• natural gas midstream and intrastate transportation and storage through La Grange Acquisition, L.P., which conducts business under the assumed name of ETC OLP; and

• interstate natural gas transportation services through ET Interstate. ET Interstate is the parent company of Transwestern, ETC FEP, ETC Tiger and CrossCountry.

• NGL transportation, storage and fractionation services primarily through Lone Star.

• Other operations, including natural gas compression services through ETC Compression.

Previously we conducted our retail propane activities through HOLP and Titan. On January 12, 2012, we contributed HOLP and Titan to AmeriGas, as discussed in Note 5 of the consolidated financial statements included in Item 1. Recent Developments
Sunoco Merger
On October 5, 2012, Sam Acquisition Corporation, a Pennsylvania corporation and a wholly-owned subsidiary of ETP, completed its merger with Sunoco, Inc. ("Sunoco"). Under the terms of the merger agreement, Sunoco shareholders received a total of approximately 54,971,724 ETP Common Units and a total of approximately $2.6 billion in cash.
ETP used approximately $2.0 billion of Sunoco's cash on hand to partially fund the cash portion of the Sunoco Merger consideration. The remainder of the cash portion of the merger consideration, approximately $620 million, was funded with borrowings on ETP's Credit Facility.
Sunoco generates cash flow from a portfolio of retail outlets for the sale of gasoline and middle distillates in the east coast, midwest and southeast areas of the United States. Prior to October 5, 2012, Sunoco also owned a 2% general partner interest, 100% of the IDRs, and 32.4% of the outstanding common units of Sunoco Logistics. In addition, in September 2012, Sunoco completed its exit from the refining business as a result of the contribution of its Philadelphia refinery to a joint venture and the related sale of its crude oil and refined product inventory to this joint venture. In connection with this transaction, Sunoco received a 33% non-operating minority interest in this joint venture. Sunoco Logistics is a publicly traded limited partnership that owns and operates a logistics business consisting of a geographically diverse portfolio of complementary pipeline, terminalling and crude oil acquisition and marketing assets. The refined products pipelines business consists of refined products pipelines located in the northeast, midwest and southwest United States, and equity interests in refined products pipelines. The crude oil pipeline business consists of crude oil pipelines located principally in Oklahoma and Texas. The terminal facilities business consists of refined products and crude oil terminal capacity at the Nederland Terminal on the Gulf Coast of Texas and capacity at the Eagle Point terminal on the banks of the Delaware River in New Jersey. The crude oil acquisition and marketing business, principally conducted in Oklahoma and Texas, involves the acquisition and marketing of crude oil and consists of crude oil transport trucks and crude oil truck unloading facilities.

