 31, 2011	$	6,810		$	—		$	(815	)	$	127		$	—		$	6,122
Net income	672			—			619			—			—			1,291
Other comprehensive income (loss)	—			—			—			20			—			20
Cash distributions	(1,056		)	—			(384		)	—			—			(1,440		)
Distributions to The Williams Companies, Inc.- net	—			—			(16		)	—			—			(16		)
Sales of common units	2,559			—			—			—			—			2,559
Issuances of common units related to acquisitions	1,044			—			—			—			—			1,044
Issuances of common units in common control transactions	345			—			(338		)	—			—			7
Contributions from general partner	—			—			93			—			—			93
Contributions from noncontrolling interest	—			—			—			—			14			14
Other	(2		)	—			(1		)	—			—			(3		)
Net increase (decrease) in equity	3,562			—			(27		)	20			14			3,569
Balance – December 31, 2012	$	10,372		$	—		$	(842	)	$	147		$	14		$	9,691
Net income	660			—			456			—			3			1,119
Other comprehensive income (loss)	—			—			—			(55		)	—			(55		)
Cash distributions	(1,422		)	—			(424		)	—			—			(1,846		)
Contributions from The Williams Companies, Inc.- net	—			—			221			—			—			221
Sales of common units (Note 14)	1,962			—			—			—			—			1,962
Contributions from general partner	—			—			78			—			—			78
Contributions from noncontrolling interests	—			—			—			—			398			398
Other	24			—			(25		)	—			—			(1		)
Net increase (decrease) in equity	1,224			—			306			(55		)	401			1,876
Balance – December 31, 2013	$	11,596		$	—		$	(536	)	$	92		$	415		$	11,567
Net income	354			62			772			—			96			1,284
Other comprehensive income (loss)	—			—			—			(90		)	—			(90		)
Cash distributions	(1,706		)	—			(742		)	—			—			(2,448		)
Contributions from The Williams Companies, Inc. - net	—			—			10,703			—			7,502			18,205
Sales of common units (Note 14)	55			—			—			—			—			55
Issuance of Class D units in common control transaction (Note 1)	—			1,017			(1,017		)	—			—			—
Beneficial conversion feature of Class D units	117			(117		)	—			—			—			—
Amortization of beneficial conversion feature of Class D units	(49		)	49			—			—			—			—
Contributions from general partner	—			—			13			—			—			13
Distributions to noncontrolling interests	—			—			—			—			(243		)	(243		)
Contributions from noncontrolling interests	—			—			—			—			334			334
Other	—			—			21			—			(13		)	8
Net increase (decrease) in equity	(1,229		)	$	1,011		9,750			(90		)	7,676			17,118
Balance – December 31, 2014	$	10,367		$	1,011		$	9,214		$	2		$	8,091		$	28,685

See accompanying notes.

41

Williams Partners L.P.

Consolidated Statement of Cash Flows

	Years Ended December 31,
	2014			2013			2012
	(Millions)
OPERATING ACTIVITIES:
Net income	$	1,284		$	1,119		$	1,291
Adjustments to reconcile to net cash provided by operations:
Depreciation and amortization	1,151			791			734
Provision (benefit) for deferred income taxes	25			50			5
Net (gain) loss on dispositions of assets	57			6			7
Amortization of stock-based awards	9			—			—
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable	(169		)	21			32
Inventories	(36		)	(17		)	10
Other current assets and deferred charges	(43		)	25			25
Accounts payable	(42		)	(32		)	(81		)
Accrued liabilities	(233		)	171			(23		)
Affiliate accounts receivable and payable – net	9			(1		)	42
Other, including changes in noncurrent assets and liabilities	333			36			91
Net cash provided by operating activities	2,345			2,169			2,133
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	572			224			—
Proceeds from long-term debt	4,386			2,699			2,639
Payments of long-term debt	(1,157		)	(2,080		)	(1,440		)
Proceeds from sales of common units	55			1,962			2,559
General partner contributions	13			53			93
Distributions to limited partners and general partner	(2,448		)	(1,846		)	(1,440		)
Distributions to noncontrolling interests	(243		)	—			—
Contributions from noncontrolling interests	334			398			13
Contributions from The Williams Companies, Inc. – net	73			221			9
Payments for debt issuance costs	(24		)	(12		)	(12		)
Other – net	24			(24		)	17
Net cash provided by financing activities	1,585			1,595			2,438
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures (1)	(3,692		)	(3,316		)	(2,366		)
Net proceeds from dispositions	34			3			22
Purchases of businesses	—			—			(2,049		)
Purchase of business from affiliate	—			25			(25		)
Purchases of and contributions to equity-method investments	(468		)	(439		)	(471		)
Purchase of ARO trust investments	(52		)	(58		)	(34		)
Proceeds from sale of ARO trust investments	39			46			43
Other – net	270			3			53
Net cash used by investing activities	(3,869		)	(3,736		)	(4,827		)
Increase (decrease) in cash and cash equivalents	61			28			(256		)
Cash and cash equivalents at beginning of year	110			82			338
Cash and cash equivalents at end of year	$	171		$	110		$	82
_________
(1) Increases to property, plant, and equipment	$	(3,571	)	$	(3,333	)	$	(2,595	)
Changes in related accounts payable and accrued liabilities	(121		)	17			229
Capital expenditures	$	(3,692	)	$	(3,316	)	$	(2,366	)

See accompanying notes.

42

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

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 in which we own interests accounted for as equity-method investments that are not consolidated in our financial statements.  When we refer to our equity investees by name, we are referring exclusively to their businesses and operations. 

We are a publicly traded Delaware limited partnership. WPZ GP LLC, a Delaware limited liability company wholly owned by The Williams Companies, Inc. (Williams), serves as our general partner. Williams owns an approximate 58 percent limited partner interest, a 2 percent general partner interest, and incentive distribution rights (IDRs) in us. Our operations are located in the United States and Canada.

These financial statements were previously presented as supplemental financial statements because post-merger results had not yet been reported (see below for discussion of the merger).  In preparing these financial statements, no changes were made to the previously presented supplemental financial statements except to remove the word “supplemental” and to include the matters discussed in Note 19 – Subsequent Events.

Merger

Pursuant to an Agreement and Plan of Merger dated as of October 24, 2014, the general partners of Williams Partners L.P. and Access Midstream Partners, L.P. agreed to combine those businesses and their general partners, with Williams Partners L.P. merging with and into Access Midstream Partners, L.P. and the Access Midstream Partners, L.P. general partner being the surviving general partner (the Merger). Following the completion of the Merger on February 2, 2015, as further described below, the surviving Access Midstream Partners, L.P. changed its name to Williams Partners L.P. and the name of its general partner was changed to WPZ GP LLC. For the purpose of these financial statements and notes, Williams Partners L.P. (WPZ) refers to the renamed merged partnership, while Pre-merger Access Midstream Partners, L.P. (Pre-merger ACMP) and Pre-merger Williams Partners L.P. (Pre-merger WPZ) refer to the separate partnerships prior to the consummation of the Merger and subsequent name change.

In accordance with the terms of the Merger, each Pre-merger ACMP unitholder received 1.06152 Pre-merger ACMP units for each Pre-merger ACMP unit owned immediately prior to the merger. In conjunction with the Merger, each Pre-merger WPZ common unit held by the public was exchanged for 0.86672 common units of Pre-merger ACMP.   Each Pre-merger WPZ common unit held by Williams was exchanged for 0.80036 common units of Pre-merger ACMP.  Prior to the closing of the merger, the Class D limited partner units of Pre-merger WPZ, all of which were held by Williams, were converted into Pre-merger WPZ common units on a one-for-one basis pursuant to the terms of the partnership agreement of Pre-merger WPZ.  All of the general partner interests of Pre-merger WPZ were converted into general partner interests of Pre-merger ACMP such that the general partner interest of Pre-merger ACMP represents 2 percent of the outstanding partnership interest.

Description of Business

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

Access Midstream provides domestic gathering, treating, and compression services to producers under long-term, fixed-fee contracts. Its primary operating areas are in the Barnett Shale region of north-central Texas, The Eagle Ford Shale region of South Texas, the Haynesville Shale region of northwest Louisiana, the Marcellus Shale region primarily in Pennsylvania and West Virginia, the Niobrara Shale region of eastern Wyoming, the Utica Shale region of eastern

43

Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

Ohio, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware and Permian Basins. Access Midstream also includes a 49 percent equity-method investment in Utica East Ohio Midstream, LLC (UEOM), a 50 percent equity-method investment interest in the Delaware Basin gas gathering system in the Mid-Continent region, and Appalachia Midstream Services, LLC, which owns an approximate average 45 percent interest in 11 gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).

Northeast G&P is comprised of midstream gathering and processing businesses in the Marcellus and Utica shale regions, as well as a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain) and a 58 percent equity-method 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-method 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-method 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 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, an oil sands offgas processing plant located near Fort McMurray, Alberta, and a natural gas liquid (NGL)/olefin fractionation facility and butylene/butane splitter facility at Redwater, Alberta. This segment also includes our NGL and natural gas marketing business, storage facilities and an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in Overland Pass Pipeline, LLC (OPPL).

