WILLIAMS PARTNERS L.P. - 10-K - Management's Discussion and Analysis of Financial Condition and Results of Operations

(Edgar Glimpses Via Acquire Media NewsEdge) General We are primarily an energy infrastructure company focused on connecting North America's significant hydrocarbon resource plays to growing markets for natural gas and natural gas liquids (NGLs). We manage our business and analyze our results of operations on a segment basis. Our operations are divided into two business segments: Gas Pipeline and Midstream Gas & Liquids (Midstream).

• Gas Pipeline includes Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline GP (Northwest Pipeline), which own and operate interstate natural gas pipelines. Gas Pipeline also holds interests in interstate and intrastate natural gas pipeline systems including a 50 percent interest in Gulfstream Natural Gas System L.L.C.

(Gulfstream) and a 51 percent interest in Constitution Pipeline Company, LLC (Constitution).

• Midstream is comprised primarily of significant, large-scale operations in the Rocky Mountain and Gulf Coast regions, operations in the Marcellus Shale region, and various equity investments in domestic natural gas gathering and processing assets and NGL fractionation and transportation assets. Midstream's assets also include substantial operations and investments in the Four Corners region, the Piceance basin, an NGL fractionator and storage facilities near Conway, Kansas as well as an interest and operatorship of an olefins production facility in Geismar, Louisiana along with a refinery grade propylene splitter and pipelines in the Gulf Coast region. Midstream's interest and operatorship of the olefins production facility in Geismar, Louisiana and associated assets is a result of a fourth-quarter 2012 acquisition from a subsidiary of The Williams Companies, Inc. (Williams).

Williams currently holds an approximate 70 percent interest in us, comprised of an approximate 68 percent limited partner interest and all of our 2 percent general partner interest.

Acquisitions In February 2012, we completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC (Laser Acquisition). These entities primarily own the Laser Gathering System, which is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in the Marcellus Shale in Susquehanna County, Pennsylvania, as well as 10 miles of gathering lines in southern New York. This acquisition represents a strategic platform to enhance our expansion in the Marcellus Shale by providing our customers with both operational flow assurance and marketing flexibility. (See Results of Operations - Segments, Midstream Gas & Liquids.) In April 2012, we completed the acquisition of 100 percent of the ownership interest in Caiman Eastern Midstream, LLC (Caiman Acquisition). The acquired entity operates a gathering and processing business in northern West Virginia, southwestern Pennsylvania and eastern Ohio. We believe the acquisition will provide us with a significant footprint and growth potential in the NGL-rich portion of the Marcellus Shale. (See Results of Operations - Segments, Midstream Gas & Liquids.) In November 2012, we completed the acquisition of Williams' 83.3 percent undivided interest and operatorship of the olefins production facility located in Geismar, Louisiana, along with a refinery-grade propylene splitter and pipelines in the Gulf region (Geismar Acquisition), for total consideration valued at $2.364 billion, including 42,778,812 of our limited partner units, $25 million in cash and an increase in the general partner capital account to maintain Williams' 2 percent general partner interest. The acquisition is expected to bring more certainty to cash flows that are currently exposed to volatile ethane prices by shifting the commodity price exposure to ethylene.

Prior period segment disclosures have been recast for this transaction. (See Results of Operations - Segments, Midstream Gas & Liquids.) 51-------------------------------------------------------------------------------- Table of Contents Distributions In January 2013, our general partner's Board of Directors approved a quarterly distribution to unitholders of $0.8275 per unit, an increase of approximately 2.5 percent over the prior quarter and 8.5 percent over the same period in the prior year. (See Management's Discussion and Analysis of Financial Condition and Liquidity.) Overview During the second quarter 2012, NGL margins declined sharply largely attributable to a record-warm winter, a slowing global economy, and growing NGL supplies. The downward trend of per-unit NGL margins leveled-off during the second-half of 2012. We have been impacted by this environment as our net income for 2012 decreased by $279 million compared to 2011, primarily due to lower NGL production and marketing margins, higher operating costs and selling, general, and administrative expenses (SG&A), partially offset by an increase in fee revenues and olefin production margins. See additional discussion in Results of Operations.

Our net cash provided by operating activities for 2012 decreased $272 million compared to 2011 primarily due to lower operating income.

Abundant and low-cost natural gas reserves in the United States continue to drive strong demand for midstream and pipeline infrastructure. We believe that we have successfully positioned our energy infrastructure businesses for significant future growth, as highlighted by the following accomplishments during 2012 through the present: Recent Events In addition to the previously discussed acquisitions, we note the following: • In February 2012, we announced a new interstate gas pipeline project. The new 120-mile Constitution Pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems. We currently own 51 percent of Constitution Pipeline with two other parties holding 25 percent and 24 percent, respectively. This project, along with the newly acquired Laser Gathering System and our Springville pipeline, are key steps in our strategy to create the Susquehanna Supply Hub, a major natural gas supply hub in northeastern Pennsylvania. In April 2012, we began the Federal Energy Regulatory Commission (FERC) pre-filing process for the Constitution Pipeline and expect to file a FERC application during the second quarter of 2013.

• In April 2012, we completed an equity issuance of 10 million common units representing limited partner interests in us at a price of $54.56 per unit.

Subsequently, we sold an additional 973,368 common units for $54.56 per unit to the underwriters upon the underwriters' exercise of their option to purchase additional common units. Also in April 2012, we sold 16,360,133 common units to Williams for $1 billion. The net proceeds of these transactions were used for general partnership purposes, including funding a portion of the cash purchase price of the Caiman Acquisition.

• In July 2012, Transco issued $400 million of 4.45 percent senior unsecured notes due 2042 to investors in a private debt placement. A portion of these proceeds was used to repay Transco's $325 million 8.875 percent senior unsecured notes that matured on July 15, 2012. An offer to exchange these unregistered notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended, was commenced in November 2012 and completed in December 2012.

• In July 2012, we formed Caiman Energy II, LLC with Caiman Energy, LLC and others to develop large-scale natural gas gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale, primarily in Ohio and northwest Pennsylvania. As a result, we plan to contribute $380 million through 2014 to fund a portion of Blue Racer Midstream, a joint project formed in December 2012 between Caiman Energy II, LLC and another party.

52 -------------------------------------------------------------------------------- Table of Contents • Following Williams' spin-off of WPX Energy, Inc. (WPX) at the end of 2011 and in consideration of the growth plans of the ongoing business, Williams initiated an organizational restructuring evaluation to better align resources to support an ongoing business strategy 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. This effort has resulted in changes in our organizational structure effective January 1, 2013 and, thus, how our underlying businesses will be managed. As a result, our segment reporting structure will change beginning in 2013.

• In August 2012, we completed an equity issuance of 8,500,000 common units representing limited partner interests in us at a price of $51.43 per unit.

Subsequently, we sold an additional 1,275,000 common units for $51.43 per unit to the underwriters upon the underwriters' exercise of their option to purchase additional common units. The net proceeds of these transactions were primarily used to repay outstanding borrowings on our senior unsecured revolving credit facility (revolver).

• In August 2012, we completed a public offering of $750 million of 3.35 percent senior unsecured notes due 2022. We used the net proceeds to repay outstanding borrowings on our revolver and for general partnership purposes.

• In January 2013, we agreed to sell a 49 percent ownership interest in our Gulfstar FPS™ project to a third party. The transaction is expected to close in second-quarter 2013, at which time we expect the third party will contribute $225 million to fund its proportionate share of the project costs, following with monthly capital contributions to fund its share of ongoing construction.

