Regency Energy Partners Reports Increases in Fourth-Quarter and Full-Year 2012 Adjusted EBITDA

Regency Energy Partners LP (NYSE: RGP), (“Regency” or the “Partnership”), announced today its financial results for the fourth-quarter and full-year ended December 31, 2012.

For full-year 2012, adjusted EBITDA increased by 14 percent to $480 million compared to $422 million in 2011. For fourth-quarter 2012, adjusted EBITDA increased to $116 million compared to $115 million for fourth-quarter 2011. These increases in adjusted EBITDA were primarily due to volume growth in the gathering and processing segment, partially offset by higher operations and maintenance expenses. The full-year increase was also partly due to a full-year contribution from the Lone Star Joint Venture in 2012, compared to a partial-year contribution in 2011.

For the year-ended December 31, 2012, Regency generated $310 million in cash available for distribution, compared to $285 million for full-year 2011, primarily due to the same items set forth above. For fourth-quarter 2012, Regency generated $68 million in cash available for distribution, compared to $82 million in the fourth-quarter of 2011. This decrease was primarily due to lower proceeds from asset sales in the fourth-quarter of 2012 compared to the prior period.

Net income decreased to $48 million for the full-year ended December 31, 2012, from $74 million for the full-year ended December 31, 2011. These decreases were primarily due to non-cash valuation adjustments recorded in each respective period. For fourth-quarter 2012, Regency reported a net loss of $9 million compared to a net income of $14 million for fourth-quarter 2011.

“In 2012, robust drilling activity in south and west Texas and in north Louisiana contributed to a 20 percent increase in gathering and processing volumes, and we also saw an upswing in revenue generating horsepower in our contract compression business,” said Mike Bradley, president and chief executive officer of Regency. “In addition, we continued construction on major organic growth projects in several of our liquids-rich operating regions.”

“Looking ahead, we have a significant amount of growth projects coming online, and we expect these projects to generate strong returns as they ramp up throughout 2013 and 2014,” said Bradley.

REVIEW OF SEGMENT PERFORMANCE

Adjusted total segment margin increased 10 percent to $463 million for the full-year 2012, compared to $421 million for full-year 2011.

Gathering and Processing – We provide “wellhead-to-market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs from the raw natural gas and selling or delivering the pipeline-quality natural gas and NGLs to various markets and pipeline systems. This segment also includes our 33.33% membership interest in Ranch JV, which processes natural gas delivered from the NGLs-rich Bone Spring and Avalon shale formations in west Texas.

Adjusted segment margin for the Gathering and Processing segment, which excludes non-cash gains and losses from commodity derivatives, was $274 million for full-year 2012, compared to $233 million for full-year 2011. The increase was primarily due to volume growth in south and west Texas, and north Louisiana.

Total throughput volumes for the Gathering and Processing segment increased to 1.4 million MMbtu per day of natural gas for full-year 2012, compared to 1.2 million MMbtu per day of natural gas for full-year 2011. Processed NGLs increased to 38,000 barrels per day for the full-year 2012, compared to 32,000 barrels per day for full-year 2011.

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.

The Haynesville Joint Venture consists solely of the Regency Intrastate Gas System and is operated by Regency. Income from unconsolidated affiliates for the Haynesville Joint Venture was $29 million full-year 2012, compared to $49 million for full-year 2011. Total throughput volumes for the Haynesville Joint Venture averaged 0.9 million MMbtu per day of natural gas for full-year 2012, compared to 1.3 million MMbtu per day for full-year 2011. These decreases are primarily due to a non-cash asset impairment charge related to surplus equipment and the expiration of certain contracts.

The MEP Joint Venture consists solely of the Midcontinent Express Pipeline and is operated by Kinder Morgan Energy Partners, L.P. Income from unconsolidated affiliates for the MEP Joint Venture was $42 million for full-year 2012 and $43 million for full-year 2011. Total throughput volumes for the MEP Joint Venture averaged 1.4 million MMbtu per day of natural gas for full-year 2012 and 1.4 million MMbtu per day for full-year 2011.

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.

