• Natural Gas Transportation. We own a 49.99% general partner interest in HPC, which owns RIGS, a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets, and a 50% membership interest in MEP, which owns an interstate natural gas pipeline with approximately 500 miles stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipe Line system in Butler, Alabama. This segment also includes Gulf States, which owns a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.

• NGL Services. We own a 30% membership interest in Lone Star, an entity owning a diverse set of midstream energy assets including pipelines, storage, fractionation and processing facilities located in Texas, Mississippi and Louisiana.

• Contract Services. We own and operate a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. We also own and operate a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management.

• Corporate. The Corporate segment comprises our corporate offices.

Gathering and Processing segment. Results of operations from our Gathering and Processing segment are determined primarily by the volumes of natural gas that we gather and process, our current contract portfolio and natural gas and NGL prices. We measure the performance of this segment primarily by the adjusted segment margin it generates. We gather and process natural gas pursuant to a variety of arrangements generally categorized as "fee-based" arrangements, "percent-of-proceeds" arrangements and "keep-whole" arrangements. Under fee-based arrangements, we earn fixed cash fees for the services that we render. Under the latter two types of arrangements, we generally purchase raw natural gas and sell processed natural gas and NGLs. We regard the adjusted segment margin generated by our sales of natural gas and NGLs under percent-of-proceeds and keep-whole arrangements as comparable to the revenues generated by fixed fee arrangements to the extent that they are hedged.
Percent-of-proceeds and keep-whole arrangements involve commodity price risk to us because our adjusted segment margin is based in part on natural gas and NGL prices. We seek to minimize our exposure to fluctuations in commodity prices in several ways, including managing our contract portfolio. In managing our contract portfolio, we classify our gathering and processing contracts according to the nature of commodity risk implicit in the settlement structure of those contracts.
We also minimize our exposure to commodity price fluctuations by executing swap and put option contracts settled against ethane, propane, butane, natural gasoline, natural gas and WTI market prices. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.
In addition, we perform a producer services function whereby we purchase natural gas from producers or gas marketers at receipt points on our systems, including HPC, and transport that gas to delivery points on HPC's system at which we sell the natural gas at market price. We regard the segment margin with respect to those purchases and sales as the economic equivalent of a fee for our transportation service. These contracts are frequently settled in terms of an index price for both purchases and sales. In order to minimize commodity price risk, we attempt to match sales with purchases at the index price. We typically sell natural gas under pricing terms related to a market index. To the extent possible, we match the pricing and timing of our supply portfolio to our sales