Outlook for 2013 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 operational excellence and customer satisfaction. We believe that accomplishing these goals will position us to deliver an attractive return to our unitholders.

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

In light of the above, our business plan for 2013 continues to reflect both significant capital investment and growth in distributions. Our planned capital investments for 2013 total approximately $3.75 billion, of which we expect to fund a significant portion through debt and equity issuances. 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; • Availability of capital; • Lower than expected levels of cash flow from operations; • Counterparty credit and performance risk; • Decreased volumes from third parties served by our midstream business; • Unexpected significant increases in capital expenditures or delays in capital project execution; 53 -------------------------------------------------------------------------------- Table of Contents • Lower than anticipated energy commodity prices and margins; • Changes in the political and regulatory environments; • Physical damages to facilities, especially damage to offshore facilities by named windstorms.

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

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 and Intangible Assets At December 31, 2012, our Consolidated Balance Sheet includes $649 million of goodwill and $1.7 billion in intangible assets related to the Laser and Caiman Acquisitions, which were completed earlier in the year.

Goodwill We performed our annual assessment of goodwill for impairment as of October 1.

All of our goodwill is allocated to our Northeast gathering and processing businesses (the reporting unit). In our evaluation, our estimate of the fair value of the reporting unit exceeded its carrying value, including goodwill, and thus no impairment was recognized. If the carrying value of the reporting unit had exceeded its fair value, a computation of the implied fair value of the goodwill would have been compared with its related carrying value. If the carrying value of the reporting unit goodwill had exceeded the implied fair value of that goodwill, an impairment loss would have been recognized in the amount of the excess.

The fair value of the reporting unit was estimated using an income approach (discounted cash flows). Significant estimates and assumptions in this determination included our estimate of the expected future cash flows associated with the underlying operations. These assumptions include projections of future production volumes and timing, certain energy commodity prices, capital expenditures and recovery provisions, gathering fees, and operating expenses.

Judgments and assumptions are inherent in our estimate of future cash flows used to evaluate these assets. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of an impairment charge in the consolidated financial statements. Our calculation of fair value used a discount rate of 11.25 percent.

We estimate that an increase of approximately 250 basis points in the discount rate could result in a fair value of the reporting unit below its carrying value, all other variables held constant.

Other intangible assets We evaluate other intangible assets for both changes in the expected remaining useful lives and impairment when events or changes in circumstances indicate, in our management's judgment, that the estimated useful lives have changed or the carrying value of such assets may not be recoverable. Changes in an estimated remaining useful life would be reflected prospectively through amortization over the revised remaining useful life. When an indicator of impairment has occurred, we compare our management's estimate of undiscounted future cash flows attributable to the intangible assets to the carrying value of the assets to determine whether an impairment has occurred and we apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes. If an impairment of the carrying value has occurred, we determine the amount of the impairment 54-------------------------------------------------------------------------------- Table of Contents 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. Indicators of potential impairment may include: • Laws prohibiting the production of reserves in the areas where our assets from the Laser and Caiman Acquisitions operate; • The development of alternative energy sources that would halt the production of reserves in these areas; or • The loss of or failure to renew customer contracts. A significant portion of the value allocated to these contracts in our purchase price allocation was based on our assumptions regarding our ability and intent to renew or renegotiate existing customer contracts. (See Note 2 of Notes to Consolidated Financial Statements.) We have not evaluated our intangible assets for impairment as of December 31, 2012, as there were no indicators of potential impairment.

Equity-method Investments At December 31, 2012, our Consolidated Balance Sheet includes approximately $1.8 billion of investments that are accounted for under the equity method of accounting. We evaluate these investments for impairment when events or changes in circumstances indicate, in our management's judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We generally estimate the fair value of our investments using an income approach where significant judgments and assumptions include expected future cash flows and the appropriate discount rate. In some cases, we may utilize a form of market approach to estimate the fair value of our investments.

If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge. Events or changes in circumstances that may be indicative of an other-than-temporary decline in value will vary by investment, but may include: • Lower than expected cash distributions from investees; • Significant asset impairments or operating losses recognized by investees; • Significant delays in or lack of producer development or significant declines in producer volumes in markets served by investees; and, • 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, 2012.

55-------------------------------------------------------------------------------- Table of Contents 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, 2012. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

Years Ended December 31, $ Change % Change $ Change % Change from from from from 2012 2011* 2011* 2011 2010* 2010* 2010 (Millions) Revenues: Service revenues $ 2,709 +192 +8% $ 2,517 +171 +7% $ 2,346 Product sales 4,611 -586 -11% 5,197 +1,084 +26% 4,113 Total revenues 7,320 7,714 6,459 Costs and expenses: Product costs 3,526 +425 +11% 3,951 -728 -23% 3,223 Operating and maintenance expenses 987 -39 -4% 948 -111 -13% 837 Depreciation and amortization expenses 714 -93 -15% 621 -43 -7% 578 Selling, general, and administrative expenses 553 -147 -36% 406 +2 - 408 Other (income) expense - net 23 -10 -77% 13 -27 NM (14 ) Total costs and expenses 5,803 5,939 5,032 Operating income 1,517 1,775 1,427 Equity earnings (losses) 111 -31 -22% 142 +33 +30% 109 Interest expense (405 ) +10 +2% (415 ) -51 -14% (364 ) Interest income 3 +1 +50% 2 -2 -50% 4 Other income (expense) - net 6 -1 -14% 7 -5 -42% 12 Net income 1,232 1,511 1,188 Less: Net income attributable to noncontrolling interests - - - - +16 +100% 16 Net income attributable to controlling interests $ 1,232 $ 1,511 $ 1,172 * + = 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.

2012 vs. 2011 The increase in service revenues is primarily due to Midstream's higher fee revenues resulting from increased gathering and processing fee revenues from higher volumes in the Marcellus Shale, including new volumes on our recently acquired gathering and processing assets in our Ohio Valley Midstream and Susquehanna Supply Hub businesses and higher volumes in the western deepwater Gulf of Mexico and in the Piceance basin. Additionally, Gas Pipeline's transportation revenues increased from expansion projects placed into service in 2011 and 2012.

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

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

The increase in operating and maintenance expenses is primarily due to Gas Pipeline's increased employee-related benefit costs and increased pipeline maintenance as well as Midstream's increased maintenance expenses primarily associated with its new assets acquired in 2012, partially offset by lower costs in our Four Corners area related to the consolidation of certain operations.

The increase in depreciation and amortization expenses is primarily associated with Midstream's new assets acquired in 2012 (see Note 2 of Notes to Consolidated Financial Statements).

The increase in SG&A is primarily due to an increase of $71 million at Midstream reflecting $23 million of acquisition and transition-related costs as well as higher employee-related and information technology expenses driven by general growth within Midstream's business operations. Also, general corporate expenses increased $66 million in 2012 related to our higher proportionate share of these costs as a result of Williams' spin-off of WPX, which was completed on December 31, 2011. This increase in general corporate expenses includes $25 million of reorganization-related costs in 2012 primarily relating to Williams' engagement of a consulting firm to assist in better aligning resources to support our business strategy following Williams' spin-off of WPX.

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

Equity earnings (losses) decreased primarily due to lower Laurel Mountain Midstream, LLC (Laurel Mountain), Aux Sable Liquid Products L.P. (Aux Sable) and Discovery Producer Services LLC (Discovery) equity earnings at Midstream primarily reflecting lower operating results of these investees and the impairment of two minor NGL processing plants at Laurel Mountain, partially offset by an increase in equity earnings at Gas Pipeline primarily resulting from the acquisition of an additional 24.5 percent interest in Gulfstream in May 2011.