The Lone Star Joint Venture, which was acquired in May 2011, owns and operates NGL storage, fractionation and transportation assets and is operated by Energy Transfer Partners, L.P. For the year-ended December 31, 2012, income from unconsolidated affiliates for the Lone Star Joint Venture was $44 million, compared to $28 million for the year-ended December 31, 2011. For the year-ended December 31, 2012, total throughput volumes for the West Texas Pipeline averaged 134,000 barrels per day, compared to 130,000 barrels per day for the period May 2, 2011 to December 31, 2011. NGL Fractionation throughput volumes averaged 17,000 barrels per day for the year-ended December 31, 2012, compared to 16,000 the period May 2, 2011 to December 31, 2011.

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.

Segment margin for the Contract Services segment, including both revenues from external customers as well as intersegment revenues, was $189 million for full-year 2012, compared to $185 million for full-year 2011. The increase in segment margin is primarily due to the increase in revenue generating horsepower, inclusive of intersegment revenue generating horsepower. As of December 31, 2012, the Contract Compression segment’s revenue generating horsepower, including intersegment revenue generating horsepower, increased to 919,000, compared to 846,000 as of December 31, 2011. The increase in revenue generating horsepower is primarily attributable to additional horsepower placed into service in south Texas for the Gathering and Processing segment to provide compression services to external customers.

Corporate – The Corporate segment comprises our corporate offices. Segment margin in the Corporate segment was $20 million for full-year 2012 compared to $17 million for full-year 2011.

ORGANIC GROWTH

For the twelve months ended December 31, 2012, Regency incurred $767 million of growth capital expenditures: $318 million for the NGL Services segment, $298 million for the Gathering and Processing segment, and $151 million for the Contract Services segment.

For the full-year ended December 31, 2012, Regency incurred $34 million of maintenance capital expenditures.

In 2013, Regency expects to invest approximately $400 million in growth capital expenditures, of which $185 million is related to the Gathering and Processing segment; $120 million is related to the NGL Services segment and $95 million is related to the Contract Services segment.

In addition, Regency expects to invest $35 million in maintenance capital expenditures in 2013, including its proportionate share related to joint ventures.

CASH DISTRIBUTIONS

On January 28, 2013, Regency announced a cash distribution of $0.46 per outstanding common unit for the fourth-quarter ended December 31, 2012. This distribution is equivalent to $1.84 per outstanding common unit on an annual basis and was paid on February 14, 2013, to unitholders of record at the close of business on February 7, 2013.

Based on the terms of the partnership agreement, the Series A Preferred Units were paid a quarterly distribution of $0.445 per unit for the fourth-quarter ended December 31, 2012, on the same schedule as set forth above.

In the fourth-quarter of 2012, Regency generated $68 million in cash available for distribution, representing 0.83 times the amount required to cover its announced distribution to unitholders. For full-year 2012, Regency generated $310 million in cash available for distribution, representing 0.95 times the amount required to cover its announced distribution to unitholders.

Regency makes distribution determinations based on its cash available for distribution and the perceived sustainability of distribution levels over an extended period. In addition to considering the cash available for distribution generated during the quarter, Regency takes into account cash reserves established with respect to prior distributions, seasonality of results, timing of organic growth projects and its internal forecasts of adjusted EBITDA and cash available for distribution over an extended period. Distributions are determined by the Board of Directors and are driven by the long-term sustainability of the business.

TELECONFERENCE

Regency Energy Partners will hold a quarterly conference call to discuss its fourth-quarter 2012 results Thursday, February 21, 2013, at 10 a.m. Central Time (11 a.m. Eastern Time).

The dial-in number for the call is 1-866-770-7125 in the United States, or +1-617-213-8066 outside the United States, passcode 50928052. A live webcast of the call may be accessed on the Investor Relations page of Regency’s website at www.regencyenergy.com. The call will be available for replay for seven days by dialing 1-888-286-8010 (from outside the U.S., +1-617-801-6888) passcode 94006638. A replay of the broadcast will also be available on the Partnership’s website for 30 days.

NON-GAAP FINANCIAL INFORMATION

This press release and the accompanying financial schedules include the non-GAAP financial measures of:

  • EBITDA;
  • adjusted EBITDA;
  • cash available for distribution;
  • segment margin;
  • total segment margin;
  • adjusted segment margin; and
  • adjusted total segment margin.

These financial metrics are key measures of the Partnership’s financial performance. The accompanying schedules provide reconciliations of these non-GAAP financial measures to their most directly-comparable financial measures calculated and presented in accordance with accounting principles generally accepted in the United States of America ("GAAP"). Our non-GAAP financial measures should not be considered 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 as a measure of operating performance, liquidity or ability to service debt obligations. Reconciliations of these non-GAAP financial measures to our GAAP financial statements are included in the Appendix.