Basis of Presentation

Prior to the Merger, Williams owned certain limited partnership interests in both Pre-merger WPZ and Pre-merger ACMP, as well as 100 percent of the general partners of both partnerships. Due to the ownership of the general partners, Williams controlled both partnerships. Williams’ control of Pre-merger WPZ began with its inception in 2005, while control of Pre-merger ACMP was achieved upon obtaining an additional 50 percent interest in its general partner effective July 1, 2014. Williams previously acquired 50 percent of the Pre-merger ACMP general partner in a separate transaction in 2012.

The Merger has been accounted for as a combination between entities under common control, with Pre-merger WPZ representing the predecessor entity. As such, the accompanying financial statements represent a continuation of Pre-merger WPZ, the accounting acquirer, except for certain adjustments to give effect to the exchange ratio applied to Pre-merger WPZ’s historically outstanding units. Because the Merger was between entities under common control, it was treated similar to a pooling of interests whereby the historical results of operations for Pre-merger ACMP were combined with those of Pre-merger WPZ for periods under common control (periods subsequent to July 1, 2014) and the net assets of Pre-merger ACMP are combined at Williams’ historical basis. (See Note 2 – Acquisitions.)

Previously presented limited partner units of Pre-merger WPZ have been adjusted to reflect the exchange ratios above, which has resulted in a change to historical earnings per unit. Historical earnings of Pre-merger ACMP prior to the Merger have been presented herein as allocated to either the capital account of the general partner for interests owned by Williams or to noncontrolling interests for interests held by the public. Thus, there was no change in the total amount of historical earnings attributable to common unitholders.

In February 2014, we acquired certain Canadian operations from Williams (Canada Acquisition) for total consideration of $56 million of cash (including a $31 million post-closing adjustment paid in the second quarter), 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 received quarterly

44

Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

distributions of additional paid-in-kind Class D units. 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 and the acquired assets and liabilities were combined with ours at their historical amounts. These Canadian operations are reported in our NGL & Petchem Services segment.

In October 2014, a purchase price adjustment was finalized whereby we received $56 million in cash from Williams in the fourth quarter 2014and Williams waived $2 million in payments on its IDRs with respect to Pre-merger WPZ’s November 2014 distribution.

The Canadian operations previously participated in Williams’ cash management program under a credit agreement with Williams. Net changes in amounts due to/from Williams prior to the Canada Acquisition, along with the cash consideration paid for the Canada Acquisition, are reflected within Distributions to the Williams Companies, Inc. - net within the Consolidated Statement of Changes in Equity.

Prior period amounts and disclosures have been recast for this transaction. The effect of recasting our financial statements to account for this transaction increased net income by $49 million and $59 million for the years ended 2013 and 2012, respectively, and also resulted in Foreign currency translation adjustments of $(56) million and $20 million for the years ended 2013 and 2012, respectively, reflected within Other comprehensive income (loss). This acquisition does not impact historical earnings per unit as pre-acquisition earnings were allocated to our general partner.

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 Pre-merger WPZ’s 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 Pre-merger WPZ’s 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 certain ventures in which we own an undivided interest. Management’s 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.

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

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 or noncontrolling interests, if applicable. 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.

Equity-method investment basis differences

Differences between the cost of our equity-method investments and our underlying equity in the net assets of investees are accounted for as if the investees were consolidated subsidiaries. Equity earnings (losses) in the Consolidated Statement of Comprehensive Income includes our allocable share of net income (loss) of investees adjusted for any depreciation and amortization, as applicable, associated with basis differences.

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;

• Depreciation and/or amortization of equity-method investment basis differences;

• 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

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

that are regulated can differ from the accounting requirements for nonregulated 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, 2014 and 2013 are as follows:

	December 31,
	2014		2013
	(Millions)
Current assets reported within Other current assets	$	81	$	39
Noncurrent assets reported within Regulatory assets, deferred charges, and other	289		315
Total regulated assets	$	370	$	354
Current liabilities reported within Other accrued liabilities	$	11	$	19
Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other	349		289
Total regulated liabilities	$	360	$	308

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 an accelerated depreciation method. (SeeNote 11 – 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.

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

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 rate to the liability balance. 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 of the consideration, plus the fair value of any noncontrolling interest or any previously held equity interest, over the fair value of the net assets 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 contractual customer relationships. 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.

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

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 13 – 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 16 – 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.

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

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.

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, processing, treating, and compression services and are performed under volumetric-based fee contracts. These revenues are recorded when services have been performed.

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

Certain of our gas gathering agreements have minimum volume commitments. If a customer under such an agreement fails to meet its minimum volume commitment for a specified period, generally measured on an annual basis, it is obligated to pay a contractually determined fee based upon the shortfall between actual production volumes and the minimum volume commitment for that period. The revenue associated with minimum volume commitments is recognized in the period that the actual shortfall is determined and is no longer subject to future reduction or offset.

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 or capacity has been provided.

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

Our Canadian business has processing and fractionation operations where we retain certain NGLs and olefins from an upgrader’s offgas stream and we recognize revenues when the fractionated products 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 income in 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 income tax purposes, with the exception of Texas franchise tax and foreign income taxes associated with our Canadian operations. Other income taxes are 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.

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

Foreign deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of the related assets and liabilities. Our management’s judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets.

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 9 – 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.

Foreign currency translation

Our foreign subsidiaries use the Canadian dollar as their functional currency. Assets and liabilities of such foreign subsidiaries are translated at the spot rate in effect at the applicable reporting date, and the combined statements of comprehensive income are translated into the U.S. dollar at the average exchange rates in effect during the applicable period. The resulting cumulative translation adjustment is recorded as a separate component of AOCI.

Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates when the transactions are settled result in transaction gains and losses which are reflected in the Consolidated Statement of Comprehensive Income.

Accumulated Other Comprehensive Income (Loss)

AOCI is substantially comprised of foreign currency translation adjustments. These adjustments did not impact Net income in any of the periods presented.

Accounting standards issued but not yet adopted

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09 establishing Accounting Standards Codification Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. The standard is effective for annual reporting periods beginning after December 15, 2016, and interim periods within the reporting period. Accordingly, we will adopt this standard in the first quarter of 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is not permitted. We continue to evaluate both the impact of this new standard on our consolidated financial statements and the transition method we will utilize for adoption.

Note 2 – Acquisitions

ACMP

As previously discussed in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies, these financial statements reflect Williams’ basis in Pre-merger ACMP for periods subsequent to Williams’ acquiring control of Pre-merger ACMP on July 1, 2014 (ACMP Acquisition). Williams’ basis

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

in Pre-merger ACMP reflects its business combination accounting, which, among other things, requires identifiable assets acquired and liabilities assumed to be measured at their acquisition-date fair values.

The valuation techniques used to measure the acquisition-date fair value of Pre-merger ACMP consisted of valuing the limited partner units and general partner interest separately. The limited partner units of Pre-merger ACMP, consisting of common and Class B units, were valued based on Pre-merger ACMP’s closing common unit price at July 1, 2014. The general partner interest, including IDRs, was valued on a noncontrolling basis using an income approach based on a discounted cash flow analysis and a market comparison analysis based on comparable guideline companies and an implied fair value from Williams’ purchase.

The following table presents the preliminary allocation of the acquisition-date fair value of the major classes of the assets acquired, which are presented in the Access Midstream segment, liabilities assumed, noncontrolling interest, and equity at July 1, 2014. The allocation is considered preliminary because the valuation work has not been completed due to the ongoing review of the valuation results and validation of significant inputs and assumptions. Significant changes since the allocation disclosed in the third quarter reflect an increase in investments and decreases in goodwill, other intangible assets, and property, plant and equipment - net, generally associated with the attribution of fair value between consolidated and non-consolidated operations. The fair value of accounts receivable acquired equals contractual amounts receivable.

	(Millions)
Accounts receivable	$	168
Other current assets	63
Investments	5,872
Property, plant, and equipment – net	7,015
Goodwill	474
Other intangible assets	9,009
Current liabilities	(408		)
Debt	(4,052		)
Other noncurrent liabilities	(9		)
Noncontrolling interest in ACMP’s subsidiaries	(958		)
Noncontrolling interest representing Pre-merger ACMP public unitholders	(6,544		)
Equity	(10,630		)

The goodwill recognized in the acquisition relates primarily to enhancing and diversifying our basin positions and was allocated to the reporting units representing the northeast, central, and west regions within our Access Midstream segment.

Other intangible assets recognized in the acquisition are related to contractual customer relationships from gas gathering agreements with our customers. The basis for determining the value of these intangible assets is estimated future net cash flows to be derived from acquired contractual customer relationships discounted using a risk-adjusted discount rate. These intangible assets are being amortized on a straight-line basis over 30 years during which contractual customer relationships are expected to contribute to our cash flows. Approximately 56 percent of the expected future revenues from these contractual customer relationships are impacted by our ability and intent to renew or renegotiate existing customer contracts. 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 current contract periods, the weighted-average periods to the next renewal or extension of the existing customer contracts is approximately 17 years.