Interest expense decreased due to an increase in interest capitalized related to construction projects primarily at Midstream, partially offset by an increase in interest incurred related to increased borrowings (see Note 11 of Notes to Consolidated Financial Statements).

2011 vs. 2010 The increase in service revenues is primarily due to higher Midstream gathering and processing fee revenue in the Marcellus Shale related to gathering assets acquired at the end of 2010, in the western deepwater Gulf of Mexico related to assets placed into service in late 2010, and in the Piceance basin as a result of an agreement executed in November 2010. These increases are partially offset by a decline in fee revenue in the eastern deepwater Gulf of Mexico primarily due to natural field declines. Gas Pipeline's transportation revenues increased primarily due to expansion projects placed in service in 2010 and 2011.

The increase in product sales is primarily due to higher marketing and NGL and olefin production revenues at Midstream as a result of higher average energy commodity prices, partially offset by a decrease in NGL production volumes.

The increase in product costs is primarily due to increased marketing purchases and olefin feedstock costs at Midstream primarily resulting from higher average energy commodity prices. These increases are partially offset by decreased costs associated with production of NGLs reflecting lower average natural gas prices and lower NGL production volumes at Midstream.

The increase in operating and maintenance expenses is primarily due to increased maintenance expenses and higher property insurance expenses at Midstream.

57-------------------------------------------------------------------------------- Table of Contents The increase in depreciation and amortization expenses is primarily due to assets placed in service late in 2010, along with increased depreciation of a facility, which was idled in 2012, at Midstream.

The unfavorable change in other (income) expense - net within operating income primarily reflects: • $15 million of lower involuntary conversion gains in 2011 as compared to 2010 at Midstream due to insurance recoveries that are in excess of the carrying value of assets; • The absence of a $12 million gain in 2010 on the sale of part of our ownership interest in certain Piceance gathering assets at Midstream; • $4 million lower sales of base gas from Hester Storage Field in 2011 compared to 2010 at Gas Pipeline.

Partially offsetting the unfavorable change is $8 million related to the net reversal of project feasibility costs from expense to capital in 2011 at Gas Pipeline (see Note 6 of Notes to Consolidated Financial Statements).

The increase in operating income generally reflects an improved energy commodity price environment in 2011 compared to 2010 and increased fee revenues, partially offset by higher operating costs and an unfavorable change in other (income) expense - net as previously discussed.

Equity earnings (losses) changed favorably primarily due to a $21 million increase from Gulfstream as a result of an increased ownership interest at Gas Pipeline and a $14 million increase from the 2010 acquisition of an additional interest in Overland Pass Pipeline Company LLC (OPPL) at Midstream.

The increase in interest expense is primarily due to the $3.5 billion of senior notes issued in February 2010 and $600 million of senior notes issued in November 2010. In addition, 2010 project completions at Midstream contributed to a decrease in interest capitalized.

Net income attributable to noncontrolling interests decreased due to the merger with Williams Pipeline Partners L.P., which was completed in the third quarter of 2010.

58 -------------------------------------------------------------------------------- Table of Contents Results of Operations - Segments Gas Pipeline Overview Gas Pipeline's strategy to create value focuses on maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets.

Gas Pipeline's 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 little near-term impact on revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.

Significant events of 2012 include: Expansion projects Mid-Atlantic Connector In July 2011, we received approval from the FERC to expand our existing natural gas transmission system from North Carolina to markets as far downstream as Maryland. The capital cost of the project was approximately $60 million. The project was placed into service in the first quarter of 2013, increasing capacity by 142 Mdth/d.

Virginia Southside In December 2012, we filed an application with the FERC to expand our existing natural gas transmission system from New Jersey to a proposed power station in Virginia and a delivery point in North Carolina. The capital cost of the project is estimated to be approximately $300 million. We plan to place the project into service in September 2015, which is expected to increase capacity by 270 Mdth/d.

Constitution Pipeline In April 2012, we began the FERC pre-filing process for a new interstate gas pipeline project. We currently own 51 percent of Constitution Pipeline with two other parties holding 25 percent and 24 percent, respectively. We will be the operator of Constitution Pipeline. The new 120-mile Constitution Pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems. The total cost of the entire project is estimated to be $680 million. We plan to place the project into service in March 2015, with an expected capacity of 650 Mdth/d. The pipeline is fully subscribed with two shippers. We expect to file a FERC application during the second quarter of 2013.

Mid-South In August 2011, we received approval from the FERC to upgrade compressor facilities and expand our existing natural gas transmission system from Alabama to markets as far north as North Carolina. The cost of the project is estimated to be $200 million. We placed the first phase of the project into service in September 2012, which increased capacity by 95 Mdth/d. We plan to place the second phase of the project into service in June 2013, which is expected to increase capacity by an additional 130 Mdth/d.

59-------------------------------------------------------------------------------- Table of Contents Rockaway Delivery Lateral In January 2013, we filed an application with the FERC to construct a three-mile offshore lateral to a distribution system in New York. The capital cost of the project is estimated to be approximately $180 million. We plan to place the project into service during the second half of 2014, with an expected capacity of 647 Mdth/d.

Northeast Supply Link In November 2012, we received approval from the FERC to expand our existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in New York and New Jersey. The cost of the project is estimated to be $390 million and is expected to increase capacity by 250 Mdth/d. We plan to place the project into service in November 2013.

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

In September 2011, we filed an application with the FERC seeking authorization to abandon these four caverns. In February 2013, the FERC issued an order approving the abandonment. We estimate the total abandonment costs, which will be capital in nature, will be approximately $92 million, which is expected to be spent through the end of 2013. As of December 31, 2012, we have incurred approximately $69 million in cumulative abandonment costs. This estimate is subject to change as work progresses and additional information becomes known.

Management considers these costs to be prudent costs incurred in the abandonment of these caverns and expects to recover these costs, net of insurance proceeds, in future rate filings. To the extent available, the abandonment costs will be funded from the ARO Trust. (See Note 13 of Notes to Consolidated Financial Statements.) Outlook for 2013 In addition to the various in-progress expansion projects previously discussed, we have several other proposed projects to meet customer demands. Subject to regulatory approvals, construction of some of these projects could begin as early as 2013. We have planned capital and investment expenditures of $725 million to $825 million in 2013 mainly due to various in-progress expansion projects discussed above, as well as maintenance of existing facilities, primarily due to pipeline integrity costs and U. S. Department of Transportation mandatory requirements.

Filing of rate cases On August 31, 2012, Transco filed a general rate case with the FERC for an overall increase in rates. In September 2012, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general rate filing to be effective March 1, 2013, subject to refund and the outcome of a hearing. We expect that our new rates, although still subject to refund until the rate case is resolved, will contribute to a modest increase in revenue in 2013. The specific rates that reflected a rate decrease were accepted, without suspension, to be effective October 1, 2012 and will not be subject to refund. The impact of these specific new rates that became effective October 1, 2012 is expected to reduce revenues by approximately $2 million for the period from January 1, 2013 until the remaining rates that are currently suspended become effective on March 1, 2013.

During the first quarter of 2012, Northwest Pipeline filed a Stipulation and Settlement Agreement with the FERC for an increase in their rates. Northwest Pipeline received FERC approval during the second quarter of 2012. The new rates, which as filed are 7.4 percent higher than the formerly applicable rates, became effective January 1, 2013.