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;
  • unit-based compensation expenses;
  • 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.

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.

We define cash available for distribution as adjusted EBITDA:

  • minus interest expense, excluding capitalized interest;
  • minus maintenance capital expenditures;
  • minus distributions to Series A Preferred Units,
  • plus cash proceeds from asset sales, if any; and
  • other adjustments.

Cash available for distribution is used as a supplemental liquidity measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to approximate the amount of operating surplus generated by us during a specific period and to assess our ability to make cash distributions to our unitholders and our general partner. Cash available for distribution is not the same measure as operating surplus or available cash, both of which are defined in our partnership agreement.

Neither EBITDA nor adjusted EBITDA should not be considered 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. EBITDA and adjusted EBITDA do not include interest expense, income tax expense or depreciation and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net earnings determined under GAAP, as well as EBITDA and adjusted EBITDA, to evaluate our performance.

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 revenues generated from operations less the cost of natural gas and NGLs purchased and other costs 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 percentages 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 revenues minus direct costs, primarily compressor unit repairs, associated with those revenues. We calculate total segment margin as the sum of segment margin of our segments less intersegment eliminations. 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, as applicable, including intersegment eliminations.

Total segment margin and adjusted total segment margin are included as a supplemental disclosure because they are primary performance measures used by our management as they represent the result of product sales, service fee revenues and product purchases, a key component of our operations. We believe total segment margin and adjusted total segment margin are important measures because they are directly related to our volumes and commodity price changes.

Operation and maintenance expense is a separate measure used by management 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 operation and maintenance expenses. These expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. We do not deduct operation and maintenance expenses from total revenue in calculating total segment margin and adjusted total segment margin because we separately evaluate commodity volume and price changes in these margin amounts.

As an indicator of our operating performance, total segment margin or adjusted total segment margin should not be considered an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Our total segment margin and adjusted total segment margin may not be comparable to a similarly titled measure of another company because other entities may not calculate these measures in the same manner.

FORWARD-LOOKING INFORMATION AND OTHER DISCLAIMERS

This release includes “forward-looking” statements. Forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may” or similar expressions help identify forward-looking statements. Although we believe our forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, we cannot give any assurance that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. Additional risks include: volatility in the price of oil, natural gas, and natural gas liquids, declines in the credit markets and the availability of credit for the Partnership as well as for producers connected to the Partnership’s system and its customers, the level of creditworthiness of, and performance by the Partnership’s counterparties and customers, the Partnership's ability to access capital to fund organic growth projects and acquisitions, and the Partnership’s ability to obtain debt and equity financing on satisfactory terms, the Partnership's use of derivative financial instruments to hedge commodity and interest rate risks, the amount of collateral required to be posted from time-to-time in the Partnership's transactions, changes in commodity prices, interest rates, and demand for the Partnership's services, changes in laws and regulations impacting the midstream sector of the natural gas industry, weather and other natural phenomena, industry changes including the impact of consolidations and changes in competition, the Partnership's ability to obtain required approvals for construction or modernization of the Partnership's facilities and the timing of production from such facilities, and the effect of accounting pronouncements issued periodically by accounting standard setting boards. Therefore, actual results and outcomes may differ materially from those expressed in such forward-looking statements.

These and other risks and uncertainties are discussed in more detail in filings made by the Partnership with the Securities and Exchange Commission, which are available to the public. The Partnership undertakes no obligation to update publicly or to revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Regency Energy Partners LP (NYSE: RGP) is a growth-oriented, master limited partnership engaged in the gathering and processing, contract compression, contract treating and transportation of natural gas and the transportation, fractionation and storage of natural gas liquids. Regency's general partner is owned by Energy Transfer Equity, L.P. (NYSE: ETE). For more information, please visit Regency’s website at www.regencyenergy.com.