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

The following unaudited pro forma Revenues and Net income attributable to controlling interests for the years ended December 31, 2014 and 2013, are presented as if the ACMP Acquisition had been completed on January 1, 2013. These pro forma amounts are not necessarily indicative of what the actual results would have been if the acquisition had in fact occurred on the date or for the periods indicated, nor do they purport to project Revenues or Net income attributable to controlling interests for any future periods or as of any date. These amounts do not give effect to any potential cost savings, operating synergies, or revenue enhancements to result from the transactions or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements.

	December 31,
	2014		2013
	(Millions)
Revenues	$	7,953	$	7,881
Net income attributable to controlling interests	$	1,376	$	1,172

Significant adjustments to pro forma Net income attributable to controlling interests include additional depreciation and amortization expense associated with reflecting the acquired investments, property, plant, and equipment, and other intangible assets at fair value. The adjustments assume estimated useful lives of 30 years.

During the year ended December 31, 2014, ACMP contributed Revenues of $781 million and Net income attributable to controlling interests of $165 million.

Costs incurred by Williams related to this acquisition are $16 million and are reported within our Access Midstream segment and included in Selling, general, and administrative expenses in our Consolidated Statement of Comprehensive Income. Direct transaction costs associated with financing commitments are $9 million and reported within Interest incurred in our Consolidated Statement of Comprehensive Income.

Laser and Caiman

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 Pre-merger WPZ 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 Pre-merger WPZ 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	318			1,393
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.

Note 3 – Variable Interest Entities

Consolidated VIEs

As of December 31, 2014, we consolidate the following VIEs:

Gulfstar One

We own a 51 percentinterest in Gulfstar One LLC (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, designed, constructed, and installed a proprietary floating-production system, Gulfstar FPS™, and associated pipelines which began providing production handling and gathering services for the Tubular Bells oil and gas discovery in the eastern deepwater Gulf of Mexicoin the fourth quarter of 2014. We received certain advance payments from the producer customers. In certain circumstances, the producer customers could be responsible for Gulfstar One’s unrecovered portion of the firm price of building the facilities if the production handling agreement is terminated. Construction of an expansion project is underway that will provide production handling and gathering 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 the first quarter of 2016. The current estimate of the total remaining construction costs for the expansion project is approximately $150 million, which we expect will be funded with revenues received from customers and capital contributions from us and the other equity partner on a proportional basis.

Constitution

We own a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its long-term 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 the second half of 2016 and estimate the total remaining construction costs of the project to be approximately $628 million, which will be funded with capital contributions from us and the other equity partners, proportional to ownership interest.

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

Cardinal

We own a 66 percent interest in Cardinal Gas Services, L.L.C (Cardinal Venture), a subsidiary that, due to certain risks shared with customers, is a VIE. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Cardinal Venture’s economic performance. We, as operator for Cardinal Venture, designed, constructed, and installed associated pipelines which will initially provide production handling and gathering services for the Utica region. We received certain advance payments from the equity partners during the construction process.

Jackalope

We own a 50 percent interest in Jackalope Gas Gathering Services, L.L.C (Jackalope Venture), a subsidiary that, due to certain risks shared with customers, is a VIE. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Jackalope Venture’s economic performance. We, as operator for Jackalope Venture, designed, constructed, and installed associated pipelines which will initially provide production handling and gathering services for the Niobrara region. We received certain advance payments from the equity partners during the construction process.

The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of our consolidated VIEs.

	December 31,
	2014			2013			Classification
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	113		$	84		Cash and cash equivalents
Accounts receivable	52			—			Trade accounts and notes receivable, net
Other current assets	3			—			Other current assets
Property, plant, and equipment - net	2,794			1,001			Property, plant, and equipment – net
Goodwill	103			—			Goodwill
Other intangible assets, net	1,493			—			Other intangible assets – net of accumulated amortization
Other noncurrent assets	14			—			Regulatory assets, deferred charges, and other
Accounts payable	(48		)	(122		)	Accounts payable - trade
Accrued liabilities	(36		)	(3		)	Other accrued liabilities
Current deferred revenue	(45		)	(10		)	Other accrued liabilities
Noncurrent deferred income taxes	(13		)	—			Deferred income taxes
Asset retirement obligation	(94		)	—			Asset retirement obligations, noncurrent
Noncurrent deferred revenue associated with customer advance payments	(395		)	(115		)	Regulatory liabilities, deferred income and other

Nonconsolidated VIEs

Laurel Mountain

In October 2014, Laurel Mountain, a previously reported VIE, was restructured removing the customer risk sharing provisions and is no longer considered a VIE as of December 31, 2014. Laurel Mountain continues to be reported as a 69 percent-ownedequity-method investment due to the significant participatory rights of our partners such that we do not have control of Laurel Mountain.

Caiman II

During April 2014, Caiman II, a previously reported VIE, became able to finance its current activities without additional subordinated financial support due in part to its primary investee, Blue Racer Midstream LLC, securing a revolving credit agreement with a third party. As a result of obtaining the additional financial support, Caiman II is no

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

longer considered a VIE in 2014 but continues to be reported as a 58 percent-owned equity-method investment due to the significant participatory rights of our partners such that we do not have control of Caiman II.

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,
	2014			2013			2012
	(Millions)
Allocation of net income to general partner:
Net income	$	1,284		$	1,119		$	1,291
Net income applicable to pre-merger operations allocated to general partner	(95		)	—			—
Net income applicable to pre-partnership operations allocated to general partner	(15		)	(49		)	(244		)
Net income applicable to noncontrolling interests	(96		)	(3		)	—
Costs charged directly to general partner	1			1			1
Income subject to 2% allocation of general partner interest	1,079			1,068			1,048
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	22			21			21
Priority allocations, including incentive distributions, paid to general partner	641			387			355
Costs charged directly to general partner	(1		)	(1		)	(1		)
Pre-merger net income allocated to general partner interest	95			—			—
Pre-partnership net income allocated to general partner interest	15			49			244
Net income allocated to general partner	$	772		$	456		$	619
Net income	$	1,284		$	1,119		$	1,291
Net income allocated to general partner’s equity	772			456			619
Net income allocated to Class D limited partners’ equity (1)	62			—			—
Net income allocated to noncontrolling interests	96			3			—
Net income allocated to common limited partners’ equity	$	354		$	660		$	672
Adjustments to reconcile Net income allocated to common limited partners' equity
to Allocation of net income to common units:
Incentive distributions paid	640			383			355
Incentive distributions declared (2)	(626		)	(432		)	(382		)
Impact of Class D issuance timing	(9		)	—			—
Allocation of net income to common units	$	359		$	611		$	645

____________

(1) The net income allocated to Pre-merger WPZ Class D limited partners includes $49 million for the year ended December 31, 2014, related to the amortization of the beneficial conversion feature associated with the Pre-merger WPZ Class D units.

(2) Following the completion of the Merger, we paid a cash distribution of $0.85 per unit on February 13, 2015, on our outstanding common units to unitholders of record at the close of business on February 9, 2015. For the purpose of determining the Allocation of net income to common units for the calculation of earnings per unit, the incentive distribution declared for the fourth quarter of 2014 reflects only the portion of the total incentive distribution associated with the Pre-merger WPZ common units exchanged in the Merger.

Class D Units

As previously mentioned (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies), a portion of the total consideration for the Canada Acquisition was funded through the issuance of Pre-merger WPZ Class D units to an affiliate of our general partner. The Pre-merger WPZ Class D units were issued at a discount to the market price of Pre-merger WPZ’s common units. The discount represented a

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

beneficial conversion feature and is reflected as an increase in the common unit capital account and a decrease in the Class D capital account on the Consolidated Statement of Changes in Equity. This discount was being amortized through the originally expected first quarter 2016 conversion date, resulting in an increase to the Class D capital account and a decrease to the common unit capital account. The remaining unamortized balance as of December 31, 2014, will be recognized in the first quarter of 2015 due to the Merger. All Pre-merger WPZ Class D units were converted into common units in conjunction with the Merger.

Distributions

The Pre-merger WPZ Class D units were not entitled to cash distributions. Instead, prior to conversion into Pre-merger WPZ common units, the Pre-merger WPZ Class D units received quarterly distributions of additional paid-in-kind Pre-merger WPZ Class D units. During 2014, we issued 1,377,893 Pre-merger WPZ Class D units as the paid-in-kind Class D distributions.

Earnings per unit

Basic and diluted earnings per limited partner unit are calculated using the two-class method. At December 31, 2014, the Pre-merger WPZ Class D units are anti-dilutive and therefore not included in calculating diluted earnings per common unit.

Note 5 – Related Party Transactions

Reimbursement of Expenses of Our General Partner

The employees of Pre-merger WPZ 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.

The employees of Pre-merger ACMP operated assets were employees of Pre-merger ACMP’s general partner. Pre-merger ACMP’s general partner directly charged Pre-merger ACMP for payroll and benefit costs associated with operations employees and carried the obligations for many employee-related benefits. In addition, Pre-merger ACMP’s general partner charged Pre-merger ACMP for employee related costs for employees who provided general and administrative services to Pre-merger ACMP. These costs are reflected in Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income. The employees for Pre-merger ACMP’s general partner became Williams’ employees on January 1, 2015.