portfolio in order to lock in our margin and reduce our overall commodity price exposure. To the extent our natural gas position is not balanced, we will be exposed to the commodity price risk associated with the price of natural gas. Refer to "Item 7A. Quantitative and Qualitative Disclosure about Market Risk" for further details.
Natural Gas Transportation segment. HPC has the capacity to transport up to 2.1 Bcf/d of natural gas. Results of HPC's operations are determined primarily by the volumes of natural gas transported and subscribed on its intrastate pipeline system and the level of fees charged to customers or the margins received from purchases and sales of natural gas. HPC generates revenues and segment margins principally under fee-based transportation contracts. Approximately 89% of the margin HPC earns is related to fixed capacity reservation charges that are not directly dependent on throughput volumes or commodity prices.
MEP pipeline system, operated by KMP, has the capability to transport up to 1.8 Bcf/d of natural gas, and the pipeline capacity is fully subscribed with long-term binding commitments from creditworthy shippers. Results of MEP's operations are determined primarily by the volumes of natural gas transported and subscribed on its interstate pipeline system and the level of fees charged to customers. MEP generates revenues and segment margins principally under fee-based transportation contracts. The margin MEP earns is primarily related to fixed capacity reservation charges that are not directly dependent on throughput volumes or commodity prices. If a sustained decline in commodity prices should result in a decline in volumes, MEP's revenues would not be significantly impacted until expiration of the current contracts.
Gulf States is a small interstate pipeline that uses cost-based rates and terms and conditions of service for shippers wishing to secure capacity for interstate transportation service. Rates charged are largely governed by long-term negotiated rate agreements.
NGL Services segment. Lone Star owns and operates a NGLs storage, fractionation and transportation business. Lone Star's storage assets are primarily located in Mont Belvieu, Texas and its West Texas Pipeline, which passes through the Barnett shale, and its Lone Star West Texas Gateway NGL Pipeline, which passes through the Eagle Ford shale, transport NGLs through intrastate pipeline systems that originate in the Permian and Delaware basins in west Texas, and terminate at the Mont Belvieu storage and fractionation complex. Lone Star also owns and operates fractionation and processing assets located in Louisiana and Texas, including the Lone Star Fractionator I, located at Mont Belvieu, which began service in December 2012. Results of Lone Star's operations are based upon fee-based revenues and commodity pricing which are determined primarily by volumes stored, processed or transported, the level of fees charged to customers and the value of the commodity in the market at the time of sale. The margin Lone Star earns is primarily related to the volume of NGLs stored, processed and transported.
Contract Services segment. We own and operate a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. We also own and operate a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management. Fees charged for compression and treating services are typically fixed and are based on the revenue generating horsepower. HOW WE EVALUATE OUR OPERATIONS. Management uses a variety of financial and operational measurements to analyze our performance. We view these measures as important tools for evaluating the success of our operations and review these measurements on a monthly basis for consistency and trend analysis. These measures include volumes, segment margin, total segment margin, adjusted segment margin, adjusted total segment margin, revenue generating horsepower and operation and maintenance expense on a segment and company-wide basis and EBITDA and adjusted EBITDA on a company-wide basis.
Volumes. We must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our gathering and processing systems. Our ability to maintain existing supplies of natural gas and obtain new supplies is affected by (i) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our gathering and processing systems, (ii) our ability to compete for volumes from successful new wells in other areas and (iii) our ability to obtain natural gas that has been released from other commitments. We routinely monitor producer activity in the areas served by our gathering and processing systems to pursue new supply opportunities.
Segment Margin and Total Segment Margin. We define segment margin, generally, as revenues minus cost of sales. We calculate our Gathering and Processing segment margin and Natural Gas Transportation segment margin as our revenues generated from operations less the cost of natural gas and NGLs purchased and other cost of sales, including third-party transportation and processing fees.
We do not record segment margin for our investments in unconsolidated affiliates (HPC, MEP, Lone Star, and Ranch JV) because we record our ownership percentage of their net income as income from unconsolidated affiliates in accordance with the equity method of accounting.
We calculate our Contract Services segment margin as our revenues generated from our contract compression and treating operations minus direct costs, primarily repairs, associated with those revenues.
We calculate total segment margin as the total of segment margin of our five segments, less intersegment eliminations.

Adjusted Segment Margin and Adjusted Total Segment Margin. We define adjusted segment margin as segment margin adjusted for non-cash (gains) losses from commodity derivatives. Our adjusted total segment margin equals the sum of our operating segments' adjusted segment margins or segment margins, including intersegment eliminations. Adjusted segment margin and adjusted total segment margin are included as supplemental disclosures because they are primary performance measures used by management as they represent the results of product purchases and sales, a key component of our operations.
Revenue Generating Horsepower. Revenue generating horsepower is the primary driver for revenue growth in our contract compression segment, and it is also the primary measure for evaluating our operational efficiency. Revenue generating horsepower is the total horsepower that our Contract Services segment owns and operates for external customers. It does not include horsepower under contract that is not generating revenue or idle horsepower.
Operation and Maintenance Expense. Operation and maintenance expense is a separate measure that we use to evaluate operating performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operating and maintenance expense. These expenses are largely independent of the volumes through our systems but fluctuate depending on the activities performed during a specific period. We do not deduct operation and maintenance expenses from total revenues in calculating segment margin because we use segment margin to separately evaluate commodity volume and price changes.
EBITDA and Adjusted EBITDA. We define EBITDA as net income (loss) plus interest expense, provision for income taxes and depreciation and amortization expense. We define adjusted EBITDA as EBITDA plus or minus the following:
• non-cash loss (gain) from commodity and embedded derivatives;

• non-cash unit-based compensation;

• loss (gain) on asset sales, net;

• loss on debt refinancing;

• other non-cash (income) expense, net;

• net income attributable to noncontrolling interest; and

• our interest in adjusted EBITDA from unconsolidated affiliates less income from unconsolidated affiliates.

These measures are used as supplemental measures by our management and by external users of our financial statements such as investors, banks, research analysts and others, to assess:
• financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

• the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our unitholders and General Partner;

• our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and

• the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Neither EBITDA nor adjusted EBITDA should be considered as an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. EBITDA and adjusted EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate EBITDA or adjusted EBITDA in the same manner. Adjusted EBITDA is the starting point in determining cash available for distribution, which is an important non-GAAP financial measure for a publicly traded partnership.
GENERAL TRENDS AND OUTLOOK. We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove incorrect, our actual results may vary materially from our expected results. Energy Outlook. In its annual energy outlook forecast, the EIA projects that domestic production of crude oil will increase from an average of 5.6 million Bbls/d in 2011 to 7.9 million Bbls/d by 2014, a 40% increase. Although production is projected to gradually decline beyond 2020, overall crude production is expected to remain above 6.1 million Bbls/d through 2040.