60-------------------------------------------------------------------------------- Table of Contents Year-Over-Year Operating Results Year ended December 31, 2012 2011 2010 (Millions) Segment revenues $ 1,674 $ 1,678 $ 1,605 Segment profit $ 677 $ 673 $ 637 2012 vs. 2011 Segment revenues decreased $4 million primarily due to $39 million lower system management gas sales (offset in product costs) and $4 million lower sales of base gas from Hester Storage Field. These decreases are substantially offset by a $40 million increase in transportation revenues associated with expansion projects placed in service during 2011 and 2012.

Segment costs and expenses increased $6 million, or 1 percent, primarily due to an $18 million increase in employee-related benefit costs charged to us by Williams, $13 million increased pipeline maintenance costs, an $11 million increase in project feasibility costs, $10 million higher depreciation expense resulting from additional assets placed in service in 2011, and $9 million higher selling, general and administrative costs, including increases in information technology services and rental cost. These increases were partially offset by $39 million lower system management gas costs (offset in segment revenues), $12 million lower operations and maintenance expense associated with the Eminence Storage Field leak, and an $8 million increase in the reversal of project feasibility costs from expense to capital associated with expansion projects.

Segment profit increased primarily due to the previously described changes and a $14 million increase in equity earnings primarily due to the acquisition of an additional interest in Gulfstream in May 2011.

2011 vs. 2010 Segment revenues increased $73 million, or 5 percent, primarily due to a $68 million increase in transportation revenues associated with expansion projects placed in service during 2010 and 2011, and $17 million higher system management gas sales (offset in product costs). These increases are partially offset by $4 million lower sales of base gas from Hester Storage Field.

Segment costs and expenses increased $57 million, or 6 percent, primarily due to $17 million higher system management gas costs (offset in segment revenues), $17 million increased pipeline maintenance costs, $10 million higher depreciation expense resulting from additional assets placed in service in 2010 and 2011, and $10 million increased operations and maintenance expense related to the Eminence Storage Field leak.

Segment profit increased primarily due to the previously described changes and a $20 million increase in equity earnings primarily due to the acquisition of an additional interest in Gulfstream in May 2011.

Midstream Gas & Liquids Overview of 2012 Midstream's ongoing strategy 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.

61-------------------------------------------------------------------------------- Table of Contents Significant events during 2012 include the following: Gulf Olefins production facilities acquisition In November 2012, we purchased Williams' 83.3 percent undivided interest and operatorship of the olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf region. The acquisition is expected to bring more certainty to cash flows that are currently exposed to volatile ethane prices by shifting the commodity price exposure to ethylene. Located south of Baton Rouge, Louisiana, the Geismar facility is a light-end NGL cracker with current feedstock volumes of 39,000 barrels per day (bpd) of ethane and 3,000 bpd of propane and annual production of 1.35 billion pounds of ethylene. With the benefit of a $350-$400 million expansion under way and scheduled for completion by late 2013, the facility's annual ethylene production capacity will grow by 600 million pounds to 1.95 billion pounds.

Along with ethane, propane and ethylene, the Geismar facility also produces propylene, butadiene, and debutanized aromatic concentrate (DAC). Prior periods have been recast for this transaction.

In the fourth quarter of 2012, we also completed the construction of a pipeline which is capable of supplying 12 Mbbls/d of ethane to our Geismar olefins production facility from Discovery's Paradis fractionator.

Caiman Acquisition In April 2012, we completed the Caiman Acquisition for consideration valued at approximately $2.3 billion. The transition of operations is complete.

The acquisition provides us with a significant footprint and growth potential in the natural gas liquids-rich Ohio River Valley area of the Marcellus Shale. The existing physical assets that we acquired include a gathering system, two processing facilities and a fractionator located in northern West Virginia and establish our new Ohio Valley Midstream business. In addition to the acquisition cost, we committed a large portion of our 2012 capital expenditures and continue to commit planned capital expenditures in 2013 and beyond for ongoing expansions to the gathering system, processing facilities, and fractionator, which are currently under construction. NGL pipelines are also planned. The assets are anchored by long-term contracted commitments, including 236,000 dedicated gathering acres from 10 producers in West Virginia, Ohio, and Pennsylvania.

Several projects were completed in the fourth quarter of 2012 increasing our gathering, processing and fractionating capacities. The Fort Beeler plant complex has 320 million cubic feet per day (MMcf/d) of cryogenic processing capacity currently available with another 200 MMcf/d expected during the first quarter of 2013. The Moundsville fractionator is now in service with approximately 13 thousand barrels per day (Mbbls/d) of NGL handling capacity. An NGL pipeline, connecting the Fort Beeler plant to the Moundsville fractionator has also been completed and is in service.

Utica Shale infrastructure project In July 2012, we formed Caiman Energy II, LLC with Caiman Energy, LLC and others to develop large-scale natural gas gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale, primarily in Ohio and northwest Pennsylvania. As a result, through our 47.5 percent ownership, we plan to contribute $380 million through 2014 to fund a portion of Blue Racer Midstream, a joint project formed in December 2012 between Caiman Energy II, LLC and another party.

Susquehanna Supply Hub, northeastern Pennsylvania In February 2012, we completed the Laser Acquisition for $325 million in cash, net of cash acquired in the transaction and subject to certain closing adjustments, and 7,531,381 of our common units valued at $441 million. The gathering system is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in Susquehanna County, Pennsylvania, as well as 10 miles of gathering pipeline in southern New York. The acquisition is supported by existing long-term gathering agreements that provide acreage dedications and volume commitments.

62-------------------------------------------------------------------------------- Table of Contents Our Springville pipeline, a 33-mile, 24-inch diameter natural gas gathering pipeline, connecting a portion of our gathering assets into the Transco pipeline, was placed into service in January 2012, and expansions were completed in the third quarter of 2012 allowing us to deliver approximately 625 MMcf/d into the Transco pipeline. This new take-away capacity allows full use of approximately 1.6 billion cubic feet per day (Bcf/d) of capacity from various compression and dehydration expansion projects to our gathering business in northeastern Pennsylvania's Marcellus Shale which we acquired at the end of 2010.

As production in the Marcellus increases and expansion projects are completed, the Susquehanna Supply Hub is expected to reach a natural gas take away capacity of 3 Bcf/d by 2015, including capacity contributions from the Constitution Pipeline.

Volume impacts in 2012 Due to third-party NGL pipeline capacity restrictions from our Four Corners plants beginning in late September and to unfavorable ethane economics in December, we reduced our recoveries of ethane in our onshore plants, which resulted in 7 percent lower NGL equity sales volumes in the fourth quarter of 2012 compared to the third quarter of 2012.

Our NGL equity sales volumes for the third quarter of 2012 were modestly impacted by maintenance on the Overland Pass Pipeline for approximately 5 days.

As a result of the NGL pipeline maintenance, NGL takeaway capacity from our western plants on the Overland Pass Pipeline was reduced, which forced our western plants to reduce NGL recoveries.

In the Gulf Coast, our Mobile Bay plant was shut down for 10 days due to Hurricane Isaac. The plant and offshore platforms were evacuated during the storm. Afterwards, the plant remained shut down due to flooding issues on a third-party pipeline limiting the NGL takeaway capacity. In addition, production into Devils Tower was shut-in for various time periods due to third-party hurricane related issues. These events related to Hurricane Isaac did not have a material impact to our overall NGL production or NGL equity sales.

