Resources Connection 8-K Regency Energy Partners Reports Full-Year 2007 Financial Results

Regency Energy Partners Reports Full-Year 2007 Financial Results

Adjusted EBITDA in 2007 Increased by 43% vs. 2006

DALLAS, Feb. 29, 2008 – Regency Energy Partners LP (Nasdaq: RGNC), (“Regency” or the “Partnership”), announced today its financial results for the fourth quarter and year ended December 31, 2007.

Revenue for the fourth quarter 2007 increased 46% to $325 million, compared to $222 million for the fourth quarter 2006.  Adjusted total segment margin increased by 37% to $57 million in the fourth quarter 2007, compared to $42 million in the fourth quarter 2006.  The Partnership’s adjusted EBITDA increased 49% to $38 million for the fourth quarter 2007, compared to $25 million for the fourth quarter 2006.

The Partnership reported net income of $2 million in the fourth quarter 2007, compared to net income of $7 million for the fourth quarter 2006.  The fourth-quarter 2007 results included $12 million in non-cash losses from risk management activities.  The fourth-quarter 2006 results included $1 million in non-cash gains from risk management activities.

Revenue for 2007 increased 30% to $1.2 billion, compared to $897 million in 2006.  Adjusted total segment margin increased by 34% to $206 million in 2007, compared to $154 million in 2006.  The Partnership’s adjusted EBITDA increased 43% to $133 million in 2007, compared to $93 million in 2006.

For the year ended December 31, 2007, the Partnership recorded a net loss of $20 million, compared to a net loss of $7 million in 2006.  The 2007 results included the following non-recurring items: a $21-million loss on debt financing; a $12-million expense, consisting primarily of a nonrecurring charge resulting from the vesting of all long-term incentive plan awards upon the change of ownership of Regency’s general partner; and a $15-million non-cash loss from risk management activities.  The 2006 results included the following items: $13 million for fees paid to terminate three, long-term management services contracts in connection with Regency’s initial public offering and the TexStar transaction; an $11-million loss on debt financing; and $3 million of non-cash gains from risk management activities.

“This past year was a monumental year for Regency, best defined by GE Energy Financial Services becoming the majority owner of our general partner,” said James W. Hunt, chairman, president and chief executive officer of Regency.  “In addition, in 2007, Regency announced three acquisitions, totaling almost $897 million, with a fourth deal announced last week for $85 million.  We also completed $78 million in organic growth projects last year.  As a result of these initiatives, we have created the momentum needed to drive our growth in the midstream sector for years to come.”

CASH DISTRIBUTIONS

On January 25, 2008, the Partnership announced a cash distribution of 40 cents per outstanding common and subordinated unit for the fourth quarter ended December 31, 2007.  This represents a 3% increase in the distribution paid for the previous quarter and a 14% increase over the minimum quarterly distribution.  The distribution is equivalent to $1.60 on an annual basis and was paid on February 14, 2008, to unitholders of record at the close of business on February 7, 2008.

In the fourth quarter 2007, Regency generated $27 million in cash available for distribution, representing coverage of 1.6 times the amount required to cover its distribution to common unitholders, and 1.1 times the amount required to cover the distribution to the general partner and all limited partners, including subordinated unitholders.

The Partnership makes distribution determinations based on its cash available for distribution and the perceived sustainability of distribution levels over an extended time 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, and its internal forecasts of adjusted EBITDA and cash available for distribution over the extended time period.

ORGANIC GROWTH PROJECTS

Regency continues to focus on growing the business through organic growth projects.  In 2007, the Partnership identified and implemented $78 million of growth capital projects.  The major projects completed included an upgrade of the Eustace Plant in East Texas, an addition of 31 miles of gathering pipeline in South Texas, and a major efficiency project at the South Texas Tilden Plant.

The 2008 growth budget includes approximately $208 million of currently identified organic growth capital expenditures.  Approximately $118 million of the capital will be spent to add 175 thousand horsepower of compression for CDM Resource Management, a subsidiary of Regency.  The remaining $90 million will be spent primarily in the gathering and processing segment.  The most significant of these projects includes the construction of a 40-mile, 10-inch diameter pipeline, as well as a 20-mile, 10-inch diameter pipeline extension, which will connect the Fashing Processing Plant to the Tilden Processing Plant in South Texas.

ACQUISITIONS

In 2007, Regency announced approximately $897 million in acquisitions, including Pueblo Midstream Gas, FrontStreet Hugoton LLC, and CDM Resource Management.  The Pueblo acquisition closed in April 2007, and both the FrontStreet and CDM acquisitions closed in January 2008.