Holdco Transaction
Immediately following the closing of the Sunoco Merger, ETE contributed its interest in Southern Union into ETP Holdco Corporation ("Holdco"), an ETP-controlled entity, in exchange for a 60% equity interest in Holdco. In conjunction with ETE's contribution, ETP contributed its interest in Sunoco to Holdco and will retain a 40% equity interest in Holdco. Prior to the contribution of Sunoco to Holdco, Sunoco contributed $2.0 billion of cash and its interests in Sunoco Logistics to ETP in exchange for 90,706,000 Class F Units representing limited partner interests in ETP ("Class F Units"). The Class F Units are entitled to 35% of the quarterly cash distribution generated by ETP and its subsidiaries other than Holdco, subject to a maximum cash distribution of $3.75 per Class F Unit per year, which is the current level. Pursuant to a stockholders agreement between ETE and ETP, ETP will control Holdco. Consequently, ETP consolidated Holdco (including Sunoco and Southern Union) in its financial statements subsequent to consummation of the Holdco Transaction. Under the terms of the Holdco transaction agreement, ETE will relinquish an aggregate of $210 million of incentive distributions over 12 consecutive quarters following the closing of the Holdco Transaction. The relinquishment will apply to the distribution paid with respect to the third quarter ended September 30, 2012.
Discontinued Operations
In October 2012, we sold ETC Canyon Pipeline, LLC ("Canyon") for approximately $207 million. The results of continuing operations of Canyon have been reclassified to loss from discontinued operations and the prior year amounts have been restated to present Canyon's operations as discontinued operations. Canyon's assets and liabilities have been reclassified and reported as assets and liabilities held for sale as of September 30, 2012. A write down of the carrying amounts of the Canyon assets to their fair values was recorded for approximately $145 million during the three months ended September 30, 2012. General
Our primary objective is to increase the level of our distributable cash flow over time by pursuing a business strategy that is currently focused on growing our natural gas and NGL businesses through, among other things, pursuing certain construction and expansion opportunities relating to our existing infrastructure and acquiring certain strategic operations and businesses or assets. The actual amounts of cash that we will have available for distribution will primarily depend on the amount of cash we generate from our operations.
Prior to the completion of the Sunoco Merger and Holdco Transaction on October 5, 2012, our principal operations included the following segments:
• Intrastate natural gas transportation and storage - Revenue is principally generated from fees charged to customers to reserve firm capacity on or move gas through our pipelines on an interruptible basis. Our interruptible or short-term business is generally impacted by basis differentials between delivery points on our system and the price of natural gas. The basis differentials that have the greatest impact on our interruptible business are primarily between West Texas and East Texas or segments thereof. When narrow or flat spreads exist, our open capacity may be underutilized and go unsold. Conversely, when basis differentials widen, our interruptible volumes and fees generally increase. The fee structure normally consists of a monetary fee and fuel retention. Excess fuel retained after consumption, if any, is typically sold at market prices. In addition to transport fees, we generate revenue from purchasing natural gas and transporting it across our system. The natural gas is then sold to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies. The HPL System purchases natural gas at the wellhead for transport and selling. Other pipelines with access to West Texas supply, such as Oasis and ET Fuel, may also purchase gas at the wellhead and other supply sources for transport across our system to be sold at market on the east side of our system. This activity allows our intrastate transportation and storage segment to capture the current basis differentials between delivery points on our system or to capture basis differentials that were previously locked in through hedges. Firm capacity long-term contracts are typically not subject to price differentials between shipping locations.

We also generate fee-based revenue from our natural gas storage facilities by contracting with third parties for their use of our storage capacity. From time to time, we inject and hold natural gas in our Bammel storage facility to take advantage of contango markets, a term used to describe a pricing environment when the price of natural gas is higher in the future than the current spot price. We use financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. Our earnings from natural gas storage we purchase, store and sell are subject to the current market prices (spot price in relation to forward price) at the time the storage gas is hedged. At the inception of the hedge, we lock in a margin by purchasing gas in the spot market and entering into a financial derivative to lock in the forward sale price. If we designate the related financial derivative as a fair value hedge for accounting purposes, we value the hedged natural gas inventory at current spot market prices whereas the financial derivative is valued using forward natural gas prices. As a result of fair value hedge accounting, we have elected to exclude the spot forward premium from the measurement of effectiveness and changes in the spread between forward natural gas prices and spot market prices result in unrealized gains or losses until the underlying physical

gas is withdrawn and the related financial derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. If the spread narrows between spot and forward prices, we will record unrealized gains or lower unrealized losses. If the spread widens prior to withdrawal of the gas, we will record unrealized losses or lower unrealized gains.
As noted above, any excess retained fuel is sold at market prices. To mitigate commodity price exposure, we will use financial derivatives to hedge prices on a portion of natural gas volumes retained. For certain contracts that qualify for hedge accounting, we designate them as cash flow hedges of the forecasted sale of gas. The change in value, to the extent the contracts are effective, remains in accumulated other comprehensive income until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.
In addition, we use financial derivatives to lock in price differentials between market hubs connected to our assets on a portion of our intrastate transportation system's unreserved capacity. Gains and losses on these financial derivatives are dependent on price differentials at market locations, primarily points in West Texas and East Texas. We account for these derivatives using mark-to-market accounting, and the change in the value of these derivatives is recorded in earnings. During the fourth quarter of 2011, we began using derivatives for trading purposes.
• Interstate natural gas transportation - The majority of our interstate transportation revenues are generated through firm reservation charges that are based on the amount of firm capacity reserved for our firm shippers regardless of usage. Shippers on our interstate pipelines pay reservation charges for the firm capacity reserved for their use under multi-year contracts. In addition to reservation revenues, additional revenue sources include interruptible transportation charges as well as usage rates and overrun rates paid by firm shippers based on their actual capacity usage.