Volatile commodity prices Driven primarily by a sharp decline in NGL prices during the second quarter of 2012, followed by increasing natural gas prices in the latter half of 2012, average per-unit NGL margins declined during 2012 and were approximately 23 percent lower in 2012 than in 2011. Because we typically realize lower per-unit margins for ethane versus other NGLs, if we had produced the same mix of ethane and non-ethane NGLs during the fourth quarter of 2012 as we generally have in prior periods, the average per-unit margin in the fourth quarter of 2012 would have been lower. Key factors in the NGL market weakness have been high propane inventories caused by the extremely warm winter and the effect of the propane oversupply on ethane inventories and pricing. Despite an increase in natural gas prices during the latter half of 2012, we have benefited from lower natural gas prices in 2012 than in 2011, driven by abundant natural gas supplies.

NGL margins are defined as NGL revenues less any applicable British thermal unit (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.

63 -------------------------------------------------------------------------------- Table of Contents [[Image Removed: LOGO]] Outlook for 2013 The following factors, among others, could impact our business in 2013.

Commodity price changes • We expect a decline in ethane and propane prices and an increase in natural gas prices such that our full year 2013 NGL margins are expected to be lower than our rolling five-year average and 2012 per-unit NGL margins. NGL price changes have historically tracked somewhat with changes in the price of crude oil, although NGL, crude, and natural gas prices are highly volatile, difficult to predict, and are often not highly correlated. NGL margins are highly dependent upon continued demand within the global economy. However, NGL products are currently the preferred feedstock for ethylene and propylene production, which has been shifting away from the more expensive crude-based feedstocks.

• While per-unit ethylene margins are volatile and highly dependent upon continued demand within the global economy, we believe that our average per-unit ethylene margin will improve over 2012 levels, benefiting from higher ethylene prices and lower ethane and propane feedstock prices.

Bolstered by abundant long-term domestic natural gas supplies, we expect to benefit from these dynamics in the broader global petrochemical markets because of our NGL-based olefins production.

Gathering, processing, and NGL sales volumes • The growth of natural gas supplies supporting our gathering and processing volumes are impacted by producer drilling activities, which are influenced by natural gas prices.

• We anticipate significant growth in our natural gas gathering volumes as our infrastructure grows to support drilling activities in the Marcellus Shale region.

• We anticipate equity NGL volumes in 2013 to be lower than 2012 due in part to a change in a customer's contract in the onshore business from percent-of-liquids to fee-based processing, with a portion of the fee 64 -------------------------------------------------------------------------------- Table of Contents representing a share of the associated NGL margins. We also expect lower equity NGL volumes due to periods when we expect it will not be economical to recover ethane. Our expectations of sustained low natural gas prices are expected to discourage producer drilling activities in the western onshore area and unfavorably impact the supply of natural gas available to gather and process in 2013.

• In our businesses in the Gulf Coast, we expect lower production handling and crude transportation volumes compared to 2012, as production flowing through our Devils Tower facility declines.

• We anticipate higher general and administrative, operating, and depreciation expense supporting our growing operations in the Marcellus Shale area.

Olefin production volumes • We expect lower ethylene volumes in 2013 as compared to 2012 primarily due to major maintenance planned for 2013. With the completion of our Geismar expansion in the latter part of 2013, as discussed below, we expect growth in production volumes in the fourth quarter of 2013.

Expansion Projects We expect to invest total capital of $2.8 billion to $ 3.1 billion in 2013. We plan to continue pursuing expansion and growth opportunities in the Marcellus Shale region, Gulf of Mexico, and Piceance basin.

Our ongoing major expansion projects include the following: • Expansion of our Susquehanna Supply Hub in northeastern Pennsylvania, as previously discussed.

• Expansions currently under construction to our natural gas gathering system, processing facilities and fractionator in our Ohio Valley Midstream business of the Marcellus Shale including a third turbo-expander at our Fort Beeler facility which is expected to add 200 MMcf/d of processing capacity in the first quarter of 2013. By the end of 2013, we expect our first turbo-expander at our Oak Grove facility to add 200 MMcf/d of processing capacity and additional fractionation capacity at our Moundsville fractionators bringing the NGL handling capacity to approximately 43 Mbbls/d.

• Expansions to our gathering system infrastructure through capital to be invested within our Laurel Mountain equity investment, also in the Marcellus Shale region.

• We will design, construct, and install our Gulfstar FPS™, a spar-based floating production system that utilizes a standard design approach with a capacity of 60 Mbbls/d of oil, up to 200 MMcf/d of natural gas, and the capability to provide seawater injection services. We expect Gulfstar FPS™ to be capable of serving as a central host facility for other deepwater prospects in the area. Construction is underway and the project is expected to be in service in 2014. In January 2013, we agreed to sell a 49 percent ownership interest in our Gulfstar FPS™ project to a third party.

The transaction is expected to close in second-quarter 2013, at which time we expect the third party will contribute $225 million to fund its proportionate share of the project costs, following with monthly capital contributions to fund its share of ongoing construction.

• In conjunction with a basin-wide agreement for all gathering and processing services provided by us to WPX in the Piceance basin, we plan to construct a 350 MMcf/d cryogenic natural gas processing plant. The Parachute TXP I plant is expected to be in service in 2014.

• An expansion of our Geismar olefins production facility is under way which is expected to increase the facility's ethylene production capacity by 600 million pounds per year to a new annual capacity of 1.95 billion pounds. The additional capacity will be wholly owned by us and is expected to increase our share of the Geismar production facility to over 88 percent. We expect to complete the expansion in the latter part of 2013.

• Our equity investee which we operate, Discovery, plans to construct, own, and operate a new 215-mile, 20-inch deepwater lateral pipeline from a third-party floating production facility located in the Keathley Canyon production area in the central deepwater Gulf of Mexico. Discovery has signed long-term agreements with anchor customers for natural gas gathering and processing services for production from the 65 -------------------------------------------------------------------------------- Table of Contents Keathley Canyon and Green Canyon areas. The Keathley Canyon Connector™ lateral will originate from a third-party floating production facility in the southeast portion of the Keathley Canyon area and will connect to Discovery's existing 30-inch offshore natural gas transmission system. 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.

Pre-construction activities have begun; the pipeline is expected to be laid in 2013 and in service in mid-2014.

• Through our equity investment in OPPL, we are participating in the construction of a pipeline connection and capacity expansions, expected to be complete in early 2013, to increase the pipeline's capacity to the maximum of 255 Mbbls/d, to accommodate new volumes coming from the Bakken Shale in the Williston basin.

Year-Over-Year Operating Results Years ended December 31, 2012 2011 2010 (Millions) Segment revenues $ 5,646 $ 6,036 $ 4,854 Segment profit $ 1,135 $ 1,362 $ 1,029 2012 vs. 2011 The decrease in segment revenues includes: • A $366 million decrease in revenues from our equity NGLs primarily reflecting a decrease of $354 million associated with an overall 26 percent decrease in average NGL per-unit sales prices. Average ethane and non-ethane per-unit prices decreased by 49 percent and 15 percent, respectively.

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

• Marketing revenues are $93 million lower primarily due to a significant decrease in NGL and olefin prices, partially offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities.

• A $163 million increase in fee revenues primarily due to higher volumes in the Marcellus Shale, including new volumes on our recently acquired gathering and processing assets in our Ohio Valley Midstream and Susquehanna Supply Hub businesses; higher volumes in the western deepwater Gulf of Mexico, including higher volumes on our Perdido Norte natural gas and oil pipelines; and higher volumes in the Piceance basin.