In 2012, Williams engaged a consulting firm to assist in better aligning resources to support its 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 $26 million for the years ended December 31, 2013 and 2012, respectively.

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

Transactions with Equity-Method Investees

Service revenues, in the Consolidated Statement of Comprehensive Income, includes fees received from Appalachia Midstream Investments for the use of compression equipment during the year.

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

• 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.

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

	Years Ended December 31,
	2014		2013		2012
	(Millions)
Service revenues	$	13	$	—	$	—
Product costs	186		147		171
Operating and maintenance expenses - employee costs	413		339		275
Selling, general, and administrative expenses:
Employee direct costs	331		270		308
Employee allocated costs	171		169		190

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 $13 million in Accounts payable — trade in the Consolidated Balance Sheet with our equity-method investees at December 31, 2014 and 2013, 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 $75 million, $67 million, and $75 million for the years ended December 31, 2014, 2013, and 2012, respectively.

Omnibus Agreement

In February 2010, Pre-merger WPZ entered into an omnibus agreement with Williams. The terms of this agreement survived the Merger. Under this agreement, Williams is obligated to reimburse us for certain items including (i) 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 (ii) 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. Net amounts received under this agreement for the years ended December 31, 2014, 2013 and 2012 were $11 million, $12 million, and $15 million, respectively.

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

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

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 Merger, Geismar, and Canada 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. The Canadian operations previously participated in Williams’ cash management program under a credit agreement with Williams. Net changes in amounts due to/from Williams prior to the Canada Acquisition are reflected within Distributions to/Contributionsfrom The Williams Companies, Inc. - net within the Consolidated Statement of Changes in Equity.

Note 14 – Partners’ Capital includes related party transactions for the sale of limited partner units to Williams in March 2013.

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 $115 million and $131 million in Service revenues in Consolidated Statement of Comprehensive Income from this company for transportation and storage of natural gas for the years ended December 31, 2014 and December 31, 2013, respectively. 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 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 in Product costs in the Consolidated Statement of Comprehensive Income for the purchase of propane at market prices for the year ended December 31, 2012.

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

Note 6 – Investments

Investments accounted for using the equity method consist of:

	December 31,
	2014		2013
	(Millions)
Appalachia Midstream Investments (2)	$	3,033	$	—
Delaware Basin gas gathering system – 50% (2)	1,478		—
UEOM – 49% (2)	1,411		—
Discovery – 60% (1)	602		527
Laurel Mountain – 69% (1)	459		481
OPPL – 50%	453		452
Caiman II – 58% (1)	432		256
Gulfstream – 50%	317		333
Other	214		138
	$	8,399	$	2,187

____________

(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.

(2) These are Pre-merger ACMP investments. The Appalachia Midstream Investments include investments in 11 different gathering systems in the Marcellus Shale. Ownership interests range from 33.75 percent to 67.50 percent, resulting in an overall approximate average interest of 45 percent. For those investments where we own in excess of 50 percent, we apply the equity-method of accounting due to the significant participation rights of our partners such that we do not control. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)

We have differences between the carrying value of our equity-method investments and the underlying equity in the net assets of the investees of$3.7 billionat December 31, 2014. This difference primarily relates to our investments in Appalachian Midstream Investments, Delaware Basin gas gathering system, and UEOM resulting from property, plant, and equipment, as well as customer-based intangible assets and goodwill. (See Note 2 – Acquisitions.)

Equity earnings (losses) in 2014 includes $146 million of equity earnings for the last six months of the year from equity-method investments of Pre-merger ACMP, partially offset by $49 million of noncash amortization of the difference between the cost of our investment and our underlying share of the net assets (See Note 2 - Acquisitions).

We generally fund our portion of significant expansion or development projects of these investees through additional capital contributions. As of December 31, 2014, our proportionate share of amounts remaining to be spent for specific capital projects already in progress for Discovery and Laurel Mountain totaled $98 millionand $92 million, respectively. See the table below for significant contributions.

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

	Years Ended December 31,
	2014		2013		2012
	(Millions)
Caiman II	$	175	$	192	$	69
Discovery	106		193		169
Appalachia Midstream Investments	84		—		—
UEOM	57		—		—
Delaware Basin gas gathering system	20		—		—
Laurel Mountain	12		42		174

The organizational documents of entities in which we have an equity-method interest generally require distribution of available cash to members on a quarterly basis. Dividends and distributions, including those presented below, received from companies accounted for by the equity method of accounting were $344 million, $154 million, and $172 million in 2014, 2013, and 2012, respectively. These transactions reduced the carrying value of our investments. These dividends and distributions primarily included: 

	Years Ended December 31,
	2014		2013		2012
	(Millions)
Appalachia Midstream Investments	$	120	$	—	$	—
Gulfstream	81		81		78
Laurel Mountain	39		—		—
Discovery	36		12		21
OPPL	27		27		28
Aux Sable Liquid Products L.P.	15		20		28

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

	December 31,
	2014			2013
	(Millions)
Assets (liabilities):
Current assets	$	599		$	412
Noncurrent assets	9,135			5,956
Current liabilities	(850		)	(264		)
Noncurrent liabilities	(954		)	(1,305		)

	Years Ended December 31,
	2014		2013		2012
	(Millions)
Gross revenue	$	1,623	$	1,333	$	1,213
Operating income	534		367		378
Net income	460		291		309

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

Note 7 – Other Income and Expenses

The following table presents certain gains or losses reflected in Other (income) expense – net within Costs and expenses in our Consolidated Statement of Comprehensive Income:

	Years Ended December 31,
	2014			2013			2012
	(Millions)
Access Midstream
Loss related to sale of certain assets	$	10		$	—		$	—
Impairment of certain materials and equipment held for sale (See Note 16)	12			—			—
Northeast G&P
Contingency gain settlement	(154		)	—			—
Impairment of certain materials and equipment (See Note 16)	30			—			—
Net gain related to partial acreage dedication release	(12		)	—			—
Loss associated with a producer claim	—			25			—
Atlantic-Gulf
Amortization of regulatory assets associated with asset retirement obligations	33			30			7
Impairment of certain equipment	10			—			—
Write-off of the Eminence abandonment regulatory asset not recoverable through rates	(3		)	12			—
Insurance recoveries associated with the Eminence abandonment	—			(16		)	—
Project feasibility costs	2			4			21
Capitalization of project feasibility costs previously expensed	(5		)	(1		)	(19		)

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.

In November 2014, we settled a claim arising from the resolution of a contingent gain related to claims associated with the purchase of a business in a prior period. Pursuant to the settlement, we received $154 million in cash, all of which has been recognized as a gain in the fourth quarter of 2014.

Geismar Incident

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.

At the time of the incident, we had 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;

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

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

We expensed $13 million at NGL & Petchem Services during 2013 of costs under our insurance deductibles reported in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income. During the years ended December 31, 2014 and 2013, we received $246 million and $50 million, respectively, of insurance recoveries related to the Geismar Incident. These amounts are reported within our NGL & Petchem Services segment and reflected as gains in Net insurance recoveries – Geismar Incident in our Consolidated Statement of Comprehensive Income. Also, during the years ended December 31, 2014 and 2013, we incurred $14 million and $10 million, respectively, of covered insurable expenses in excess of our retentions (deductibles) also included in Net insurance recoveries – Geismar Incident.

Additional Items

Selling, general, and administrative expenses in 2014 includes $15 million of employee-related transition costs and $11 million of consulting, legal, and accounting fees associated with the Merger reported primarily within the Access Midstream segment. Operating and maintenance expenses in 2014 also includes $15 million of employee-related transition costs associated with the Merger reported within the Access Midstream segment.

Other income (expense) – net below Operating income includes $34 million, $20 million, and $15 million for allowance for equity used during construction (AFUDC) for the years ended December 31, 2014, 2013, and 2012, respectively. AFUDC increased during 2014 due to the increase in spending on Constitution and various Transco expansion projects.

Note 8 – Provision (Benefit) for Income Taxes

The Provision (benefit) for income taxes includes:

	Years Ended December 31,
	2014		2013			2012
	(Millions)
Current:
State	$	3	$	2		$	11
Foreign	1		(22		)	26
	4		(20		)	37
Deferred:
State	8		15			—
Foreign	17		35			5
	25		50			5
Total provision (benefit)	$	29	$	30		$	42

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

Reconciliations from the Provision (benefit) for income taxes at the federal statutory rate to the recorded Provision (benefit) for income taxes are as follows:

	Years Ended December 31,
	2014			2013			2012
	(Millions)
Provision at statutory rate	$	462		$	402		$	467
Increases (decreases) in taxes resulting from:
Income not subject to U.S. federal tax	(462		)	(402		)	(467		)
State income taxes	11			17			11
Foreign operations — net	18			13			31
Provision (benefit) for income taxes	$	29		$	30		$	42

The 2013 state deferred provision includes $14 million related to the impact of a second-quarter 2013 Texas franchise tax law change.

Income before income taxes includes $72 million, $61 million, and $96 million of foreign income in 2014, 2013, and 2012, respectively.

Deferred tax liabilities, primarily attributable to the taxable temporary differences from property, plant, and equipment, were $133 million, $117 million, and $72 million in 2014, 2013, and 2012, respectively.

