Resources Connection 8-K Regency Energy Partners Reports Second-Quarter 2007 Financial Results

Exhibit 99.1

Regency Energy Partners Reports Second-Quarter 2007 Financial Results

Second-quarter 2007 Adjusted EBITDA Increased by 53%
vs. the prior year period

DALLAS, Aug 14, 2007 – Regency Energy Partners LP (Nasdaq: RGNC) (“Regency” or the “Partnership”) announced today its financial results for the second quarter ended June 30, 2007.

Revenue for the second quarter 2007 increased 40% to $302 million, compared to $215 million for the second quarter of 2006. Adjusted total segment margin increased by 43% to $51 million in the second quarter 2007, compared to $36 million in last year’s second quarter. The Partnership’s adjusted EBITDA increased 53% to $33 million for the second quarter 2007, compared to $22 million for the second quarter of 2006. Comparing second-quarter 2007 results to first-quarter 2007 results, adjusted EBITDA increased by 24%.

The Partnership had a net loss of $8 million for the three months ended June 30, 2007, compared to a net income of $4 million for the three months ended June 30, 2006. Second-quarter 2007 results included an increase in general and administrative expenses of $12 million (consisting primarily of a nonrecurring charge resulting from the vesting of all of long-term incentive plan awards upon the change of ownership of our general partner), an increase in interest expense of $8 million, an increase in operation and maintenance expense of $3 million, and an increase in depreciation and amortization expense of $3 million.

“Our strong operational performance in the second quarter was due to improved segment volumes and margins, generated from the completion of some of our major organic growth projects,” said James W. Hunt, Chairman, President and Chief Executive Officer of Regency. “We are well positioned for a strong finish to 2007 with the acquisition of Pueblo Midstream Gas Corp., the acquisition by GE Energy Financial Services of our general partner, and a successful $361 million equity offering, which will significantly reduce our interest expense going forward.”

Hunt added, “Moving forward, Regency will serve as a platform for GE Energy Financial Services’ growth in the midstream sector. We have revised our growth strategy and, in addition to organic growth projects, we will pursue strategic midstream assets from third parties that may be outside our current geographic focus or more expansive in nature.”

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CASH DISTRIBUTIONS

On July 27, 2007, the Partnership announced a cash distribution of 38 cents per unit for the second quarter ended June 30, 2007. The distribution will be paid on Aug. 14, 2007, to unitholders of record at the close of business on Aug. 7, 2007. This quarterly distribution equates to $1.52 on an annual basis.

In the second quarter 2007, Regency generated $21 million in cash available for distribution, representing coverage of 1.35 times the amount required to cover distribution to common unitholders and 0.92 times the amount required to cover the distribution to the general partner and all limited partners, including subordinated unitholders. This includes distributions paid on the 11.5 million units issued after the quarter closed. Excluding distributions on these newly issued units, the coverage ratio would have been 1.88 times the amount required to cover distributions to common unitholders and 1.13 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

The Partnership completed three major organic growth projects in the second quarter: 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. These projects constitute the majority of the $56 million of capital expenditures the Partnership incurred on organic growth projects in the first half of 2007. Regency is executing on an additional $32 million of organic growth projects that are scheduled to be completed in the second half of 2007.

REVIEW OF SEGMENT PERFORMANCE

Company adjusted total segment margin for Gathering & Processing and Transportation increased by 43% from $36 million in the second quarter 2006 to $51 million in the second quarter 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 $39 million for the quarter ended June 30, 2007, compared to $25 million for the prior year period, a 53% increase.

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Total throughput volumes for the Gathering & Processing segment averaged 756 thousand MMbtu per day of natural gas, and processed NGLs averaged 21 thousand barrels per day for the quarter ended June 30, 2007, compared to 496 thousand MMbtu per day of natural gas and 17 thousand barrels for produced NGLs for the second quarter 2006.