Segment costs and expenses decreased $208 million, or 4 percent, including: • A $183 million decrease in olefin feedstock costs including $130 million lower ethylene feedstock costs driven by 38 percent lower average per-unit feedstock costs and $28 million lower propylene feedstock costs primarily due to 20 percent lower per-unit feedstock costs.

• A $137 million decrease in costs associated with our equity NGLs primarily due to a 31 percent decrease in average natural gas prices.

• A $46 million decrease in marketing purchases primarily due to significantly lower average NGL prices, partially offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities. The changes in natural gas marketing purchases are more than offset by similar changes in natural gas marketing revenues.

66 -------------------------------------------------------------------------------- Table of Contents • A $101 million increase in operating costs including higher depreciation and amortization of assets and intangibles, along with maintenance costs associated with assets acquired in 2012, partially offset by lower costs in our Four Corners area related to the consolidation of certain operations.

• A $71 million increase in general and administrative expenses including $23 million of Caiman and Laser acquisition and transition-related costs, as well as increases in employee-related and information technology expenses driven by general growth within our business operations.

The decrease in Midstream's segment profit reflects the previously described changes in segment revenues and segment costs and expenses. A more detailed analysis of the segment profit of certain Midstream operations is presented as follows.

The decrease in Midstream's segment profit includes: • A $229 million decrease in NGL margins driven primarily by commodity price changes including lower NGL prices, partially offset by lower natural gas prices.

• A $101 million increase in operating costs as previously discussed.

• A $71 million increase in general and administrative expenses as previously discussed.

• A $47 million decrease in margins related to the marketing of NGLs primarily due to the impact of a significant and rapid decline in NGL prices, primarily during the second quarter of 2012, while product was in transit and a $7 million unfavorable change in write-downs of inventories to lower of cost or market. These unfavorable variances compare to periods of increasing prices during 2011.

• A $45 million decrease in equity earnings primarily due to $19 million lower Laurel Mountain equity earnings driven by lower gathering rates indexed to natural gas prices, higher operating costs, including depreciation, and the impairment of two minor NGL processing plants, partially offset by higher gathered volumes; $12 million lower Aux Sable equity earnings primarily due to lower NGL margins; and $12 million lower Discovery equity earnings primarily due to lower NGL margins and volumes.

• A $163 million increase in fee revenues as previously discussed.

• A $106 million increase in olefin product margins including $88 million higher ethylene production margins primarily due to 38 percent lower average per-unit feedstock prices, partially offset by 10 percent lower average per-unit sales prices. DAC production margins were also $13 million higher, primarily resulting from higher average per-unit margins primarily driven by lower average per-unit feedstock prices.

2011 vs. 2010 The increase in segment revenues includes: • A $657 million increase in marketing revenues primarily due to higher average NGL, crude and propylene prices. These changes are substantially offset by similar changes in marketing purchases.

• A $244 million increase in revenues from our equity NGLs reflecting an increase of $272 million associated with a 25 percent increase in average NGL per-unit sales prices, partially offset by a decrease of $28 million associated with a 3 percent decrease in equity NGL volumes.

• A $167 million increase in olefin sales revenues including $126 million higher ethylene production sales revenues due to 28 percent higher average per-unit sales prices on 6 percent higher volumes primarily resulting from the absence of a four-week plant maintenance outage in 2010; and $30 million higher butadiene and DAC production sales revenues primarily due to higher average per-unit sales prices.

67 -------------------------------------------------------------------------------- Table of Contents • A $107 million increase in fee revenues primarily due to higher gathering and processing fee revenues. We have fees from new volumes on our gathering assets in the Marcellus Shale in northeastern Pennsylvania, which we acquired at the end of 2010 and on our Perdido Norte gas and oil pipelines in the western deepwater Gulf of Mexico, which went into service in late 2010. In addition, higher fees in the Piceance basin are primarily a result of an agreement executed in November 2010. These increases are partially offset by a decline in gathering and transportation fees in the eastern deepwater Gulf of Mexico primarily due to natural field declines.

Segment costs and expenses increased $862 million, or 22 percent, including: • A $641 million increase in marketing purchases primarily due to higher average NGL, crude and propylene prices. These changes are offset by similar changes in marketing revenues.

• A $117 million increase in olefin feedstock costs including $93 million higher ethylene feedstock costs resulting from higher average per-unit feedstock costs and 6 percent higher volumes and $11 million higher butadiene and DAC feedstock costs primarily due to higher per-unit feedstock costs.

• A $104 million increase in operating costs reflecting $63 million, or 17 percent, higher maintenance expenses, including maintenance expenses for our gathering assets in northeastern Pennsylvania acquired at the end of 2010, more maintenance performed on our assets in the western Onshore businesses, and higher property insurance expense. In addition, depreciation expense is $33 million higher primarily due to our new Perdido Norte pipelines and our Echo Springs expansion, both of which went into service in late 2010, along with increased depreciation of our Lybrook plant which was idled in January 2012 when the gas was redirected to our Ignacio plant.

• The absence of $30 million in gains recognized in 2010 associated with sale of certain assets in Colorado's Piceance basin and involuntary conversion gains due to insurance recoveries in excess of the carrying value of certain Gulf Coast assets which were damaged by Hurricane Ike in 2008 and our Ignacio plant which was damaged by a fire in 2007.

• A $42 million decrease in costs associated with our equity NGLs reflecting a decrease of $21 million associated with a 5 percent decrease in average natural gas prices and a $21 million decrease reflecting lower equity NGL volumes.

The increase in Midstream's segment profit reflects the previously described changes in segment revenues and segment costs and expenses. A more detailed analysis of the segment profit of certain Midstream operations is presented as follows.

The increase in Midstream's segment profit includes: • A $286 million increase in NGL margins reflecting: • A $278 million increase in the Onshore businesses' NGL margins reflecting a $249 million increase from favorable commodity price changes due primarily to a 25 percent increase in average NGL prices.

NGL equity volumes sold are 5 percent higher reflecting new capacity at our Echo Springs plant.

• An $8 million increase in the Gulf Coast businesses' NGL margins related to a $39 million increase from favorable commodity price changes, partially offset by 39 percent lower NGL equity volumes sold primarily due to a change in a major contract from "keep-whole" to "percent-of-liquids" processing.

• A $107 million increase in fee revenues as previously discussed.

• A $50 million increase in olefin product margins including $33 million higher ethylene production margins due to 27 percent higher per-unit margins on 6 percent higher volumes and $19 million higher butadiene and DAC production margins primarily resulting from higher average per-unit margins.

68 -------------------------------------------------------------------------------- Table of Contents • A $16 million increase in margins related to the marketing of NGLs, crude and propylene.

• A $13 million increase in equity earnings primarily due to higher OPPL equity earnings as a result of our purchase of an increased ownership interest in September 2010.

• A $104 million increase in operating costs as previously discussed.

• A $30 million unfavorable change primarily related to gains recognized in 2010 as previously discussed.

69 -------------------------------------------------------------------------------- Table of Contents Management's Discussion and Analysis of Financial Condition and Liquidity Overview In 2012, we continued to focus upon growth through disciplined investments.

Examples of this growth included: • Expansion of Gas Pipeline's interstate natural gas pipeline system to meet the demand of growth markets.

• Laser, Caiman, and Geismar Acquisitions, as well as continued investment in Midstream's gathering and processing capacity and infrastructure in the Marcellus Shale area, western United States, and deepwater Gulf of Mexico.

These investments were primarily funded through cash flow from operations and debt and equity offerings.