Condensed Consolidated Balance Sheets

Regency Energy Partners LP
Condensed Consolidated Balance Sheets
($ in thousands)
December 31, 2012December 31, 2011
Assets
Current assets $ 236,788 $ 187,124
Property, plant and equipment, net 2,162,596 1,885,528
Investment in unconsolidated affiliates 2,213,989 1,924,705
Long-term derivative assets 762 474
Other assets, net 41,613 39,353
Intangible assets, net 711,610 740,883
Goodwill 789,789 789,789
Total Assets $ 6,157,147 $ 5,567,856
Liabilities and Partners' Capital and Noncontrolling Interest
Current liabilities $ 286,881 $ 233,306

Long-term derivative liabilities

25,239 39,112
Other long-term liabilities 5,426 6,071
Long-term debt 2,157,111 1,687,147
Series A Preferred Units 72,733 71,144
Partners' capital 3,532,716 3,498,207
Noncontrolling interest 77,041 32,869
Total Partners' Capital and Noncontrolling Interest 3,609,757 3,531,076
Total Liabilities and Partners' Capital and Noncontrolling Interest $ 6,157,147 $ 5,567,856

Consolidated Statements of Operations

Regency Energy Partners LP
Consolidated Statements of Operations
($ in thousands)
Year Ended
December 31, 2012December 31, 2011December 31, 2010
REVENUES $ 1,339,168 $ 1,433,898 $ 1,221,663
OPERATING COSTS AND EXPENSES
Cost of sales 870,970 1,012,826 862,105
Operations and maintenance 165,900 147,643 125,650
General and administrative 62,945 67,408 80,951
Loss (gain) on asset sales, net 2,845 (2,372 ) 516
Depreciation and amortization 201,511 168,684 117,751
Total operating costs and expenses 1,304,171 1,394,189 1,186,973
OPERATING INCOME34,99739,70934,690
Income from unconsolidated affiliates 114,337 119,540 69,365
Interest expense, net (122,372 ) (102,474 ) (82,792 )
Loss on debt refinancing, net (7,820 ) - (17,528 )
Other income and deductions, net 29,510 17,309 (12,126 )
INCOME (LOSS) BEFORE INCOME TAXES48,65274,084(8,391)
Income tax expense (benefit) 828 465 956
INCOME (LOSS) FROM CONTINUING OPERATIONS47,82473,619(9,347)
DISCONTINUED OPERATIONS - - (1,571 )
NET INCOME (LOSS)$47,824$73,619$(10,918)
Net income attributable to noncontrolling interest (2,313 ) (1,177 ) (562 )
NET INCOME (LOSS) ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP$45,511$72,442$(11,480)
Limited partners' interest in net income (loss) $ 27,236 $ 57,450 $ (22,850 )
Weighted average number of common units outstanding 167,492,735 145,490,869 115,590,707
Basic income (loss) per common unit $ 0.16 $ 0.39 $ (0.20 )
Diluted income (loss) per common unit $ 0.13 $ 0.32 $ (0.20 )

Consolidated Statements of Operations

Regency Energy Partners LP
Consolidated Statements of Operations
($ in thousands)
Three Month Ended
December 31, 2012December 31, 2011December 31, 2010
REVENUES $ 355,411 $ 369,881 $ 322,745
OPERATING COSTS AND EXPENSES
Cost of sales 237,621 257,564 221,121
Operations and maintenance 44,652 42,025 33,100
General and administrative 15,839 13,510 18,563
Loss (gain) on asset sales, net 1,303 (2,422 ) 3
Depreciation and amortization 58,992 45,989 33,217
Total operating costs and expenses 358,407 356,666 306,004
OPERATING INCOME(2,996)13,21516,741
Income from unconsolidated affiliates 27,139 32,619 23,618
Interest expense, net (36,314 ) (28,926 ) (19,791 )
Loss on debt refinancing, net - - (15,748 )
Other income and deductions, net 3,961 (2,796 ) (12,232 )
(LOSS) INCOME BEFORE INCOME TAXES(8,210)14,112(7,412)
Income tax expense (benefit) 739 484 (143 )
(LOSS) INCOME FROM CONTINUING OPERATIONS(8,949)13,628(7,269)
DISCONTINUED OPERATIONS - - (1,654 )
NET (LOSS) INCOME$(8,949)$13,628$(8,923)
Net income attributable to noncontrolling interest (886 ) (104 ) (69 )
NET (LOSS) INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP$(9,835)$13,524$(8,992)
Limited partners' interest in net (loss) income $ (13,856 ) $ 9,417 $ (11,815 )
Weighted average number of common units outstanding 170,841,959 155,675,662 137,234,829
Basic (loss) income per common unit $ (0.08 ) $ 0.06 $ (0.09 )
Diluted (loss) income per common unit $ (0.08 ) $ 0.06 $ (0.09 )