Transportation – The Transportation segment includes the Partnership’s natural gas transportation pipelines and related facilities and activities. Adjusted segment margin for Transportation was $13 million for the second quarter 2007, 19% higher than the $11 million in the prior year period. Total transportation throughput volumes for the Transportation segment averaged 778 thousand MMbtu per day of natural gas for the quarter ended June 30, 2007, 35% higher than the 577 thousand MMbtu per day of natural gas for the corresponding period in 2006.

TELECONFERENCE

Regency Energy Partners will hold a quarterly conference call to discuss second-quarter 2007 results on Tuesday, Aug. 14, 2007, at 10 a.m. Central Time (11 a.m. Eastern Time).

The dial-in number for the call is 1-866-277-1182 in the United States, or +1-617-597-5359 outside the United States, pass code 10595351. A live webcast of the call can be accessed on the investor information page of Regency Energy Partners’ Web site atwww.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 73433988. 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.

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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, and 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 made an adjustment for the accelerated vesting of our long-term incentive program due to the change of control of our general partner. We consider this charge 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 non-cash items affecting adjusted EBITDA, such as non-cash unit-based compensation expense related to our Long-Term Incentive Plan (LTIP),

• minus interest expense,

• 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.

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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

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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, 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 atwww.regencyenergy.com.

CONTACT:

Investor Relations:
Shannon Ming
Director, Investor Relations
Regency Energy Partners
214-239-0093
Shannon.ming@regencygas.com

Media Relations:
Elizabeth Browne
HCK2 Partners
972-716-0500 x26
ebrowne@hck2.com

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Consolidated Statements of Operations

	Three Months Ended June 30,						Year to Date June 30,
($ in thousands)	2007			2006			2007			2006
REVENUE
Gas sales	$	195,870		$	131,278		$	363,253		$	289,750
NGL sales		83,236			65,043			146,777			121,179
Gathering, transportation and other fees (includes related party revenues of $431 and $784 in 2007 and $597 and $1,116 in 2006)		17,884			14,730			37,763			27,434
Unrealized/realized gain/(loss) from risk management activities		(2,625	)		(2,425	)		(2,710	)		(4,082	)
Other		7,171			6,032			12,881			11,643
Total revenue		301,536			214,658			557,964			445,924
OPERATING COSTS AND EXPENSES
Cost of gas and liquids (includes related party expenses of $7,755 and $13,173 in 2007 and $753 and $1,266 in 2006)		249,760			178,027			461,698			374,763
Operation and maintenance		11,008			8,382			21,932			17,827
General and administrative		19,293			6,923			26,144			12,339
Loss on sale of assets		532			—			2,340			—
Management services termination fee		—			—			—			9,000
Depreciation and amortization		12,507			9,378			23,934			18,547
Total operating costs and expenses		293,100			202,710			536,048			432,476
OPERATING INCOME		8,436			11,948			21,916			13,448
OTHER INCOME AND DEDUCTIONS
Interest expense, net		(15,961	)		(8,389	)		(30,846	)		(16,390	)
Other income and deductions, net		173			201			283			383
Total other income and deductions		(15,788	)		(8,188	)		(30,563	)		(16,007	)
NET INCOME (LOSS) BEFORE INCOME TAXES		(7,352	)		3,760			(8,647	)		(2,559	)
Income tax expense		225			—			225			—
NET INCOME (LOSS)		(7,577	)		3,760			(8,872	)		(2,559	)
Less:
Net income from January 1-31, 2006		—			—			—			1,564
NET INCOME (LOSS) FOR PARTNERS	$	(7,577	)	$	3,760		$	(8,872	)	$	(4,123	)

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Segment Financial and Operating Data

	Three Months Ended June 30,				Year to Date June 30,
($ in thousands)	2007		2006		2007		2006
Gathering and Processing Segment
Financial data
Segment margin	$	38,407	$	25,914	$	68,584	$	50,556
Adjusted segment margin	$	38,708	$	25,234	$	68,893	$	49,627
Operating data
Throughput (MMbtu/d)		756,092		496,238		742,729		460,116
NGL gross production (BBls/d)		20,967		16,972		20,510		17,224