During 2014, we received cash refunds (net of payments) for income taxes of $28 million. Cash payments for income taxes (net of refunds) were $2 million and $54 million in 2013 and 2012, respectively, and are recorded in the Consolidated Balance Sheet.

As of December 31, 2014, we do not have any material unrecognized tax benefits.

Tax years after 2010 are subject to examination by the Texas Comptroller. Generally, tax returns for our Canadian entities are open to audit for tax years after 2010. Williams has indemnified us for any adjustments to foreign tax returns filed prior to the Canada Acquisition.

Note 9 – Benefit Plans

Certain of the benefit costs charged to us by our general partners 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. Employees supporting Pre-merger ACMP were not participants in the pension and other postretirement benefit plans sponsored by Williams during 2014. As a result, there are no pension and other postretirement benefit costs included in the amounts presented below associated with those employees. During 2014, employees supporting Pre-merger ACMP were eligible for defined contribution plans sponsored by the general partner of Pre-merger ACMP. The cost for the employer matching contributions for the period subsequent to July 1, 2014, is included in the defined contribution amount presented below. Effective January 1, 2015, these employees became Williams employees and eligible for certain employee benefit plans sponsored by Williams.

Defined benefit 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 2014, 2013, and 2012 totaled $28 million, $44 million, and $41 million, respectively. At the total Williams plan level, the pension plans had a projected benefit obligation of $1.5 billion and $1.4 billion at December 31, 2014 and 2013, respectively. The plans were underfunded by $251 million and $143 million at December 31, 2014 and 2013, respectively.

65

Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

Postretirement benefits other than pensions

Williams provides certain retiree health care and life insurance benefits for eligible participants. We recognized a net periodic postretirement benefit credited to us by Williams of $14 million and $4 million in 2014 and 2013, respectively, 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 $233 million and $213 million at December 31, 2014 and 2013, respectively. The plans were underfunded by $25 million and $12 million at December 31, 2014 and 2013, respectively.

Any differences between the annual expense and amounts currently being recovered in rates by Transco and Northwest Pipeline are recorded as an adjustment to expense and collected or refunded through future rate adjustments.

Defined contribution plans

We were charged compensation expense of $25 million, $16 million, and $19 million in 2014, 2013, and 2012, respectively, for contributions to these plans. The increase in expense in 2014 is primarily due to the impact of its acquisition of ACMP. (See Note 2 - Acquisitions.)

Note 10 – Inventories

	December 31,
	2014		2013
	(Millions)
Natural gas liquids, olefins, and natural gas in underground storage	$	150	$	111
Materials, supplies, and other	81		83
	$	231	$	194

Note 11 – Property, Plant and Equipment

	Estimated	Depreciation
	Useful Life (1)	Rates (1)	December 31,
	(Years)	(%)	2014			2013
			(Millions)
Nonregulated:
Natural gas gathering and processing facilities	5 - 40		$	18,717		$	9,172
Construction in progress	Not applicable		2,115			2,727
Other	3 - 45		1,459			964
Regulated:
Natural gas transmission facilities		1.2 - 6.97	10,867			10,633
Construction in progress		Not applicable	985			273
Other		1.35 - 33.33	1,336			1,293
Total property, plant, and equipment, at cost			$	35,479		$	25,062
Accumulated depreciation and amortization			(8,157		)	(7,437		)
Property, plant, and equipment – net			$	27,322		$	17,625

____________

(1) Estimated useful life and depreciation rates are presented as of December 31, 2014. Depreciation rates for regulated assets are prescribed by the FERC.

66

Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

Depreciation and amortization expense for Property, plant, and equipment – net was $944 million, $729 million and $690 million in 2014, 2013, and 2012, respectively.

Regulated Property, plant, and equipment – net includes approximately $746 million and $785 million at December 31, 2014 and 2013, 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 and pipelines, 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 and appropriately abandon offshore pipelines, 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 ARO:

	December 31,
	2014			2013
	(Millions)
Beginning balance	$	561		$	579
Liabilities incurred	101			8
Liabilities settled (1)	(21		)	(31		)
Accretion expense	44			53
Revisions (2)	146			(48		)
Ending balance	$	831		$	561

______________

(1) For 2014 and 2013, liabilities settled include $7 million and $25 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 2014 revisions primarily reflect an increase in the estimated retirement costs for our offshore pipelines, an increase in the inflation rate and decreases in the discount rates used in the annual review process. The 2013 revision primarily reflects increases in the estimated remaining useful life of the assets. The 2013 revision also includes an increase of $9 million 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 16 – 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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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

Note 12 – Goodwill and Other Intangible Assets

Goodwill

Changes in the carrying amount of goodwill by reportable segment for the periods indicated are as follows:

	Access Midstream		Northeast G&P		Total
	(Millions)
December 31, 2013	$	—	$	646	$	646
Acquisition	474		—		474
December 31, 2014	$	474	$	646	$	1,120

Our goodwill is not subject to amortization, but is evaluated at least annually for impairment or more frequently if impairment indicators are present. We did not identify or recognize any impairments to goodwill in connection with our annual evaluation of goodwill for impairment (performed as of October 1) during the years ended December 31, 2014, 2013, and 2012. Following a significant decline in energy commodity prices and a decline in the fair value of Pre-merger ACMP's publicly-traded limited partner units, both in the fourth quarter of 2014, we performed an additional impairment evaluation as of December 31, 2014 of the goodwill recorded within the Access Midstream segment. In this evaluation, our estimate of the fair value of each reporting unit exceeded its carrying value and thus no impairment losses were recognized in 2014.

Other Intangible Assets

The gross carrying amount and accumulated amortization of Other intangible assets – net of accumulated amortization at December 31 are as follows:

	2014					2013
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
	(Millions)
Contractual customer relationships	$	10,761	$	(310	)	$	1,747	$	(105	)

Other intangible assets – net of accumulated amortization primarily relate to gas gathering, processing, and fractionation contractual customer relationships recognized in the ACMP, Laser, and Caiman acquisitions (See Note 2 – Acquisitions.) 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 contractual customer relationships are expected to contribute to our cash flows.

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 contractual customer relationships associated with the ACMP, Laser, and Caiman acquisitions were approximately 17 years, 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 investment required.

The amortization expense related to Other intangible assets – net of accumulated amortization was $207 million, $60 million and $43 million in 2014, 2013, and 2012, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $357 million.

68

Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

Note 13 – Debt, Banking Arrangements, and Leases

Long-Term Debt

	December 31,
	2014			2013
	(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 (3)	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
5.875% Notes due 2021 (1)	750			—
4% Notes due 2021	500			500
3.35% Notes due 2022	750			750
6.125% Notes due 2022 (1)	750			—
4.875% Notes due 2023 (1)	1,400			—
4.5% Notes due 2023	600			600
4.3% Notes due 2024	1,000			—
4.875% Notes due 2024 (1)	750			—
3.9% Notes due 2025	750			—
6.3% Notes due 2040	1,250			1,250
5.8% Notes due 2043	400			400
5.4% Notes due 2044	500			—
4.9% Notes due 2045	500			—
Pre-merger ACMP Credit facility loans (1)	640			—
Capital lease obligations	5			—
Net unamortized debt premium (discount) (2)	207			(21		)
Long-term debt, including current portion	16,330			9,057
Long-term debt due within one year	(4		)	—
Long-term debt	$	16,326		$	9,057

______________________________________________________

(1) These notes and credit facility loans are associated with Pre-merger ACMP. See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies and Note 2 – Acquisitions.

(2) Includes premium related to the fair value of Pre-merger ACMP debt. See Note 2 – Acquisitions.

(3) Presented as long-term debt due to our intent and ability to refinance.

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

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 net unamortized debt premium (discount) and capital lease obligations, for each of the next five years:

	December 31, 2014
	(Millions)
2015	$	—
2016	375
2017	785
2018	1,140
2019	—

Issuances and retirements

We retired $750 million of 3.8 percent senior unsecured notes that matured on February 15, 2015.

On June 27, 2014, Pre-merger WPZ completed a public offering of $750 million of 3.9 percent senior unsecured notes due 2025 and $500 million of 4.9 percent senior unsecured notes due 2045. Pre-merger WPZ used the net proceeds to repay amounts outstanding under its commercial paper program, to fund capital expenditures, and for general partnership purposes.

On March 4, 2014, Pre-merger WPZ completed a public offering of $1 billion of 4.3 percent senior unsecured notes due 2024 and $500 million of 5.4 percent senior unsecured notes due 2044. Pre-merger WPZ used the net proceeds to repay amounts outstanding under its commercial paper program, to fund capital expenditures, and for general partnership purposes.

On November 15, 2013, Pre-merger WPZ 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. Pre-merger WPZ used the net proceeds to repay amounts outstanding under its commercial paper program, to fund capital expenditures, and for general partnership purposes.

70

Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

Credit Facilities

	December 31, 2014
	Available		Outstanding
	(Millions)
Pre-merger WPZ credit facility (1)(3)
Loans	$	2,500	$	—
Letters of credit sub-limit	1,300		—
Letters of credit under certain bilateral bank agreements			1
Pre-merger ACMP credit facility (2)
Loans	1,750		640
Letters of credit sub-limit	200		2
Swing line advances sub-limit	100		—

________________

(1) Under certain conditions, the amount available may be increased up to an additional $500 million.