Segment Financial and Operating Data

Three Months Ended December 31,Year Ended December 31,
201220112010201220112010
($ in thousands)
Gathering and Processing Segment
Financial data:
Segment margin $ 68,830 $ 64,355 $ 52,915 $ 278,742 $ 233,146 $ 196,008
Adjusted segment margin 70,698 63,804 59,731 273,915 233,201 226,191
Operating data:
Throughput (MMbtu/d) 1,504,073 1,349,592 1,029,597 1,432,972 1,187,149 996,800
NGL gross production (Bbls/d) 40,427 36,382 29,327 38,182 31,902 26,155
Three Months Ended December 31,Year Ended December 31,
201220112010201220112010
($ in thousands)
Contract Services Segment
Financial data:
Segment margin $ 49,812 $ 47,067 $ 49,580 $ 189,435 $ 185,029 $ 165,663
Operating data:
Revenue generating horsepower, including intercompany revenue generating horsepower 918,861 846,172 844,800 918,861 846,172 844,800
Three Month Ended December 31,Year Ended December 31,
201220112010201220112010
($ in thousands)
Corporate Segment
Financial data:
Segment margin $ 5,100 $ 4,200 $ 4,200 $ 19,500 $ 16,800 $ 16,733

The following provides key performance measures for 100% of the Haynesville Joint Venture, the MEP Joint Venture, the Lone Star Joint Venture and the Ranch Joint Venture

Three Months Ended December 31,Year Ended December 31,
201220112010201220112010
($ in thousands)
Haynesville Joint Venture
Financial data:
Segment margin $ 43,009 $ 43,901 $ 47,450 $ 173,244 $ 183,309 $ 174,347
Operating data:
Throughput (MMbtu/d) 747,569 1,054,392 1,543,570 854,388 1,321,266 1,277,881
Three Months Ended December 31,

Year Ended December 31,

201220112010201220112010
($ in thousands)
MEP Joint Venture
Financial data:
Segment margin $ 61,259 $ 62,815 $ 57,799 $ 245,753 $ 246,758 $ 212,345
Operating data:
Throughput (MMbtu/d) 1,397,314 1,380,010 1,541,533 1,409,079 1,360,658 1,408,778
Three Months EndedYear Ended

From May 2, 2011
(Initial Acquisition
date) through

December 31, 2012December 31, 2011December 31, 2012

December 31,
2011

($ in thousands)
Lone Star Joint Venture
Financial data:
Segment margin $ 72,832 $ 66,931 $ 277,140 $ 178,718
Operating data:
West Texas Pipeline Throughput (Bbls/d) 136,754 128,681 134,274 130,246
NGL Fractionation Throughput (Bbls/d) 17,715 18,464 17,152 15,676
Three Months EndedYear Ended
December 31, 2012December 31, 2012
($ in thousands)
Ranch Joint Venture
Financial data:
Segment margin $ 374 $ 524
Operating data:
Throughput (MMbtu/d) 5,205 3,274

*

* For the period from June to December 2012, as Ranch Joint Venture's Refrigeration Processing Plant started its operation in June 2012.

The following provides a reconciliation of segment margin to net income for 100% of the Haynesville Joint Venture, the MEP Joint Venture the Lone Star Joint Venture and the Ranch Joint Venture

Three Months Ended December 31,Year Ended December 31,
201220112010201220112010
Haynesville Joint Venture($ in thousands)
Net income $ 14,483 $ 24,483 $ 32,097 $ 69,847 $ 109,186 $ 106,737
Add:
Operation and maintenance 5,778 5,747 2,296 22,084 20,803 17,518
General and administrative 5,149 4,124 4,436 19,699 17,161 17,759
Loss on asset sales, net 425 - (1 ) 1,710 - 105
Depreciation and amortization 9,114 9,084 8,474 36,468 34,930 31,797
Interest expense, net 427 463 171 1,824 1,245 526
Impairment of property, plant and equipment 7,637 - - 21,751 - -
Other income and deductions, net (4 ) - (23 ) (139 ) (16 ) (95 )
Total Segment Margin$43,009$43,901$47,450$173,244$183,309$174,347
Three Months Ended December 31,Year Ended December 31,
201220112010201220112010
MEP Joint Venture($ in thousands)
Net income $ 20,660 $ 22,655 $ 18,109 $ 83,266 $ 85,339 $ 60,173
Add:
Operating expenses 10,405 9,913 9,514 41,613 40,365 38,255
Depreciation and amortization 17,357 17,362 17,401 69,432 69,538 66,929
Interest expense, net 12,837 12,892 12,779 51,442 51,515 48,751
Other income and deductions, net - (7 ) (4 ) - 1 (1,763 )
Total Segment Margin$61,259$62,815$57,799$245,753$246,758$212,345