In February 2008, Regency agreed to acquire Nexus Gas Holdings, LLC (“Nexus”), for $85 million.  The acquisition will expand Regency’s reach in North Louisiana and East Texas.  With this acquisition, Regency will also acquire Nexus’ agreement to purchase 136 miles of pipeline from Southern Natural Gas Company (SNG).  Before Regency can purchase the pipeline from SNG, the U.S. Federal Energy Regulatory Commission must approve the abandonment and certain closing conditions must be met.  If the transaction closes under the currently anticipated conditions, Regency will purchase the pipeline from SNG and make an additional payment to Nexus.  

The Nexus acquisition is subject to approval under the Hart-Scott-Rodino Antitrust Improvements Act and other customary closing conditions.  The closing is expected to occur in late first quarter or early second quarter 2008.  The purchase price of $85 million is subject to customary closing date and post closing adjustments, and will be funded using borrowings under Regency’s revolving credit facility.

REVIEW OF SEGMENT PERFORMANCE

Company adjusted total segment margin for Gathering & Processing and Transportation increased by 34% from $154 million in 2006 to $206 million in 2007.

Gathering & Processing – The Gathering & Processing segment includes the Partnership’s natural gas processing and treating plants, low-pressure gathering pipelines and NGL pipeline activities.  Adjusted segment margin for Gathering & Processing, which excludes non-cash hedging gains and losses, was $148 million for the year ended December 31, 2007, compared to $109 million for the same period in 2006, a 36% increase.

Total throughput volumes of natural gas for the Gathering & Processing segment increased by 41%, from an average of 529 thousand MMbtu per day in 2006 to an average of 745 thousand MMbtu per day in 2007.  Processed NGLs increased by 17%, from an average of 19 thousand barrels per day in 2006 to an average of 22 thousand barrels per day in 2007.

Transportation – The Transportation segment includes the Partnership’s natural gas transportation pipelines and related facilities and activities.  Adjusted segment margin for Transportation was $59 million for 2007, 31% higher than the $45 million in 2006.  Total transportation throughput volumes for the Transportation segment averaged 752 thousand MMbtu per day of natural gas for 2007, 28% higher than the 587 thousand MMbtu per day of natural gas for 2006.

TELECONFERENCE

Regency Energy Partners will hold a quarterly conference call to discuss fourth-quarter and year-end 2007 results today, February 29, 2008, at 10 a.m. Central Time (11 a.m. Eastern Time).

The dial-in number for the call is 1-800-591-6945 in the United States, or +1-617-614-4911 outside the United States, pass code 16035259.  A live webcast of the call can be accessed on the investor information page of Regency Energy Partners’ Web site at www.regencyenergy.com.  The call will be available for replay for 7 days by dialing 1-888-286-8010 (from outside the U.S., +1-617-801-6888), pass code 80152952.  A replay of the broadcast will also be available on the Partnership’s Web site.

NON-GAAP FINANCIAL INFORMATION

This press release and the accompanying financial schedules include the non-generally accepted accounting principles ("non-GAAP") financial measures of adjusted EBITDA, cash available for distribution, adjusted segment margin, and adjusted total segment margin, which 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.

We define Adjusted EBITDA as net income (loss) plus interest expense, net, depreciation and amortization expense, plus income tax expense, non-cash loss (gain) from risk management activities, non-cash commodity put option expirations, loss on debt refinancing, and gain (loss) on the sale of assets.

Adjusted EBITDA is used as a supplemental performance measure by our management and by external users of our financial statements, such as investors, commercial 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 industry,

        without regard to financing methods or capital structure; and

    --  the viability of acquisitions and capital expenditure projects

        and the overall rates of return on alternative investment

        opportunities.

In deriving adjusted EBITDA, we added an adjustment for the accelerated vesting of our long-term incentive program due to the change of control of our general partner and for the prepayment penalty associated with our senior notes.  We made adjustments for termination fees paid in the first and third quarters of 2006 in consideration for two contracts that the Partnership terminated in connection with respectively, its initial public offering and its acquisition of TexStar.  We consider these charges to be non-recurring.   In the prior periods presented, other adjustments impacted adjusted EBITDA.  See the non-GAAP reconciliation for those adjustments.

Our adjusted EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate adjusted EBITDA in the same manner.

We define cash available for distribution as adjusted EBITDA:

·   plus unit-based compensation expense related to our Long-Term Incentive Plan (LTIP),

·   minus interest expense, excluding capitalized interest,

·   minus maintenance capital expenditures,

·   minus income taxes paid, and

·   plus cash proceeds from asset sales, if any.

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 the Partnership 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.

We define adjusted segment margin as segment operating revenues (including transportation and other service fees) less segment cost of purchases of natural gas and natural gas liquids plus non cash gains (losses) from risk management activities and non-cash commodity put option expirations. Adjusted segment margin is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product purchases and sales, a key component of our operations.