Outlook We seek to manage our businesses with a focus on applying conservative financial policy and maintaining investment-grade credit metrics. Our plan for 2013 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, as follows: • Firm demand and capacity reservation transportation revenues under long-term contracts at Gas Pipeline; • Fee-based revenues from certain gathering and processing services at Midstream.

We also note that the addition of the Geismar olefins-production facility is expected to result in a favorable shift in our commodity exposure from ethane to ethylene.

We believe we have, or have access to, the financial resources and liquidity necessary to meet our requirements for working capital, capital and investment expenditures, unitholder distributions and debt service payments while maintaining a sufficient level of liquidity. In particular, we note the following for 2013: • We increased our per-unit quarterly distribution with respect to the fourth quarter of 2012 from $0.8075 to $0.8275. We expect to increase quarterly limited partner cash distributions by approximately 9 percent annually.

• We expect to fund capital and investment expenditures, debt service payments, distributions to unitholders and working capital requirements primarily through cash flow from operations, cash and cash equivalents on hand, cash proceeds from common unit and/or long-term debt issuances and utilization of our revolver as needed. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $1.925 billion and $2.325 billion in 2013. 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 2013. Our internal and external sources of liquidity include: • Cash and cash equivalents on hand; • Cash generated from operations, including cash distributions from our equity method investees; • Cash proceeds from offerings of our common units and/or long-term debt; • Use of our revolver as needed and available.

70 -------------------------------------------------------------------------------- Table of Contents 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/or general partner.

Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include: • Lower than expected levels of cash flow from operations; • Limited availability of capital due to a change in our financial condition, interest rates, market or industry conditions; • Sustained reductions in energy commodity margins from expected 2013 levels; • Physical damages to facilities, especially damage to offshore facilities by named windstorms.

As of December 31, 2012, we had a working capital deficit (current liabilities in excess of current assets) of $499 million. However, we note the following about our available liquidity.

Available Liquidity December 31, 2012 (Millions) Cash and cash equivalents $ 20 Capacity available under our $2.4 billion five-year revolver (expires June 3, 2016) (1) 2,025 $ 2,045 (1) The full amount of the revolver is available to us, to the extent not otherwise utilized by Transco and Northwest Pipeline, and may, under certain conditions, be increased by up to an additional $400 million. Transco and Northwest Pipeline are each able to borrow up to $400 million under the revolver to the extent not otherwise utilized by the other co-borrowers. As of February 25, 2013, $975 million of loans are outstanding under this revolver. At December 31, 2012, we are in compliance with the financial covenants associated with this revolver. (See Note 11 of Notes to Consolidated Financial Statements.) Shelf Registration In February 2012, we filed a shelf registration statement as a well-known seasoned issuer to facilitate unlimited issuances of registered debt and limited partnership unit securities.

Distributions from Equity Method Investees Our equity method investees' organizational documents require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses. Our more significant equity method investees include: Aux Sable, Discovery, Gulfstream, Laurel Mountain, and OPPL.

71-------------------------------------------------------------------------------- Table of Contents Debt Offerings In August 2012, we completed a public offering of $750 million of our 3.35 percent senior unsecured notes due in 2022. We used the $745 million net proceeds to repay outstanding borrowings under our revolver and for general partnership purposes.

In July 2012, Transco received net proceeds of $395 million from the issuance of $400 million of 4.45 percent senior unsecured notes due in 2042. These proceeds were used to repay Transco's $325 million 8.875 percent notes and for general corporate purposes, including capital expenditures.

Equity Offerings In August 2012, we completed an equity issuance of 8,500,000 common units representing limited partner interests in us at a price of $51.43 per unit.

Subsequently, we sold an additional 1,275,000 common units for $51.43 per unit to the underwriters upon the underwriters' exercise of their option to purchase additional common units. The net proceeds of $488 million were used to repay outstanding borrowings under our revolver and for general partnership purposes.

In April 2012, we completed an equity issuance of 10,000,000 common units representing limited partner interests in us at a price of $54.56 per unit.

Subsequently, we sold an additional 973,368 common units for $54.56 per unit to the underwriters upon the underwriters' exercise of their option to purchase additional common units. The net proceeds of $581 million were used for general partnership purposes, including the funding of a portion of the cash purchase price of the Caiman Acquisition.

In April 2012, we also issued 16,360,133 common units to Williams for $1 billion, which was used to fund a portion of the cash purchase price of the Caiman Acquisition.

In January 2012, we completed an equity issuance of 7,000,000 common units representing limited partner interests in us at a price of $62.81 per unit. In February 2012, we sold an additional 1,050,000 common units for $62.81 per unit to the underwriters upon the underwriters' exercise of their option to purchase additional common units. The net proceeds of $490 million were used to fund capital expenditures and for general partnership purposes.

Additionally, we issued equity to the sellers for acquisitions as discussed below.

Acquisitions In November 2012, we completed the Geismar Acquisition in exchange for aggregate consideration valued at $2.364 billion, including $25 million in cash and 42,778,812 of our common units.

In April 2012, we completed the Caiman Acquisition in exchange for aggregate consideration of $1.72 billion in cash, net of purchase price adjustments, and 11,779,296 of our common units.

In February 2012, we completed the Laser Acquisition in exchange for $325 million in cash, net of cash acquired in the transaction, and 7,531,381 of our common units.

Credit Ratings The table below presents our current credit ratings and outlook on our senior unsecured long-term debt.

Senior Unsecured Rating Agency Date of Last Change Outlook Debt Rating Standard & Poor's March 5, 2012 Stable BBB Moody's Investors Service February 27, 2012 Stable Baa2 Fitch Ratings February 9, 2012 Positive BBB- 72 -------------------------------------------------------------------------------- Table of Contents With respect to Standard and Poor's, a rating of "BBB" or above indicates an investment grade rating. A rating below "BBB" indicates that the security has significant speculative characteristics. A "BB" rating indicates that Standard and Poor's believes the issuer has the capacity to meet its financial commitment on the obligation, but adverse business conditions could lead to insufficient ability to meet financial commitments. Standard and Poor's may modify its ratings with a "+" or a "-" sign to show the obligor's relative standing within a major rating category.

With respect to Moody's, a rating of "Baa" or above indicates an investment grade rating. A rating below "Baa" is considered to have speculative elements.

The "1", "2", and "3" modifiers show the relative standing within a major category. A "1" indicates that an obligation ranks in the higher end of the broad rating category, "2" indicates a mid-range ranking, and "3" indicates a ranking at the lower end of the category.

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

Credit rating agencies perform independent analyses when assigning credit ratings. No assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their current criteria for investment grade ratios. A downgrade of our credit rating might increase our future cost of borrowing and would require us to post additional collateral with third parties, negatively impacting our available liquidity. As of December 31, 2012, we estimate that a downgrade to a rating below investment grade could require us to post up to $429 million in additional collateral with third parties.

Capital Expenditures Each of our businesses is capital-intensive, requiring investment to upgrade or enhance existing operations and comply with safety and environmental regulations. The capital requirements of these businesses consist primarily of: • Maintenance capital expenditures, which are generally not discretionary, including (1) capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives, (2) expenditures which are mandatory and/or essential to comply with laws and regulations and maintain the reliability of our operations, and (3) certain well connection expenditures.

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

The following table provides summary information related to our expected capital expenditures for 2013: Maintenance Expansion Segment Low Midpoint High Low Midpoint High (Millions) Gas Pipeline $ 225 $ 250 $ 275 $ 500 $ 525 $ 550 Midstream 90 100 110 2,735 2,875 3,015 Total $ 315 $ 350 $ 385 $ 3,235 $ 3,400 $ 3,565 See Results of Operations - Segments, Gas Pipeline and Midstream for discussions describing the general nature of these expenditures.