• Midstream - Revenue is principally dependent upon the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipelines as well as the level of natural gas and NGL prices.

In addition to fee-based contracts for gathering, treating and processing, we also have percent of proceeds and keep-whole contracts, which are subject to market pricing. For percent of proceeds contracts, we retain a portion of the natural gas and NGLs processed, or a portion of the proceeds of the sales of those commodities, as a fee. When natural gas and NGL prices increase, the value of the portion we retain as a fee increases. Conversely, when prices of natural gas and NGLs decrease, so does the value of the portion we retain as a fee. For wellhead (keep-whole) contracts, we retain the difference between the price of NGLs and the cost of the gas to process the NGLs. In periods of high NGL prices relative to natural gas, our margins increase. During periods of low NGL prices relative to natural gas, our margins decrease or could become negative; however, we have the ability to bypass our processing plants to avoid negative margins that may occur from processing NGLs in the event it is uneconomical to process this gas. Our processing contracts and wellhead purchases in rich natural gas areas provide that we earn and take title to specified volumes of NGLs, which we also refer to as equity NGLs. Equity NGLs in our midstream segment are derived from performing a service in a percent of proceeds contract or produced under a keep-whole arrangement. In addition to NGL price risk, our processing activity is also subject to price risk from natural gas because, in order to process the gas, in some cases we must purchase it. Therefore, lower gas prices generally result in higher processing margins.
We conduct marketing operations in which we market certain of the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that does not originate from our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other suppliers and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices of natural gas, less the costs of transportation.
• NGL transportation and services - NGL transportation revenue is principally generated from fees charged to customers under dedicated contracts or take-or-pay contracts. Under a dedicated contract, the customer agrees to deliver the total output from particular processing plants that are connected to the NGL pipeline. Take-or-pay contracts have minimum throughput commitments requiring the customer to pay regardless of whether a fixed volume is transported. Transportation fees are market-based, negotiated with customers and competitive with regional regulated pipelines.

NGL storage revenues are derived from base storage fees and throughput fees. Base storage fees are based on the volume of capacity reserved, regardless of the capacity actually used. Throughput fees are charged for providing ancillary services, including receipt and delivery, custody transfer, rail/truck loading and unloading fees. Storage contracts may be for dedicated storage or fungible storage. Dedicated storage enables a customer to reserve an entire storage cavern, which allows the customer to inject and withdraw proprietary and often unique products. Fungible storage allows a customer to store specified quantities of NGL products that are commingled in a storage cavern with other customers' products of the same type and grade. NGL storage contracts may be entered into on a firm or interruptible basis. Under a firm basis contract, the customer obtains the right to store products in the storage caverns throughout the term of the contract; whereas, under an interruptible basis contract, the customer receives only limited assurance regarding the availability of capacity in the storage caverns.