We define adjusted total segment margin as total operating revenues less the cost of purchases of natural gas and natural gas liquids plus non cash gain (losses) from risk management activities and non-cash commodity put option expirations.  Our adjusted total segment margin equals the sum of our Gathering and Processing adjusted segment margin and Transportation adjusted segment margin.

Our segment margin measures may not be comparable to similarly titled measures of other companies because other entities may not calculate segment margin amounts in the same manner.

Schedules presenting Regency's consolidated statements of operations, segment margin and operating information by segment, as well as schedules reconciling adjusted EBITDA, cash available for distribution, adjusted segment margin, and adjusted total segment margin to the most directly comparable financial measures calculated and presented in accordance with GAAP are available on Regency's Web site at www.regencyenergy.com and as an attachment to this document.

This press release may contain forward-looking statements regarding Regency Energy Partners, including projections, estimates, forecasts, plans and objectives. These statements are based on management's current projections, estimates, forecasts, plans and objectives and are not guarantees of future performance. In addition, these statements are subject to certain risks, uncertainties and other assumptions that are difficult to predict and may be beyond our control. These risks and uncertainties include changes in laws and regulations impacting the gathering and processing industry, the level of creditworthiness of the Partnership's counterparties, the Partnership's ability to access the debt and equity markets, 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, demand for the Partnership's services, 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 information.

In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than the Partnership has described. 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 (Nasdaq: RGNC) is a growth-oriented, midstream energy partnership engaged in the gathering, contract compression, processing,

marketing and transporting of natural gas and natural gas liquids.  Regency’s general partner is majority-owned by an affiliate of GE Energy Financial Services, a unit of GE (NYSE: GE).  For more information, visit the Regency Energy Partners LP Web site at www.regencyenergy.com.

CONTACT:

Investor Relations:

Shannon Ming

Vice President, Investor Relations & Communications

Regency Energy Partners

214-239-0093

shannon.ming@regencygas.com

Media Relations:

Elizabeth Browne Cornelius

HCK2 Partners

972-716-0500 x26

elizabeth.cornelius@hck2.com

Condensed Consolidated Statements of Operations

	Three Months Ended Dec. 31,						Year to Date Dec. 31,
	2007			2006			2007			2006
($ in thousands)
REVENUE
Gas sales	$	206,321		$	135,338		$	744,681		$	560,620
NGL sales		110,355			62,496			347,737			256,672
Gathering, transportation and other fees (includes related party revenues
of $26 and $1,350 in 2007 and $504 and $2,160 in 2006)		20,443			18,512			78,460			63,071
Unrealized/realized gain/(loss) from risk management activities		(23,468	)		(537	)		(34,266	)		(7,709	)
Other		10,999			6,000			31,442			24,211
Total revenue		324,650			221,809			1,168,054			896,865
OPERATING COSTS AND EXPENSES
Cost of gas and liquids (includes related party expenses of $336 and
$14,165 in 2007 and $(135) and $1,630 in 2006)		279,501			179,338			976,145			740,446
Operation and maintenance		11,065			11,102			45,474			39,496
General and administrative		6,581			5,276			39,543			22,826
Loss (gain) on sale of assets		(40	)		-			1,522			-
Management services termination fee		-			-			-			12,542
Transaction expenses		420			320			420			2,041
Depreciation and amortization		14,264			11,348			51,739			39,654
Total operating costs and expenses		311,791			207,384			1,114,843			857,005
OPERATING INCOME		12,859			14,425			53,211			39,860
OTHER INCOME AND DEDUCTIONS
Interest expense, net		(10,276	)		(9,863	)		(52,016	)		(37,182	)
Loss on debt refinancing		-			1,686			(21,200	)		(10,761	)
Other income and deductions, net		323			339			1,308			839
Total other income and deductions		(9,953	)		(7,838	)		(71,908	)		(47,104	)
INCOME (LOSS) BEFORE INCOME TAXES		2,906			6,587			(18,697	)		(7,244	)
Income tax expense		866			-			931			-
NET INCOME (LOSS)		2,040			6,587			(19,628	)		(7,244	)
Less:
Net income from January 1-31, 2006		-			-			-			1,564
NET INCOME (LOSS) FOR PARTNERS	$	2,040		$	6,587		$	(19,628	)	$	(8,808	)

Segment Financial and Operating Data

	Three Months Ended Dec. 31,				Year to Date Dec. 31,
($ in thousands)	2007		2006		2007		2006
Gathering and Processing Segment
Financial data
Segment margin	$	28,787	$	30,121	$	132,577	$	111,372
Adjusted segment margin	$	40,437	$	29,316	$	147,526	$	108,872
Operating data
Throughput (MMbtu/d)		763,184		605,181		745,020		529,467
NGL gross production (BBls/d)		23,414		19,480		21,803		18,587