(2) Under certain conditions, the amount available may be increased up to an additional $250 million.

(3) Transco and Northwest Pipeline are each able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers.

The agreements governing credit facilities for Pre-merger WPZ and Pre-merger ACMP contain the following terms and conditions:

• 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.

• Each time funds are borrowed under Pre-merger WPZ’s credit facility, the applicable borrower could choose from two methods of calculating interest: a fluctuating base rate equal to the bank’s alternate base rate plus an applicable margin or a periodic fixed rate equal to LIBOR plus an applicable margin. The borrower was required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee were determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings.

• Each time funds are borrowed under Pre-merger ACMP’s credit facility, it may choose from two methods of calculating interest: (1) the greater of (a) the reference rate of Wells Fargo Bank, NA, (b) the federal funds effective rate plus 0.50 percent or (c) the Eurodollar rate which is based on LIBOR plus 1.00 percent, each of which is subject to a margin that varies from 0.50 percent to 1.50 percent, according to its leverage ratio (as defined in the agreement), or (2) the Eurodollar rate plus a margin that varies from 1.50 percent to 2.50 percent, according to its leverage ratio. The revolving credit facility is secured by all of Pre-merger ACMP’s assets. If Pre-merger ACMP reaches investment grade status, it will have the option to release the security under the credit facility and amounts borrowed will bear interest under a specified ratings-based pricing grid. Pre-merger ACMP is required to pay a commitment fee based on the unused portion of its respective credit facility of (a) 0.25 percent to 0.375 percent while it is subject to the leverage-based pricing grid, according to its leverage ratio and (b) 0.15 percent to 0.30 percent while it is subject to the ratings-based pricing grid, according to its senior unsecured long-term debt ratings.

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

Pre-merger WPZ credit facility

On December 1, 2014, Pre-merger WPZ, Transco, Northwest Pipeline, the lenders named therein and an administrative agent entered into Amendment No.1 and Consent to the First Amended & Restated Credit Agreement, dated as of July 31, 2013. The amendment provided the consent of the lenders for this credit agreement to continue for Pre-merger ACMP upon consummation of the merger and the termination of Pre-merger ACMP’s existing credit agreement. In addition, the amendment provided the consent that certain existing liens and guarantees of indebtedness of Pre-merger ACMP to be terminated in connection with the merger would not become liens and guarantees of indebtedness under this credit agreement.

On February 2, 2015, the Pre-merger WPZ credit facility was terminated in connection with the merger.

Pre-merger ACMP credit facility

On February 2, 2015, Pre-merger ACMP credit facility loans outstanding were paid and terminated in connection with the merger.

Credit facilities post-merger

On February 2, 2015, we along with Transco, Northwest Pipeline, the lenders named therein and an administrative agent entered into the Second Amended & Restated Credit Agreement with aggregate commitments available of $3.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. The maturity date of the facility is February 2, 2020. However, the co-borrowers may request an extension of the maturity date for an additional one year period, up to two times, to allow a maturity date as late as February 2, 2022, under certain circumstances. The agreement allows for swing line loans up to an aggregate amount of $150 million, subject to available capacity under the credit facility, and letters of credit commitments of $1.125 billion. Transco and Northwest Pipeline are each able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers.

The agreement governing our credit facility contains the following terms and conditions:

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

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

• Other than swingline loans, each time funds are borrowed, the borrower must choose whether such borrowing will be an alternate base rate borrowing or a Eurodollar borrowing.  If such borrowing is an alternate base rate borrowing, interest is calculated on the basis of the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus ½ of 1 percent and (c) a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus 1 percent, plus, in the case of each of (a), (b) and (c), an applicable margin. If the borrowing is a Eurodollar borrowing, interest is calculated on the basis of LIBOR for the relevant period plus an applicable margin.  Interest on swingline loans is calculated as the sum of the alternate base rate plus an applicable margin.  The borrower is required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings.

Our significant financial covenants require:

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

• The ratio of debt to EBITDA (each as defined in the credit facility) to be no greater than 5 to 1, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the ratio of debt to EBITDA is to be no greater than 5.5 to 1.

• 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.

On February 3, 2015, we entered into a Credit Agreement providing for a $1.5 billion short-term credit facility with a maturity date of August 3, 2015 with an option to extend the maturity date to February 2, 2016 subject to certain circumstances.  Our short-term credit facility has substantially the same financial covenants as our $3.5 billion credit facility.  Under our short-term credit facility any time funds are borrowed, we must choose whether such borrowing will be an alternate base rate borrowing or a Eurodollar borrowing.  Interest is calculated on each of these types of borrowings in the same manner as under our $3.5 billion credit facility. We are required to pay a commitment fee based on the unused portion of the short-term credit facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on our senior unsecured long-term debt ratings.  In the event of certain debt incurrences, issuances of equity, and certain asset sales, we will be required to repay any outstanding borrowings and the commitments under the short-term facility will be reduced on a dollar-for-dollar basis with the net cash proceeds of such events.

We are in compliance with these financial covenants as measured at December 31, 2014.

As of February 24, 2015, $1.3 billion is outstanding under our long-term credit facility.

Commercial Paper Program

Pre-merger WPZ’s commercial paper 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, 2014 and December 31, 2013, having maturity dates less than three months from the date of issuance. At December 31, 2014, $798 million of Commercial paper is outstanding at a weighted average interest rate of 0.92 percent. At December 31, 2013, $225 million of Commercial paper is outstanding at a weighted average interest rate of 0.42 percent.

On February 2, 2015, we amended and restated the commercial paper program for the merger and to allow a maximum outstanding amount of $3 billion of unsecured commercial paper notes. As of February 24, 2015, $1.8 billion is outstanding under this program.

Cash Payments for Interest (Net of Amounts Capitalized)

Cash payments for interest (net of amounts capitalized) were $499 million in 2014, $366 million in 2013, and $381 million in 2012.

73

Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

Leases-Lessee

The future minimum annual rentals under noncancelable operating leases, are payable as follows:

	December 31, 2014
	(Millions)
2015	$	72
2016	62
2017	49
2018	37
2019	33
Thereafter	129
Total	$	382

Total rent expense was $101 million in 2014, $51 million in 2013, and $46 million in 2012 and primarily included in Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income.

Note 14 – Partners’ Capital

Limited partner units presented on the Consolidated Balance Sheet have been adjusted in accordance with the exchange ratios pursuant to the terms of the Merger. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)

The partners’ equity interests in Pre-merger ACMP as of July 1, 2014, have been presented within the capital account of the general partner for interests owned by Williams and noncontrolling interests for interests held by the public as a Contribution from The Williams Companies, Inc. – net within the Consolidated Statement of Changes in Equity. Additionally, activity associated with the partners’ equity interests in Pre-merger ACMP during the period under common control has been presented accordingly within the capital account of the general partner for the interests owned by Williams or noncontrolling interests for interests held by the public. The Pre-merger ACMP partners’ equity includes limited partner common units and Class B units. These Class B units are held by an affiliate of our general partner and receive additional paid-in-kind units in lieu of cash distributions. Each Class B unit became convertible into common units on a one-for-one basis following our distribution paid to unitholders in February 2015.

Transactions which occurred prior to the Merger during 2014 and 2013 are summarized below:

In August 2014, Pre-merger WPZ issued 1,080,448 Pre-merger WPZ common units pursuant to an equity distribution agreement between Pre-merger WPZ and certain banks. The net proceeds of $55 million were used for general partnership purposes. Pre-merger WPZ incurred commission fees of $554 thousandassociated with these transactions.

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

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

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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:

	Total Quarterly Distribution per unit (1)	Unitholders (1)	General Partner (1)
Minimum Quarterly Distribution	$0.3375	98%	2%
First Target Distribution	Up to $0.388125	98	2
Second Target Distribution	Above $0.388125 up to $0.421875	85	15
Third Target Distribution	Above $0.421875 up to $0.50625	75	25
Thereafter	Above $0.50625	50	50

_____________

(1) Table reflects the completion of the Merger. See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.

The table above assumes that the Partnership’s general partner maintains its two percent general partner interest, that there are no arrearages on common units and the general partner continues to own the IDRs. The maximum distribution sharing percentage of 50 percent includes distributions paid to the general partner on its two percent general partner interest and does not include any distributions that the general partner may receive on limited partner units that it owns or may acquire.

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.

Note 15 – Equity-Based Compensation

Williams 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 restricted stock units. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets being achieved.

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

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

Operating and maintenance expenses and Selling, general, and administrative expenses include equity-based compensation expense for the years ended December 31, 2014, 2013, and 2012 of $14 million, $12 million and $13 million, respectively.