Natural gas production from shales is expected to increase to 19 trillion cubic feet by 2040 from 5 trillion cubic feet produced in 2010. Natural gas production from shales amounted to 23% of total natural gas produced in the U.S. in 2010 and is projected to grow to 56% by 2040.
The increase in natural gas consumption is expected to come primarily from the industrial and electric power sectors. Natural gas used in the industrial sector is projected to grow from 6.8 trillion cubic feet in 2011 to 7.8 trillion cubic feet in 2025. The natural gas share of electricity generation rose to 24% in 2010 and is expected to continue increasing to 30% in 2040.
Recently, however, as drilling activities have been more focused on shale plays with a high concentration of NGLs and crude oil, some producers have announced plans to reduce gas drilling activities in order to focus on oil and NGLs prospects.
Effect of Interest Rates and Inflation. Interest rates on existing and future credit facilities and future debt offerings could be significantly higher than current levels, causing our financing costs to increase accordingly. Although increased financing costs could limit our ability to raise funds in the capital markets, we expect to remain competitive with respect to acquisitions and capital projects since our competitors would face similar circumstances. Inflation in the United States has been relatively low in recent years and has not had a material effect on our results of operations. It may in the future, however, increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. Our operating revenues and costs are influenced to a greater extent by price changes in natural gas and NGLs. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along a portion of increased costs to our customers in the form of higher fees.
RECENT DEVELOPMENTS
SUGC. In February 2013, we and Regency Western entered into a contribution agreement with Southern Union, a wholly owned subsidiary of Holdco, to acquire SUGC for $1.5 billion, subject to customary post-closing adjustments. We will finance the acquisition by issuing $900 million of common units to Holdco, comprised of $750 million of our common units and $150 million of recently created Class F common units. The Class F common units are entitled to participate in our distributions for twenty-four months post-transaction closing. The remaining $600 million will be paid in cash. In addition, in conjunction with the acquisition, ETE has agreed to forgo IDR payments on the common units issued with this transaction for the twenty-four months post-transaction closing and to eliminate the $10 million annual management fee paid by us for two years post-transaction close. The transaction is expected to close in the second quarter of 2013.
Upon closing, the acquisition of SUGC will expand our presence is the Permian Basin in west Texas, one of the most prolific, high growth, oil and liquids-rich basins in North America.
Because the SUGC acquisition is a transaction between commonly controlled entities (i.e., the buyer and the sellers are each affiliates of ETE), we will be required to account for the acquisition in a manner similar to the pooling of interest method of accounting. Under this method of accounting, the SUGC acquisition will reflect historical balance sheet data for both SUGC and us instead of reflecting the fair market value of SUCG assets and liabilities. We will recast our financial statements to include the operations of SUGC from March 26, 2012 (the date upon which common control began).
Eagle Ford Expansion. In May 2012, we announced the construction of an expansion to ELG in the Eagle Ford shale ("Edwards Lime Expansion") which will increase the system's capacity by 90 MMcf/d to 160 MMcf/d, and will provide for additional crude transportation and stabilization capacity of 17,000 Bbls/d. We own a 60% interest in ELG and operate the assets. Contracts on the expansion are fee-based, which includes reservation fees. Capital expenditures related to the expansion are expected to total $150 million, of which we will contribute $90 million; this amount is included in our previously announced 2012 growth capital projections. The project is expected to be completed in the first half of 2013. Dubach Processing Facility Expansion. In August 2012, we announced an expansion of the Dubach processing facility in north Louisiana which will increase the processing capacity of the facility to 210 MMcf/d by adding an incremental 70 MMcf/d of cryogenic processing capacity and 20 MMcf/d of JT capacity. The $75 million capital expenditure related to the Dubach expansion also includes the construction of high-pressure gathering lines to transport production to the facility. The project, which is expected to come online in the second quarter of 2013, is backed by fee-based contracts and an acreage dedication.
Lone Star Expansion. In February 2012, Lone Star announced it would construct a second 100,000 Bbls/d NGL fractionation facility at Mont Belvieu, Texas. Lone Star expects this second fractionator to be completed in the fourth quarter of 2013 at an estimated cost of $350 million, of which our proportionate estimated capital contributions is $105 million. In December 2012, Lone Star announced that its West Texas Gateway NGL Pipeline and Lone Star Fractionator I were placed in service, both before originally anticipated. The West Texas Gateway NGL Pipeline, which passes through the Eagle Ford shale, is a 570-mile, 16-inch pipeline that transports NGLs produced in the Permian and Delaware Basins in West Texas to Mont Belvieu, Texas and has an