This segment also includes revenues earned from processing and fractionating refinery off-gas. Under these contracts we receive an O-grade stream from cryogenic processing plants located at refineries and fractionate the products into their pure components. We deliver purity products to customers through pipelines and across a truck rack located at the fractionation complex. In addition to revenues for fractionating the O-grade stream, we have percentage-of-proceeds and income sharing contracts, which are subject to market pricing of olefins and NGLs. For percentage-of-proceeds contracts, we retain a portion of the purity NGLs and olefins processed, or a portion of the proceeds from the sales of those commodities, as a fee. When NGLs and olefin prices increase, the value of the portion we retain as a fee increases. Conversely, when NGLs and olefin prices decrease, so does the value of the portion we retain as a fee. Under our income sharing contracts, we pay the producer the equivalent energy value for their liquids, similar to a traditional keep-whole processing agreement, and then share in the residual income created by the difference between NGLs and olefin prices as compared to natural gas prices. As NGLs and olefins prices increase in relation to natural gas prices, the value of the percent we retain as a fee increases. Conversely, when NGLs and olefins prices decrease as compared to natural gas prices, so does the value of the percent we retain as a fee.
• Retail propane and other retail propane related operations - On January 12, 2012 we contributed our propane operations, excluding our cylinder exchange operations, to AmeriGas (See Note 6 of Item 1). Subsequent to this contribution our retail propane and other retail propane segment includes our investment in AmeriGas as well as our cylinder exchange business. We sold our cylinder exchange business in June 2012.

Results of Operations
Consolidated Results
                                Three Months Ended September 30,                         Nine Months Ended September 30,
                                    2012                 2011            Change              2012                  2011            Change
Segment Adjusted EBITDA
Intrastate transportation
and storage                  $       120,593       $       170,183     $ (49,590 )   $         469,810       $      514,547     $  (44,737 )
Interstate transportation            204,488               102,312       102,176               501,888              265,920        235,968
Midstream                            105,252               103,233         2,019               298,915              273,829         25,086
NGL transportation and
services                              36,445                30,504         5,941               110,623               55,200         55,423
Retail propane and other
retail propane related                 3,977                (3,667 )       7,644                94,476              150,924        (56,448 )
All other                             10,910                 1,587         9,323                 8,362                3,167          5,195
Total                                481,665               404,152        77,513             1,484,074            1,263,587        220,487
Depreciation and
amortization                         (94,812 )            (106,419 )      11,607              (282,485 )           (294,356 )       11,871
Interest expense, net of
interest capitalized                (112,141 )            (124,000 )      11,859              (383,271 )           (347,706 )      (35,565 )
Gain on deconsolidation of
Propane Business                           -                     -             -             1,056,709                    -      1,056,709
Losses on non-hedged
interest rate derivatives                (65 )             (68,595 )      68,530                (8,087 )            (64,705 )       56,618
Non-cash unit-based
compensation expense                  (9,198 )             (10,350 )       1,152               (30,190 )            (31,139 )          949
Unrealized gains (losses) on
commodity risk management
activities                            11,456                (6,441 )      17,897               (59,519 )              1,213        (60,732 )
Loss on extinguishment of
debt                                       -                     -             -              (115,023 )                  -       (115,023 )
Adjusted EBITDA attributable
to noncontrolling interest            13,188                13,152            36                44,246               23,737         20,509
Adjusted EBITDA attributable
to discontinued operations            (4,760 )              (5,007 )         247               (15,183 )            (15,028 )         (155 )
Adjusted EBITDA attributable
to unconsolidated affiliates        (105,359 )             (15,229 )     (90,130 )            (301,559 )            (37,623 )     (263,936 )
Equity in earnings of
unconsolidated affiliates              7,920                 6,713         1,207                63,011               13,386         49,625
Other                                  6,245                (6,344 )      12,589                 8,347               (6,559 )       14,906
Income from continuing
operations before income tax
expense                              194,139                81,632       112,507             1,461,070              504,807        956,263
Income tax expense                      (768 )              (4,039 )       3,271               (14,915 )            (20,417 )        5,502
Income from continuing
operations                   $       193,371       $        77,593     $ 115,778     $       1,446,155       $      484,390     $  961,765
Income from discontinued
operations                          (147,162 )              (1,543 )    (145,619 )            (150,062 )             (4,522 )     (145,540 )
Net Income                            46,209                76,050       (29,841 )           1,296,093              479,868        816,225