Pre-merger ACMP Plan Information

Certain employees of Pre-merger ACMP’s general partner received equity-based compensation through Pre-merger ACMP’s equity-based compensation programs. The fair value of the awards issued was determined based on the fair market value of the units of Pre-merger ACMP on the date of grant. This value is being amortized over the vesting period, which is from one to four years from the date of grant. Beginning in 2015 certain of these employees will transition to our equity-based compensation plans. No additional awards of units through Pre-merger ACMP’s equity-based compensation programs are expected. Included in Operating and maintenance expenses; Selling, general, and administrative expenses; and Equity earnings (losses) is equity-based compensation expense of $11 million in 2014 related to Pre-merger ACMP’s equity-based compensation program. As of December 31, 2014, there was $65 million of unrecognized compensation expense attributable to the outstanding awards, which does not include the effect of estimated forfeitures of $6 million. These amounts are expected to be recognized over a weighted average period of 2.3 years.

The following summary reflects nonvested restricted stock unit activity for awards issued by Pre-merger ACMP and related information for the six months ended December 31, 2014:

Restricted Stock Units Outstanding	Units	Weighted- Average Fair Value
	(Millions)
Granted	1.3	$	59.67
Forfeited	—	$	63.89
Vested	—	$	63.75
Nonvested at December 31, 2014	1.3	$	59.35

76

Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

Note 16 – 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, 2014:
Measured on a recurring basis:
ARO Trust investments	$	48		$	48		$	48	$	—		$	—
Energy derivatives assets not designated as hedging instruments	3			3			1		—			2
Energy derivatives liabilities not designated as hedging instruments	(2		)	(2		)	—		—			(2		)
Additional disclosures:
Notes receivable and other	5			4			—		4			—
Long-term debt, including current portion (1)	(16,325		)	(16,607		)	—		(16,607		)	—
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, including current portion	(9,057		)	(9,581		)	—		(9,581		)	—

______________

(1) Excludes capital leases

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 (ARO 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.

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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, 2014 or 2013.

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 other in the Consolidated Balance Sheet.

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

Assets and liabilities measured at fair value on a nonrecurring basis

During 2014, we designated certain equipment within our Northeast G&P segment as held for sale. The estimated fair value (less cost to sell) of the equipment at December 31, 2014, is $32 million and is reported in Other current assets in the Consolidated Balance Sheet. The estimated fair value was determined by a market approach based on our analysis of information related to sales of similar pre-owned equipment in the principal market. This analysis resulted in impairment charges of$27 million, recorded in Other (income) expense – net within Costs and expenses. This nonrecurring fair value measurement fell within Level 3 of the fair value hierarchy.

In December 2014, certain materials and equipment within our Access Midstream segment was designated as held for sale. The estimated fair value (less cost to sell) of the equipment at December 31, 2014, is $1 million and is reported in Other current assets in the Consolidated Balance Sheet.The estimated fair value was determined by a market approach based on our analysis of information related to sales of similar pre-owned equipment in the principal market. This analysis resulted in an impairment charge of $12 million, which is included in Other (income) expense – net within Costs and expenses. This nonrecurring fair value measurement fell within Level 3 of the fair value hierarchy.

Guarantees

We are required by our revolving credit agreements 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.

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Williams Partners L.P.

Notes to Consolidated Financial Statements – (Continued)

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,
	2014		2013
	(Millions)
NGLs, natural gas, and related products and services	$	728	$	341
Transportation of natural gas and related products	175		193
Other	2		34
Total	$	905	$	568

Customers include producers, distribution companies, industrial users, gas marketers and pipelines primarily located in the continental United States and Canada. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. On December 31, 2014, one customer accounted for $308 million of the consolidated Accounts and notes receivable balance.

Revenues

In 2014, 2013 and 2012, we had one customer in our NGL & Petchem Services segment that accounted for 5 percent, 9 percent, and 14 percent of our consolidated revenues, respectively. In 2014, we also had one customer, primarily within our Access Midstream segment, that accounted for 9 percent of our consolidated revenues.

Note 17 – 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, 2014, we have accrued liabilities totaling $19 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,

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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, 2014, we have accrued liabilities of $11 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, 2014, we have accrued liabilities totaling $8 million for these costs.

Geismar Incident

As a result of the previously discussed Geismar Incident, there were two fatalities and numerous individuals (including employees and contractors) reported injuries, which varied from minor to serious. We are addressing the following matters in connection with the Geismar Incident.

On June 28, 2013, the Louisiana Department of Environmental Quality (LDEQ) issued a Consolidated Compliance Order & Notice of Potential Penalty 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. On November 12, 2014, the LDEQ issued a Notice of Potential Penalty for the alleged violations. LDEQ then issued a Penalty Assessment on November 21, 2014. We paid a penalty of $194,306 on December 1, 2014.

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. On June 16, 2014, we received a request for information related to the Geismar Incident from the EPA under Section 114 of the Clean Air Act to which we responded on August 13, 2014. The EPA could issue penalties pertaining to final determinations.

On December 11, 2013, the Occupational Safety and Health Administration (OSHA) issued citations in connection with its investigation of the June 13, 2013 incident, which included a Notice of Penalty for $99,000. We settled the citations with OSHA on September 12, 2014 for a penalty of $36,000. The settlement was judicially approved on September 23, 2014, and the order approving settlement became a final order on November 10, 2014. On June 25, 2013, OSHA commenced a second inspection pursuant to its Refinery and Chemical National Emphasis Program (NEP). OSHA did not issue a citation in connection with this NEP inspection and there is a six-month statute of limitations for violation of the Occupational Safety and Health Act of 1970 or regulations promulgated under such act.

Additionally, multiple lawsuits, including class actions for alleged offsite impacts, property damage, customer claims, and personal injury, have been filed against various of our subsidiaries. Due to ongoing litigation concerning defenses to liability and limited information as to the nature and extent of plaintiffs’ damages, we cannot reasonably estimate a range of potential loss related to these contingencies at this time.

Royalty Matters

Certain of our customers, including one major customer, have been named in various lawsuits alleging underpayment of royalty. In certain of these cases, we have also been named as a defendant based on allegations that we improperly participated with that major customer in causing the alleged royalty underpayments. We have also received subpoenas from the United States Department of Justice and the Pennsylvania Attorney General requesting documents relating to the agreements between us and our major customer and calculations of the major customer’s

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royalty payments. We believe that the claims asserted to date are subject to indemnity obligations owed to us by that major customer. Due to the preliminary status of the cases, we are unable to estimate a range of liability at this time.

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 $552 million at December 31, 2014.

Note 18 – Segment Disclosures

Our reportable segments are Access Midstream, 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

As of December 31, 2014, we evaluate segment operating performance based on Segment profit (loss) from operations, which includes Segment revenues from external and internal customers, segment costs and expenses,Equity earnings (losses) and Income (loss) from investments. 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 geographic area data includes Revenues from external customers based on product shipment origin and Long-lived assets based upon physical location.

		United States		Canada		Total
		(Millions)
Revenues from external customers:
	2014	$	7,212	$	197	$	7,409
	2013	6,685		150		6,835
	2012	7,320		151		7,471
Long-lived assets:
	2014	$	37,798	$	1,095	$	38,893
	2013	18,776		1,137		19,913
	2012	16,637		870		17,507

Long-lived assets are comprised of property, plant, and equipment, goodwill, and other intangible assets.

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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.

	Access Midstream		Northeast G&P			Atlantic- Gulf		West		NGL & Petchem Services			Eliminations			Total
	(Millions)
2014
Segment revenues:
Service revenues
External	$	781	$	450		$	1,497	$	1,034	$	126		$	—		$	3,888
Internal	—		1			4		—		—			(5		)	—
Total service revenues	781		451			1,501		1,034		126			(5		)	3,888
Product sales
External	—		225			499		70		2,727			—			3,521
Internal	—		5			354		476		259			(1,094		)	—
Total product sales	—		230			853		546		2,986			(1,094		)	3,521
Total revenues	$	781	$	681		$	2,354	$	1,580	$	3,112		$	(1,099	)	$	7,409
Segment profit (loss)	$	265	$	212		$	635	$	631	$	265					$	2,008
Less equity earnings (losses)	96		19			76		—		37						228
Segment operating income (loss)	$	169	$	193		$	559	$	631	$	228					1,780
General corporate expenses																(171		)
Operating income																$	1,609
Other financial information:
Depreciation and amortization	$	296	$	170		$	379	$	239	$	67					$	1,151
2013
Segment revenues:
Service revenues
External	$	—	$	335		$	1,414	$	1,053	$	112		$	—		$	2,914
Internal	—		—			10		1		—			(11		)	—
Total service revenues	—		335			1,424		1,054		112			(11		)	2,914
Product sales
External	—		166			830		64		2,861			—			3,921
Internal	—		—			95		708		294			(1,097		)	—
Total product sales	—		166			925		772		3,155			(1,097		)	3,921
Total revenues	$	—	$	501		$	2,349	$	1,826	$	3,267		$	(1,108	)	$	6,835
Segment profit (loss)	$	—	$	(24	)	$	614	$	741	$	346					$	1,677
Less:
Equity earnings (losses)	—		(7		)	72		—		39						104
Income (loss) from investments	—		—			—		—		(3		)				(3		)
Segment operating income (loss)	$	—	$	(17	)	$	542	$	741	$	310					1,576
General corporate expenses																(169		)
Operating income																$	1,407
Other financial information:
Depreciation and amortization	$	—	$	132		$	363	$	236	$	60					$	791