Three Months EndedYear Ended

From May 2, 2011
(Initial Acquisition
date) through

December 31, 2012December 31, 2011December 31, 2012

December 31,
2011

Lone Star Joint Venture($ in thousands)
Net income $ 37,460 $ 35,049 $ 147,172 $ 93,959
Add:
Operation and maintenance 16,861 16,194 59,126 39,254
General and administrative 4,453 3,719 19,011 13,326
Depreciation and amortization 13,787 12,205 51,524 32,248
Tax expense 261 630 1,740 833
Other income and deductions, net 10 (866 ) (1,433 ) (902 )
Total Segment Margin$72,832$66,931$277,140$178,718
Three Months EndedYear Ended
December 31, 2012December 31, 2012
($ in thousands)
Ranch Joint Venture
Net loss $ (623 ) $ (1,554 )
Add:
Operation and maintenance 389 702
General and administrative 16 16
Gain on asset sales (27 ) (27 )
Depreciation and amortization 615 1,383
Tax expense 4 4
Total Segment Margin$374$524

Reconciliation of Non-GAAP Measures to GAAP Measures

Three Months Ended December 31,
201220112010
($ in thousands)
Net income (loss) $ (8,949 ) $ 13,628 $ (8,923 )
Add (deduct):
Interest expense, net 36,314 28,926 19,791
Depreciation and amortization 58,992 45,989 33,217
Income tax expense (benefit) 739 484 (143 )
EBITDA (1)$87,096$89,027$43,942
Add (deduct):
Non-cash (gain) loss from commodity and embedded derivatives (2,177 ) 2,230 18,922
Unit-based compensation expenses 1,315 923 1,386
Loss (gain) on asset sales, net 1,303 (2,422 ) 78
Income from unconsolidated affiliates (27,139 ) (32,619 ) (23,618 )

Partnership's ownership interest in unconsolidated affiliates' adjusted EBITDA

56,911 57,572 44,469
Loss on debt refinancing, net - - 15,748
Other (income) expense, net (886 ) 189 831
Adjusted EBITDA$116,423$114,900$101,758
(1) Earnings before interest, taxes, depreciation and amortization.
(2) 100% of Haynesville Joint Venture's Adjusted EBITDA is calculated as follows:
Net income $ 14,483 $ 24,483 $ 32,097
Add (deduct):
Depreciation and amortization 9,114 9,084 8,474
Interest expense 427 463 171
Loss on sale of asset, net 425 - (1 )
Impairment of property, plant and equipment 7,637 - -
Other expense, net - - 16
Adjusted EBITDA $32,086$34,030$40,757
Average ownership interest 49.99 % 49.99 % 49.99 %
Partnership's interest in Adjusted EBITDA $16,040$17,012$20,374
(3) 100% of MEP Joint Venture's Adjusted EBITDA is calculated as follows:
Net income $ 20,660 $ 22,655 $ 18,109
Add:
Depreciation and amortization 17,357 17,362 17,401
Interest expense, net 12,837 12,892 12,779
Adjusted EBITDA $50,854$52,909$48,289
Average ownership interest 50.00 % 50.00 % 49.90 %
Partnership's interest in Adjusted EBITDA $25,427$26,455$24,095
We acquired a 49.9% interest in MEP Joint Venture in May 2010.
(4) 100% of Lone Star Joint Venture's Adjusted EBITDA is calculated as follows:
Net income $ 37,460 $ 35,049 N/A
Add (deduct):
Depreciation and amortization 13,787 12,205 N/A
Other income, net 270 (237 ) N/A
Adjusted EBITDA $51,517$47,017N/A
Average ownership interest 30.00 % 30.00 % N/A
Partnership's interest in Adjusted EBITDA $15,455$14,105N/A
We acquired a 30% interest in Lone Star Joint Venture in May 2011.
(5) 100% of Ranch Joint Venture's Adjusted EBITDA is calculated as follows:
Net loss $ (623 ) N/A N/A
Add (deduct):
Depreciation and amortization 615 N/A N/A
Other income, net (23 ) N/A N/A
Adjusted EBITDA $(31)N/AN/A
Average ownership interest 33.33 % N/A N/A
Partnership's interest in Adjusted EBITDA $(11)N/AN/A
We acquired a 33.33% interest in Ranch Joint Venture in December 2011.