See the detailed discussion of Segment Adjusted EBITDA below.
Depreciation and Amortization. For the three and nine months ended September 30, 2012 compared to the same periods last year, depreciation and amortization decreased by approximately $20.4 million and $58.0 million, respectively, due to the deconsolidation of the Propane Business in January 2012. These decreases were offset by additional depreciation recorded from assets placed in service. Interest Expense. For the three months ended September 30, 2012, interest expense decreased from the prior year period as a result of a reduction of several series of our higher coupon notes that were repurchased in the tender offers completed in January 2012 and also due to an increase in capitalized interest on our growth projects. For the nine months ended September 30, 2012, the impact of the repurchase was more than offset by incremental interest expense due to the issuance of $1.5 billion of senior notes in May 2011 to fund the LDH acquisition and the issuance of $2.0 billion of senior notes in January 2012 to fund the Citrus acquisition.

Gain on Deconsolidation of Propane Business. A gain on deconsolidation was recognized as a result of the contribution of our Propane Business to AmeriGas in January 2012.
Losses on Non-Hedged Interest Rate Derivatives. The changes between the three and nine months ended September 30, 2012 compared to the same periods last year were primarily due to the recognition of losses in the prior periods resulting from significant forward rate decreases in those periods.
Income Tax Expense. The decrease in income tax expense between the periods was primarily due to changes in taxable income within our subsidiaries that are taxable corporations and deferred tax expense related to the deconsolidation of our Propane Business.
Unrealized (Losses) Gains on Commodity Risk Management Activities. See discussion of the unrealized (losses) gains on commodity risk management activities included in the discussion of segment results below.
Loss on Extinguishment of Debt. A loss on extinguishment of debt was recognized for the nine months ended September 30, 2012 in connection with our tender offers in which we repurchased approximately $750.0 million in aggregate principal amount of Senior Notes in January 2012.
Adjusted EBITDA Attributable to Noncontrolling Interest. These amounts represent the proportionate share of Lone Star's Adjusted EBITDA attributable to Regency's 30% interest in Lone Star. This amount was excluded from the measure of Segment Adjusted EBITDA. Net income includes the results attributable to Lone Star on a consolidated basis.
Adjusted EBITDA Attributable to Unconsolidated affiliates and Equity in Earnings of Unconsolidated Affiliates. Amounts reflected for 2012 primarily include our proportionate share of such amounts related to AmeriGas, Citrus and FEP. The 2011 amounts primarily represented our proportionate share of such amounts for FEP only. Such amounts were included in calculating Segment Adjusted EBITDA and net income.
Other. Includes other income and expense amounts, net and amortization of regulatory assets.

Supplemental Information on Unconsolidated Affiliates The following table presents equity in earnings of unconsolidated affiliates, the proportionate share of unconsolidated affiliates' interest, depreciation, amortization, non-cash compensation expense, loss on debt extinguishment and taxes by unconsolidated affiliate, Adjusted EBITDA attributable to unconsolidated affiliates and distributions received from affiliates for the three and nine months ended September 30, 2012 and 2011:

                                  Three Months Ended
                                    September 30,                          Nine Months Ended September 30,
                                 2012            2011         Change          2012               2011           Change
Equity in earnings of
unconsolidated affiliates:
AmeriGas                     $  (31,970 )     $       -     $ (31,970 )   $  (28,920 )     $            -     $ (28,920 )
Citrus                           25,225               -        25,225         49,039                    -        49,039
FEP                              14,846           5,870         8,976         41,041               11,869        29,172
Other                              (181 )           843        (1,024 )        1,851                1,517           334
Total equity in earnings of
unconsolidated affiliates    $    7,920       $   6,713     $   1,207     $   63,011       $       13,386     $  49,625
Proportionate share of
interest, depreciation,
amortization, non-cash
compensation expense, loss
on debt extinguishment and
taxes:
AmeriGas                     $   35,946       $       -     $  35,946     $  107,993       $            -     $ 107,993
. . .