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	Access Midstream		Northeast G&P			Atlantic- Gulf		West		NGL & Petchem Services			Eliminations			Total
	(Millions)
2012
Segment revenues:
Service revenues
External	$	—	$	168		$	1,371	$	1,067	$	108		$	—		$	2,714
Internal	—		—			12		5		—			(17		)	—
Total service revenues	—		168			1,383		1,072		108			(17		)	2,714
Product sales
External	—		2			709		40		4,006			—			4,757
Internal	—		—			363		1,089		258			(1,710		)	—
Total product sales	—		2			1,072		1,129		4,264			(1,710		)	4,757
Total revenues	$	—	$	170		$	2,455	$	2,201	$	4,372		$	(1,727	)	$	7,471
Segment profit (loss)	$	—	$	(37	)	$	574	$	980	$	390					$	1,907
Less:
Equity earnings (losses)	—		(23		)	92		—		42						111
Income (loss) from investments	—		—			—		—		(4		)				(4		)
Segment operating income (loss)	$	—	$	(14	)	$	482	$	980	$	352					1,800
General corporate expenses																(190		)
Operating income																$	1,610
Other financial information:
Depreciation and amortization	$	—	$	76		$	381	$	234	$	43					$	734

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

	Access Midstream		Northeast G&P		Atlantic- Gulf		West		NGL & Petchem Services		Eliminations			Total
	(Millions)
2014
Service:
Regulated natural gas transportation and storage	$	—	$	—	$	1,313	$	470	$	—	$	(2	)	$	1,781
Gathering & processing	781		394		79		544		—		(2		)	1,796
2013
Service:
Regulated natural gas transportation and storage	$	—	$	—	$	1,244	$	469	$	—	$	(9	)	$	1,704
Gathering & processing	—		302		70		562		—		(2		)	932
2012
Service:
Regulated natural gas transportation and storage	$	—	$	—	$	1,171	$	438	$	—	$	(11	)	$	1,598
Gathering & processing	—		159		80		607		—		(2		)	844

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The following table reflects Total assets, Investments, and Additions to long-lived assets by reportable segments:

	Total Assets at December 31,						Investments at December 31,				Additions to Long-Lived Assets at December 31,
	2014			2013			2014		2013		2014		2013		2012
	(Millions)
Access Midstream (1)	$	23,024		$	—		$	6,004	$	—	$	16,964	$	—	$	—
Northeast G&P (2)	7,314			6,229			891		737		1,079		1,376		3,909
Atlantic-Gulf	11,124			10,007			985		930		1,593		1,072		1,002
West	4,620			4,767			—		—		168		210		360
NGL & Petchem Services	3,510			3,035			519		520		601		746		571
Other corporate assets	563			147			—		—		8		5		16
Eliminations (3)	(833		)	(614		)	—		—		—		—		—
Total	$	49,322		$	23,571		$	8,399	$	2,187	$	20,413	$	3,409	$	5,858

(1) 2014 Additions to long-lived assets within our Access Midstream segment primarily includes the acquisition-date fair value of long-lived assets from the ACMP Acquisition (Note 2 – Acquisitions).

(2) 2012 Additions to long-lived assets includes the Caiman and Laser Acquisitions. (See Note 2 – Acquisitions.)

(3) Eliminations primarily relate to the intercompany accounts receivable generated by our cash management program.

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Note 19 – Subsequent Events

Debt Items

On March 3, 2015, we completed a public offering of $1.25 billion of 3.6 percent senior notes due 2022, $750 million of 4.0 percent senior notes due 2025 and $1 billion of 5.1 percent senior notes due 2045. We used the net proceeds to repay amounts outstanding under our commercial paper program and credit facility, to fund capital expenditures, and for general partnership purposes.

On April 15, 2015, we paid $783 million, including a redemption premium, to retire $750 million of 5.875 percent senior notes due 2021.

At May 4, 2015, we had $536 million outstanding under our commercial paper program.

We had no outstanding borrowings under our long-term credit facility at May 4, 2015.

Distributions

The Board of Directors of our general partner declared a cash distribution of $0.85 per common unit on April 20, 2015 to be paid on May 14, 2015, to unitholders of record at the close of business on May 7, 2015.

Acquisition

On April 6, 2015, we announced our agreement to acquire an additional 21 percent equity interest in UEOM for $575 million, subject to the right of the other member of UEOM to participate in the transaction. If the other member exercises this right, we would acquire an approximate 13 percent interest and the other member would acquire an approximate 8 percent interest.

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Quarterly Financial Data

(Unaudited)

Summarized quarterly financial data are as follows:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(Millions, except per-unit amounts)
2014
Revenues	$	1,693	$	1,616	$	2,008	$	2,092
Product costs	769		724		807		716
Net income	352		223		247		462
Net income attributable to controlling interests	352		221		233		382
Basic and diluted net income per common unit	.44		.13		.08		.35
2013
Revenues	$	1,806	$	1,763	$	1,618	$	1,648
Product costs	790		801		710		726
Net income	344		272		285		218
Net income attributable to controlling interests	344		271		284		217
Basic and diluted net income per common unit	.61		.38		.64		$	.15

The sum of net income per common unit for the four quarters may not equal the total net income per common unit for the year due to changes in the average number of common units outstanding and rounding.

As discussed in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies, Williams Partners L.P. and Access Midstream Partners, L.P. completed a merger between entities under common control. As such, Pre-Merger ACMP’s historical financial position, results of operations, and cash flows were combined with those of Pre-merger WPZ for periods under common control (periods subsequent to July 1, 2014) and are reflected at Williams’ historical basis (see Note 2 – Acquisitions). Additionally, certain acquisition and financing-related costs were allocated to the merged partnership.

Previously presented limited partner units of Pre-merger WPZ have been adjusted to reflect the legal capital of Pre-merger ACMP in accordance with the exchange ratios, which has resulted in a change to historical net income per unit. Historical earnings of Pre-merger ACMP prior to the Merger have been presented herein as allocated to the capital account of the general partner for interest owned by Williams or to noncontrolling interests for interests held by the public. Summarized quarterly financial data has been retrospectively adjusted to reflect the change in the net income per unit information. The increases (decreases) to amounts previously report were as follows:

	First Quarter		Second Quarter			Third Quarter		Fourth Quarter
	(Millions, except per-unit amounts)
2014
Revenues	$	—	$	—		$	300	N/A
Product costs	—		—			—		N/A
Net income	—		(11		)	29		N/A
Net income attributable to controlling interests	—		(11		)	16		N/A
Basic and diluted net income per common unit	.08		.02			.01		N/A
2013
Basic and diluted net income per common unit	$	.11	$	.07		$	.12	$	.03

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(Unaudited)

2014

Net income for fourth-quarter 2014 includes:

• $167 million in revenue associated with minimum volume commitment fees at Access Midstream;

• $154 million gain related to a contingency settlement at Northeast G&P (see Note 7 – Other Income and Expenses);

• $71 million gain associated with insurance recoveries related to the Geismar Incident at NGL & Petchem Services (see Note 7 – Other Income and Expenses);

• $10 million impairment loss on certain equipment at Atlantic-Gulf (see Note 7 – Other Income and Expenses);

• $12 million impairment loss on certain materials and equipment held for sale at Access Midstream (see Note 7 – Other Income and Expenses);

• $13 million impairment loss on certain materials and equipment at Northeast G&P (see Note 7 – Other Income and Expenses);

• $17 million unfavorable inventory adjustment related to a decrease in prices at NGL & Petchem Services;

• $31 million of ACMP acquisition, merger, and transition-related expenses primarily at Access Midstream (see Note 2 – Acquisitions and Note 7 – Other Income and Expenses).

Net income for third-quarter 2014 includes:

• $12 million net gain related to a partial acreage dedication release at Northeast G&P (see Note 7 – Other Income and Expenses);

• $13 million in ACMP acquisition expenses at Access Midstream, in addition to $11 million of merger and transition-related expenses (see Note 2 – Acquisitions).

Net income for second-quarter 2014 includes:

• $50 million gain associated with insurance recoveries related to the Geismar Incident at NGL & Petchem Services (see Note 7 – Other Income and Expenses);

• $11 million of ACMP acquisition-related expenses, including $9 million of financing expenses (see Note 2 – Acquisitions);

• $17 million impairment loss on certain materials and equipment at Northeast G&P (see Note 7 – Other Income and Expenses).

Net income for first-quarter 2014 includes gain of $125 million associated with insurance recoveries related to the Geismar Incident at NGL & Petchem Services (see Note 7 – Other Income and Expenses).

2013

Net income for fourth-quarter 2013 includes:

• $14 million in expenses associated with the Geismar Incident at NGL & Petchem Services (see Note 7 – Other Income and Expenses);

• $16 million loss associated with a producer claim against us at Northeast G&P (see Note 7 – Other Income and Expenses).

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(Unaudited)

Net income for third-quarter 2013 includes:

• $50 million gain associated with insurance recoveries related to the Geismar Incident at NGL & Petchem Services (see Note 7 – Other Income and Expenses);

• $9 million loss associated with a producer claim against us at Northeast G&P (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).

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