Reconciliation of Non-GAAP Measures to GAAP Measures

Year Ended December 31,
201220112010
($ in thousands)
Net income (loss) $ 47,824 $ 73,619 $ (10,918 )
Add (deduct):
Interest expense, net 122,372 102,474 82,971
Depreciation and amortization 201,511 168,684 122,725
Income tax expense (benefit) 828 465 956
EBITDA (1)$372,535$345,242$195,734
Add (deduct):
Non-cash (gain) loss from commodity and embedded derivatives (18,827 ) (17,919 ) 42,613
Unit-based compensation expenses 4,785 3,610 13,727
(Gain) loss on asset sales, net 2,845 (2,372 ) 591
Income from unconsolidated affiliates (114,337 ) (119,540 ) (69,365 )
Partnership's ownership interest in unconsolidated affiliates' adjusted EBITDA (2)(3)(4)(5) 227,493 213,572 122,696
Loss on debt refinancing, net 7,820 - 17,528
Other (income) expense, net (2,348 ) (224 ) 3,432
Adjusted EBITDA$479,966$422,369$326,956
(1) Earnings before interest, taxes, depreciation and amortization.
(2) 100% of Haynesville Joint Venture's Adjusted EBITDA is calculated as follows:
Net income $ 69,847 $ 109,186 $ 106,737
Add (deduct):
Depreciation and amortization 36,468 34,930 31,797
Interest expense 1,824 1,245 526
Loss on sale of asset, net 1,710 - 105
Impairment of property, plant and equipment 21,751 - -
Other expense, net - 16 (228 )
Adjusted EBITDA $131,600$145,377$138,937
Average ownership interest 49.99 % 49.99 % 48.23 %
Partnership's interest in Adjusted EBITDA $65,787$72,672$67,014
(3) 100% of MEP Joint Venture's Adjusted EBITDA is calculated as follows:
Net income $ 83,266 $ 85,339 $ 42,528
Add:
Depreciation and amortization 69,432 69,538 40,103
Interest expense, net 51,442 51,515 28,959
Adjusted EBITDA $204,140$206,392$111,590
Average ownership interest 50.00 % 49.93 % 49.90 %
Partnership's interest in Adjusted EBITDA $102,070$103,059$55,682
We acquired a 49.9% interest in MEP Joint Venture in May 2010.
(4) 100% of Lone Star Joint Venture's Adjusted EBITDA is calculated as follows:
Net income $ 147,172 $ 93,959 N/A
Add (deduct):
Depreciation and amortization 51,524 32,248 N/A
Other income, net 306 (68 ) N/A
Adjusted EBITDA $199,002$126,139N/A
Average ownership interest 30.00 % 30.00 % N/A
Partnership's interest in Adjusted EBITDA $59,701$37,841N/A
We acquired a 30% interest in Lone Star Joint Venture in May 2011.
(5) 100% of Ranch Joint Venture's Adjusted EBITDA is calculated as follows:
Net loss $ (1,554 ) $ - N/A
Add (deduct):
Depreciation and amortization 1,383 - N/A
Other income, net (23 ) - N/A
Adjusted EBITDA $(194)$-N/A
Average ownership interest 33.33 % 33.33 % N/A
Partnership's interest in Adjusted EBITDA $(65)$-N/A
We acquired a 33.33% interest in Ranch Joint Venture in December 2011.

Non-GAAP Adjusted Total Segment Margin to GAAP Net Income

Three Months Ended December 31,
201220112010
($ in thousands)
Net (loss) income $ (8,949 ) $ 13,628 $ (8,923 )
Add (Deduct):
Operation and maintenance 44,652 42,025 33,100
General and administrative 15,839 13,510 18,563
Loss (gain) on asset sales, net 1,303 (2,422 ) 3
Depreciation and amortization 58,992 45,989 33,217
Income from unconsolidated affiliates (27,139 ) (32,619 ) (23,618 )
Interest expense, net 36,314 28,926 19,791
Loss on debt refinancing, net - - 15,748
Other income and deductions, net (3,961 ) 2,796 12,232
Income tax expense (benefit) 739 484 (143 )
Discontinued operations - - 1,654
Total Segment Margin117,790112,317101,624
Non-cash loss (gain) from derivatives 1,868 (551 ) 6,816
Adjusted Total Segment Margin$119,658$111,766$108,440
Gathering & Processing Segment Margin$68,830$64,355$52,915
Non-cash loss (gain) from derivatives 1,868 (551 ) 6,816
Adjusted Gathering and Processing Segment Margin70,69863,80459,731
Natural Gas Transportation Segment Margin3015971,141
Contract Services Segment Margin49,81247,06749,580
Corporate Segment Margin5,1004,2004,200
Inter-segment Elimination(6,253)(3,902)(6,212)
Adjusted Total Segment Margin$119,658$111,766$108,440