	Three Months Ended Dec. 31,				Year to Date Dec. 31,
($ in thousands)	2007		2006		2007		2006
Transportation Segment
Financial data:
Segment margin	$	16,362	$	12,350	$	59,332	$	45,047
Adjusted segment margin	$	16,667	$	12,350	$	58,942	$	45,047
Operating data
Throughput (MMbtu/d)		735,081		672,946		751,761		587,098

Reconciliation of Non-GAAP Measures to GAAP Measures

	Three Months Ended Dec. 31,						Year to Date Dec. 31,
($ in thousands)	2007			2006			2007			2006
Net income (loss)	$	2,040		$	6,587		$	(19,628	)	$	(7,244	)
Income tax expense		866			-			931			-
Interest expense, net		10,276			9,863			52,016			37,182
Depreciation and amortization		14,264			11,348			51,739			39,654
EBITDA (a)	$	27,446		$	27,798		$	85,058		$	69,592
Non-cash loss (gain) from risk management activities		11,123			(1,812	)		11,500			(6,158	)
Non-cash put option expiration		832			1,007			3,059			3,658
LTIP accelerated vesting charge		-			-			11,928			-
Loss (gain) on sale of assets		(40	)		-			1,522			-
Loss on debt refinancing		-			(1,686	)		21,200			10,761
Management services termination fee		-			-			-			12,542
Acquisition expenses		420			156			420			2,041
Compressor insurance proceeds		(1,741	)		-			(1,741	)		-
Other income/expense		-			15			6			15
Management fee		-			-			-			360
Adjusted EBITDA	$	38,040		$	25,478		$	132,952		$	92,811
a) Earnings before interest, taxes, depreciation and amortization

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

	Three Months Ended
($ in thousands)	Dec. 31, 2007
Net cash flows provided by operating activities	$	24,534
Add (deduct):
Depreciation and amortization		(14,755	)
Risk management portfolio value changes		(11,955	)
Gain on sale of assets		40
Unit based compensation expenses		(744	)
Accrued revenues and accounts receivable		14,321
Other current assets		1,700
Accounts payable and accrued liabilities		(17,466	)
Accrued taxes payable		2,553
Other current liabilities		5,116
Other assets		(1,304	)
Net income	$	2,040
Add (deduct):
Income tax expense (benefit)		866
Interest expense, net		10,276
Depreciation and amortization		14,264
EBITDA	$	27,446
Add (deduct):
Non-cash loss from risk management activities		11,123
Non-cash put option expiration		832
Gain on sale of assets		(40	)
Acquisition expenses		420
Compressor insurance proceeds		(1,741	)
Adjusted EBITDA	$	38,040
�� Add (deduct):
Unit based compensation expenses		744
Interest expense, excluding capitalized interest		(9,960	)
Maintenance capital expenditures		(1,465	)
Income taxes		(579	)
Cash available for distribution	$	26,780

Non-GAAP Adjusted Segment Margin to GAAP Net Income (Loss)

	Three Months Ended Dec. 31,						Year to Date Dec. 31,
($ in thousands)	2007			2006			2007			2006
Net income (loss)	$	2,040		$	6,587		$	(19,628	)	$	(7,244	)
Add:
Operation and maintenance		11,065			11,102			45,474			39,496
General and administrative		6,581			5,276			39,543			22,826
Management services termination fee		-			-			-			12,542
Transaction expenses		420			320			420			2,041
Loss (gain) on sale of assets		(40	)		-			1,522			-
Depreciation and amortization		14,264			11,348			51,739			39,654
Interest expense, net		10,276			9,863			52,016			37,182
Loss on debt refinancing		-			(1,686	)		21,200			10,761
Other income and deductions, net		(323	)		(339	)		(1,308	)		(839	)
Income tax expense (benefit)		866			-			931			-
Total Segment Margin	$	45,149		$	42,471		$	191,909		$	156,419
Non-cash loss (gain) from risk management activities		11,123			(1,812	)		11,500			(6,158	)
Non-cash put option expiration		832			1,007			3,059			3,658
Adjusted Total Segment Margin	$	57,104		$	41,666		$	206,468		$	153,919
Transportation segment margin		16,362			12,350			59,332			45,047
Non-cash loss (gain) from risk management activities		305			-			(390	)		-
Adjusted Segment Margin for Transportation		16,667			12,350			58,942			45,047
Adjusted Segment Margin for Gathering and Processing	$	40,437		$	29,316		$	147,526		$	108,872