73-------------------------------------------------------------------------------- Table of Contents Cash Distributions to Unitholders We have paid quarterly distributions to unitholders and our general partner after every quarter since our initial public offering on August 23, 2005. We have increased the fourth quarter 2012 distribution to $ 0.8275 per unit, from the third quarter 2012 distribution of $0.8075, which resulted in a fourth-quarter 2012 cash distribution of approximately $442 million that was paid on February 8, 2013, to the general and limited partners of record at the close of business on February 1, 2013.

Williams has agreed to temporarily waive its incentive distribution rights related to the common units issued to Williams and the seller of Caiman Eastern Midstream, LLC, in connection with our acquisition of that entity, through 2013.

In connection with the Geismar Acquisition, Williams also agreed to waive $16 million per quarter of incentive distribution rights until the later of December 31, 2013 or 30 days after the Geismar plant expansion is operational.

The incentive distribution rights waived relative to distributions paid in 2012 were $24 million.

Sources (Uses) of Cash Years Ended December 31, 2012 2011 2010 (Millions) Net cash provided (used) by: Operating activities $ 2,018 $ 2,290 $ 1,922 Financing activities 2,412 (918 ) 3,418 Investing activities (4,573 ) (1,396 ) (5,306 ) Increase (decrease) in cash and cash equivalents $ (143 ) $ (24 ) $ 34 Operating activities Net cash provided by operating activities decreased $272 million in 2012 as compared to 2011 primarily due to lower operating income.

Net cash provided by operating activities increased $368 million in 2011 as compared to 2010 primarily due to higher operating income.

Financing activities Significant transactions include: 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 revolver 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; 74 -------------------------------------------------------------------------------- Table of Contents • $1.115 billion of revolver borrowings paid; • $325 million paid to retire Transco's 8.875 percent notes upon their maturity on July 15, 2012.

2011 • $1.12 billion related to quarterly cash distributions paid to limited partner unitholders and our general partner; • $500 million received from our public offering of senior unsecured notes in November 2011 primarily used to repay borrowings on our revolver mentioned below; • $375 million received from Transco's issuance of senior unsecured notes in August 2011; • $300 million paid to retire Transco's senior unsecured notes that matured in August 2011; • $300 million received in revolver borrowings from our $1.75 billion unsecured credit facility used to acquire a 24.5 percent interest in Gulfstream from Williams in May 2011. This obligation was transferred to our new $2 billion unsecured credit facility at its inception in June 2011; • $150 million paid to retire senior unsecured notes that matured in June 2011; • $123 million distributed to Williams related to the excess purchase price over the contributed basis of Gulfstream in May 2011.

2010 • $3.5 billion of net proceeds from the issuance of senior unsecured notes; • $660 million related to quarterly cash distributions paid to limited partner unitholders and our general partner; • $600 million received from our public offering of senior notes in November 2010 primarily used to fund a portion of the cash consideration paid for the Piceance Acquisition (See Note 1 of Notes to Consolidated Financial Statements.); • $437 million received from our September and October 2010 equity offering primarily used to reduce revolver borrowings; • $430 million received in revolver borrowings from our $1.75 billion unsecured credit facility primarily used to fund our increased ownership in OPPL, a transaction that closed in September 2010; • $369 million received from our December 2010 equity offering used to reduce revolver borrowings and to fund a portion of our acquisition of certain midstream assets in Pennsylvania's Marcellus Shale in December 2010; • $250 million received from revolver borrowings on our $1.75 billion unsecured credit facility in February 2010 to repay a term loan outstanding under our credit agreement which expired at the closing of certain businesses we acquired from Williams; • $244 million distributed to Williams related to the excess purchase price over the contributed basis of the gathering and processing assets acquired in the Piceance Acquisition; 75 -------------------------------------------------------------------------------- Table of Contents • $200 million received in revolver borrowings from our $1.75 billion unsecured credit facility primarily used for general partnership purposes and to fund a portion of the cash consideration paid for the Piceance Acquisition; • $152 million in distributions to Williams primarily related to the Contributed Entities prior to the closing of the Dropdown. (See Note 1 of Notes to Consolidated Financial Statements.) Investing activities Significant transactions include: 2012 • $2.1 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 the Laser Acquisition in March 2012; • $471 million contributed to our equity method investments.

2011 • $1 billion in capital expenditures; • $174 million related to our acquisition of a 24.5 percent interest in Gulfstream from Williams in May 2011 (See Note 1 of Notes to Consolidated Financial Statements.); • $137 million contribution to our Laurel Mountain equity investment.

2010 • $3.4 billion related to the cash consideration paid for certain businesses we acquired from Williams; • $844 million in capital expenditures; • $458 million related to the Piceance Acquisition; • $424 million cash payment for our September 2010 acquisition of an increased interest in OPPL; • $150 million paid for the purchase of a business in December 2010, consisting primarily of midstream assets in Pennsylvania's Marcellus Shale.

Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments We have various other guarantees and commitments which are disclosed in Notes 9, 11, 14, and 15 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.

76 -------------------------------------------------------------------------------- Table of Contents Contractual Obligations The table below summarizes the maturity dates of our contractual obligations at December 31, 2012: 2014 - 2016 - 2013 2015 2017 Thereafter Total (Millions) Long-term debt, including current portion: Principal $ - $ 750 $ 1,535 $ 6,168 $ 8,453 Interest 426 825 710 3,323 5,284 Operating leases (1) 40 66 53 136 295 Purchase obligations (2) 1,569 196 177 495 2,437 Other long-term obligations 1 1 - 1 3 Total $ 2,036 $ 1,838 $ 2,475 $ 10,123 $ 16,472 (1) Includes a right-of-way agreement with the Jicarilla Apache Nation, which is considered an operating lease. We are required to make a fixed annual payment of $7.5 million and an additional annual payment, which varies depending on per-unit NGL margins and the volume of gas gathered by our gathering facilities subject to the right-of-way agreement. The table above for years 2014 and thereafter does not include such variable amounts related to this agreement as the variable amount is not yet determinable. The variable portion to be paid in 2013 based on 2012 gathering volumes is $7.3 million and is included in the table for year 2013.

(2) Includes approximately $1.2 billion in open property, plant and equipment purchase orders. Larger projects include Gulfstar and the Geismar plant expansion. Also includes an estimated $579 million long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2012 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. 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 Results of Operations - Segments).

Effects of Inflation Our operations have historically not been materially affected by inflation.

Approximately 56 percent of our gross property, plant, and equipment is at Gas Pipeline. Gas Pipeline is 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 Midstream, 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 use of hedging instruments and the fee-based nature of certain of our services.

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 15 of Notes to Consolidated Financial Statements). We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S.

Environmental Protection Agency (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 77-------------------------------------------------------------------------------- Table of Contents others. Current estimates of the most likely costs of such activities are approximately $17 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, 2012. We will seek recovery of approximately $10 million of these accrued costs through future natural gas transmission rates. The remainder of these costs will be funded from operations.

During 2012, we paid approximately $4 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $5 million in 2013 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, 2012, 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 non-attainment 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 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 non-attainment 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.

Additionally, in August 2010, the EPA promulgated National Emission Standards for Hazardous Air Pollutants (NESHAP) regulations that will impact our operations. The emission control additions required to comply with the NESHAP regulations are estimated to include capital costs in the range of $11 million to $13 million through 2013, the compliance date.

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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