Non-GAAP Adjusted Total Segment Margin to GAAP Net Income

Year Ended December 31,
201220112010
($ in thousands)
Net income (loss) $ 47,824 $ 73,619 $ (10,918 )
Add (Deduct):
Operation and maintenance 165,900 147,643 125,650
General and administrative 62,945 67,408 80,951
Loss (gain) on asset sales, net 2,845 (2,372 ) 516
Depreciation and amortization 201,511 168,684 117,751
Income from unconsolidated affiliates (114,337 ) (119,540 ) (69,365 )
Interest expense, net 122,372 102,474 82,792
Loss on debt refinancing, net 7,820 - 17,528
Other income and deductions, net (29,510 ) (17,309 ) 12,126
Income tax expense 828 465 956
Discontinued operations - - 1,571
Total Segment Margin468,198421,072359,558
Non-cash (gain) loss from derivatives (4,827 ) 55 30,183
Adjusted Total Segment Margin$463,371$421,127$389,741
Gathering & Processing Segment Margin$278,742$233,146$196,008
Non-cash loss (gain) from derivatives (4,827 ) 55 30,183
Adjusted Gathering & Processing Segment Margin273,915233,201226,191
Natural Gas Transportation Segment Margin1,7372,8014,359
Contract Services Segment Margin189,435185,029165,663
Corporate Segment Margin19,50016,80016,733
Inter-segment Elimination(21,216)(16,704)(23,205)
Adjusted Total Segment Margin$463,371$421,127$389,741

Reconciliation of “cash available for distribution” to net cash flows provided by operating activities and to net income

Three Months EndedYear Ended
December 31, 2012December 31, 2012
($ in thousands)($ in thousands)
Net cash flows provided by operating activities $ 71,043 $ 251,968
Add (deduct):
Depreciation and amortization, including debt issuance cost and bond premium (61,528 ) (208,441 )
Income from unconsolidated affiliates 27,139 114,337
Derivative valuation change 1,726 18,850
Loss on asset sales, net (1,303 ) (2,845 )
Unit-based compensation expenses (1,315 ) (4,785 )
Cash flow changes in current assets and liabilities:
Trade accounts receivables, accrued revenues, and related party receivables 4,002 (6,777 )
Other current assets and other current liabilities 798 (4,932 )
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues (21,709 ) 9,966
Distributions received from unconsolidated affiliates (28,808 ) (120,701 )
Other assets and liabilities 1,006 1,184
Net (Loss) Income$(8,949)$47,824
Add:
Interest expense, net 36,314 122,372
Depreciation and amortization 58,992 201,511
Income tax expense 739 828
EBITDA$87,096$372,535
Add (deduct):
Non-cash gain from commodity and embedded derivatives (2,177 ) (18,827 )
Non-cash unit based compensation 1,315 4,785
Loss on asset sales, net 1,303 2,845
Income from unconsolidated affiliates (27,139 ) (114,337 )

Partnership's ownership interest in unconsolidated affiliates' adjusted EBITDA

56,911 227,493
Loss on debt refinancing, net - 7,820
Other expense, net (886 ) (2,348 )
Adjusted EBITDA$116,423$479,966
Add (deduct):
Interest expense, excluding capitalized interest (41,133 ) (151,298 )
Maintenance capital expenditures (8,072 ) (33,697 )
Distribution to Series A Preferred Units (1,946 ) (7,782 )
Proceeds from asset disposal 4,485 27,013
Other adjustments (1,704 ) (4,514 )
Cash available for distribution$68,053$309,688

Contacts:

Investor Relations:
Regency Energy Partners
Lyndsay Hannah, 214-840-5477
Manager, Finance & Investor Relations
ir@regencygas.com
or
Media Relations:
Granado Communications Group
Vicki Granado, 214-599-8785
vicki@granadopr.com
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