initial capacity of 209,000 Bbls/d. The Fractionator I, located at Mont Belvieu, Texas, has a capacity of 100,000 barrels per day of NGLs and will handle NGL barrels delivered from several sources, including the West Texas Gateway NGL pipeline.
Ranch JV Expansion. In June 2012, Ranch JV's 25 MMcf/d refrigeration processing plant began operations. In December 2012, Ranch JV's 100 MMcf/d cryogenic processing plant began operations.
RESULTS OF OPERATIONS

Year Ended December 31, 2012 vs. Year Ended December 31, 2011
(Tabular dollar amounts, except per unit data, are in millions)
                                         Year Ended            Year Ended
                                      December 31, 2012     December 31, 2011        Change        Percent
Total revenues                       $           1,339     $           1,434     $        (95 )         7 %
Cost of sales                                      871                 1,013             (142 )        14
Total segment margin (1)                           468                   421               47          11
Operation and maintenance                          166                   147               19          13
General and administrative                          63                    67               (4 )         6
Loss (gain) on asset sales, net                      3                    (2 )              5         250
Depreciation and amortization                      201                   169               32          19
Operating income                                    35                    40               (5 )        13
Income from unconsolidated
affiliates                                         114                   120               (6 )         5
Interest expense, net                             (122 )                (103 )            (19 )        18
Loss on debt refinancing, net                       (8 )                   -               (8 )       100
Other income and deductions, net                    30                    17               13          76
Income before income taxes                          49                    74              (25 )        34
Income tax expense                                   1                     -                1         100
Net income                           $              48     $              74     $        (26 )        35
Net income attributable to the
noncontrolling interest                             (2 )                  (2 )              -           -
Net income attributable to Regency
Energy Partners LP                   $              46     $              72     $        (26 )        36 %
Gathering and processing segment
margin                               $             279     $             233     $         46          20 %
Non-cash gain from commodity
derivatives                                         (5 )                   -               (5 )       100
Adjusted gathering and processing
segment margin                       $             274     $             233     $         41          18
Natural gas transportation segment
margin                                               2                     3               (1 )        33
Contract services segment margin
(2)                                                189                   185                4           2
Corporate segment margin                            19                    17                2          12
Intersegment eliminations (2)                      (21 )                 (17 )             (4 )        24
Adjusted total segment margin        $             463     $             421     $         42          10 %


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(2) Contract Services segment margin includes intersegment revenues of $21 million and $17 million for the years ended December 31, 2012 and 2011, respectively. These intersegment revenues were eliminated upon consolidation.

Net Income Attributable to Regency Energy Partners LP. Net income attributable to Regency Energy Partners LP decreased to $46 million in the year ended December 31, 2012 from $72 million in the year ended December 31, 2011. The major components of this change were as follows:
• $47 million increase in total segment margin mainly due to increased volumes in south and west Texas and north Louisiana in our Gathering and Processing segment. Although the decline in commodity prices lowered revenues and cost of sales, it had little impact to our total segment margin, as we continue to grow our fee-based revenues in south and west Texas as well as north Louisiana;

• $13 million increase in other income and deductions, net, primarily due to a $16 million one-time producer payment received in March 2012 related to an assignment of certain contracts offset by a decrease in the non-cash gain on the embedded derivatives related to the Series A Preferred Units; and

• $4 million decrease in general and administrative expenses primarily due to lower professional fees and office expenses; offset by

• $32 million increase in depreciation and amortization expense primarily related to the completion of various organic growth projects placed in service during 2012, as well as a $12 million increase related to the accelerated depreciation and amortization of certain tangible and intangible assets and an out-of-period adjustment of $7 million recorded in March 2012 (further discussed below);

• $19 million increase in operations and maintenance expense primarily related to increases in employee costs, compressor maintenance costs, and ad valorem taxes due to growth in west and south Texas and north Louisiana;

• $19 million increase in interest expense, net, primarily related to a full . . .