	Three Months Ended June 30,				Year to Date June 30,
($ in thousands)	2007		2006		2007		2006
Transportation Segment
Financial data:
Segment margin	$	13,369	$	10,717	$	27,682	$	20,605
Adjusted segment margin	$	12,712	$	10,717	$	27,025	$	20,605
Operating data
Throughput (MMbtu/d)		777,927		577,217		741,395		508,190

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Reconciliation of Non-GAAP Measures to GAAP Measures

	Three Months Ended June 30,						Year to Date June 30,
($ in thousands)	2007			2006			2007			2006
Net income (loss)	$	(7,577	)	$	3,760		$	(8,872	)	$	(2,559	)
Income tax expense		225			—			225			—
Interest expense, net		15,961			8,389			30,846			16,390
Depreciation and amortization		12,507			9,378			23,934			18,547
EBITDA (a)	$	21,116		$	21,527		$	46,133		$	32,378
Non-cash loss (gain) from risk management activities		(1,098	)		(1,568	)		(1,783	)		(2,621	)
Non-cash put option expiration		742			888			1,435			1,692
LTIP accelerated vesting charge		11,928			—			11,928			—
Loss on sale of assets		532			—			2,340			—
Management services termination fee		—			—			—			9,000
Acquisition expenses		—			684			—			684
Other income/expense		—			—			6			—
Management fee		—			135			—			273
Adjusted EBITDA	$	33,220		$	21,666		$	60,059		$	41,406

a) Earnings before interest, taxes, depreciation and amortization

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

	Three Months Ended
($ in thousands)	June 30, 2007
Net cash flows provided by operating activities	$	8,569
Add (deduct):
Depreciation and amortization		(12,640	)
Risk management portfolio value changes		467
Loss on sale of assets		(532	)
Unit based compensation expenses		(12,982	)
Accounts receivable		18,919
Other current assets		240
Accounts payable and accrued liabilities		(20,374	)
Accrued taxes payable		(1,479	)
Interest payable		11,899
Other current liabilities		279
Other assets		57
Net loss	$	(7,577	)
Add:
Income tax expense		225
Interest expense, net		15,961
Depreciation and amortization		12,507
EBITDA	$	21,116
Add (deduct):
Non-cash gain from risk management activities		(1,098	)
Non-cash put option expiration		742
Loss on sale of assets		532
LTIP accelerated vesting charge		11,928
Adjusted EBITDA	$	33,220
Add (deduct):
Unit based compensation expenses		1,342
Interest expense		(15,622	)
Maintenance capital expenditures		(2,372	)
Proceeds from sale of assets		4,786
Income tax payment		(225	)
Cash available for distribution	$	21,129

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

	Three Months Ended June 30,						Year to Date June 30,
($ in thousands)	2007			2006			2007			2006
Net income (loss)	$	(7,577	)	$	3,760		$	(8,872	)	$	(2,559	)
Add:
Operation and maintenance		11,008			8,382			21,932			17,827
General and administrative		19,293			6,923			26,144			12,339
Management services termination fee		—			—			—			9,000
Loss on sale of assets		532			—			2,340			—
Depreciation and amortization		12,507			9,378			23,934			18,547
Interest expense, net		15,961			8,389			30,846			16,390
Other income and deductions, net		(173	)		(201	)		(283	)		(383	)
Income tax expense		225			—			225			—
Total Segment Margin	$	51,776		$	36,631		$	96,266		$	71,161
Non-cash loss (gain) from risk management activities		(1,098	)		(1,568	)		(1,783	)		(2,621	)
Non-cash put option expiration		742			888			1,435			1,692
Adjusted Total Segment Margin	$	51,420		$	35,951		$	95,918		$	70,232
Transportation segment margin		13,369			10,717			27,682			20,605
Non-cash loss (gain) from risk management activities		(657	)		—			(657	)		—
Adjusted Segment Margin for Transportation		12,712			10,717			27,025			20,605
Adjusted Segment Margin for Gathering and Processing	$	38,708		$	25,234		$	68,893		$	49,627

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