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

Exhibit 99.1

Regency Energy Partners Reports First-Quarter 2007 Financial Results

First-quarter 2007 Adjusted EBITDA Increased by 36% vs. First Quarter 2006

DALLAS, May 15, 2007 — Regency Energy Partners LP (Nasdaq: RGNC) (“Regency” or the “Partnership”) announced today its financial results for the first quarter ended March 31, 2007.

Revenue for the first quarter 2007 increased 10.9% to $256.4 million, compared to $231.3 million for the first quarter 2006. Adjusted total segment margin increased by 29.8% to $44.5 million in the first quarter 2007, compared to $34.3 million in last year’s first quarter. The Partnership’s adjusted EBITDA increased 36% to $26.8 million for the first quarter 2007, compared to $19.7 million in the first quarter 2006.

The Partnership had a net loss of $1.3 million for the three months ended March 31, 2007, compared to a loss of $6.3 million for the three months ended March 31, 2006. First-quarter 2007 results included an increase in interest expense of $6.9 million, an increase in depreciation and amortization expense of $2.3 million, and a loss on the disposal of certain non-strategic assets of $1.8 million. First-quarter 2006 results included a charge against earnings of $9 million for fees paid by the Partnership to terminate two long-term management services contracts in connection with Regency’s initial public offering. All results reflect the TexStar Field Services acquisition accounted for in a manner similar to a pooling of interests since the acquisition involved entities under common control.

“We had a good start to 2007 with the completion of three major organic growth projects in South and East Texas,” said James W. Hunt, Chairman, President and Chief Executive Officer of Regency. “In addition, as part of our integration of TexStar, we completed a divestiture of certain non-core assets acquired as part of the transaction. We are well positioned for continued growth in the second quarter.”

CASH DISTRIBUTIONS

On April 27, 2007, the Partnership announced a cash distribution of 38 cents per unit for the first quarter ended March 31, 2007. This represents a 2.7% increase in the distribution paid for the previous quarter and an 8.6% increase over the minimum quarterly distribution. The distribution is equivalent to $1.52 on an annual basis and will be paid on May 15, 2007, to unitholders of record at the close of business on May 8, 2007.

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In the first quarter of 2007, Regency generated $18.4 million in cash available for distribution, representing coverage of 1.66 times the amount required to cover its distribution to common unitholders, and 1.00 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

Earlier this month, the Partnership completed three major organic growth projects: the activation of a nitrogen rejection unit at the East Texas Eustace Plant, an addition of 31 miles of gathering pipeline in South Texas, and the electrification project and addition of acid gas injection capabilities at the South Texas Tilden Plant. These projects constitute the majority of the $33 million the Partnership spent on organic growth projects in the first quarter 2007. This activity follows the completion and start-up of three other significant projects in the fourth quarter 2006: a 200-MMcf/d dewpoint-control facility in Webster Parish, La., additional compression for the Regency Intrastate Gas System (RIGS) in North Louisiana, and a 26-mile pipeline in South Texas.

REVIEW OF SEGMENT PERFORMANCE

Company total adjusted segment margin for Gathering & Processing and Transportation increased by 29.8% from $34.5 million in the first quarter of 2006 to $44.5 million in the first quarter of 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 $30.2 million for the quarter ended March 31, 2007, compared to $24.4 million for the same period in 2006, a 23.8% increase.

Total throughput volumes for the Gathering & Processing segment averaged 729 thousand MMbtu per day of natural gas, and processed NGLs averaged 20 thousand barrels per day for the quarter ended March 31, 2007, compared to 424 thousand MMbtu per day of natural gas and 17 thousand barrels for produced NGLs for the first quarter 2006.

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Transportation — The Transportation segment includes the Partnership’s natural gas transportation pipelines and related facilities and activities. Segment margin for Transportation was $14.3 million for the first quarter 2007, 44.8% higher than the $9.9 million in the same quarter 2006. Total transportation throughput volumes for the Transportation segment averaged 704 thousand MMbtu per day of natural gas for the quarter ended March 31, 2007, 60.7% higher than the 438 thousand MMbtu per day of natural gas for the corresponding period in 2006.

TELECONFERENCE

Regency Energy Partners will hold its quarterly conference call to discuss first-quarter 2007 results on Tuesday, May 15, 2007, at 10 a.m. Central Time (11 a.m. Eastern Time).

The dial-in number for the call is 1-866-203-3436 in the United States, or +1-617-213-8849 outside the United States, pass code 40791343. 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 71634216. 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, non-cash loss (gain) from risk management activities, non-cash commodity put option expirations and loss on debt refinancing.

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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 a termination fee paid in the first quarter of 2006 in connection with our initial public offering. We also made an adjustment for management fees paid under these contracts that we consider to be non-recurring.

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, 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 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.

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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 is a growth-oriented, midstream energy partnership engaged in the gathering, processing, marketing and transportation of natural gas and natural gas liquids. For more information, visit the Regency Energy Partners LP Web site at www.regencyenergy.com.

CONTACT:

Investor Relations:

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

Media Relations:
Elizabeth Browne
Michael & Partners
972-716-0500 x26
ebrowne@michaelpartners.com

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Consolidated Statements of Operations

	Three Months Ended Mar. 31,
	2007			2006
($ in thousands)
REVENUE
Gas sales	$	167,384		$	158,472
NGL sales		63,541			56,136
Gathering, transportation and other fees (includes related party revenues of $353 in 2007 and $519 in 2006)		19,878			12,704
Unrealized/realized gain/(loss) from risk management activities		(85	)		(1,657	)
Other		5,710			5,611
Total revenue		256,428			231,266
OPERATING COSTS AND EXPENSES
Cost of gas and liquids (includes related party expenses of $5,418 in 2007 and $513 in 2006)		211,937			196,736
Operation and maintenance		10,925			9,445
General and administrative		6,851			5,416
Loss on sale of assets		1,808			—
Management services termination fee		—			9,000
Depreciation and amortization		11,427			9,169
Total operating costs and expenses		242,948			229,766
OPERATING INCOME		13,480			1,500
OTHER INCOME AND DEDUCTIONS
Interest expense, net		(14,885	)		(8,001	)
Other income and deductions, net		110			182
Total other income and deductions		(14,775	)		(7,819	)
NET LOSS		(1,295	)		(6,319	)
Less:
Net income from January 1-31, 2006		—			1,564
NET LOSS FOR PARTNERS	$	(1,295	)	$	(7,883	)

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Segment Financial and Operating Data

	Three Months Ended Mar. 31,
($ in thousands)	2007		2006
Gathering and Processing Segment
Financial data
Segment margin	$	30,178	$	24,643
Adjusted segment margin	$	30,187	$	24,393
Operating data
Throughput (MMbtu/d)		729,218		423,593
NGL gross production (BBls/d)		20,047		17,478

	Three Months Ended Mar. 31,
($ in thousands)	2007		2006
Transportation Segment
Financial data:
Segment margin	$	14,313	$	9,887
Operating data
Throughput (MMbtu/d)		704,458		438,396

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Reconciliation of Non-GAAP Measures to GAAP Measures

	Three Months Ended Mar. 31,
($ in thousands)	2007			2006
Net loss	$	(1,295	)	$	(6,319	)
Interest expense, net		14,885			8,001
Depreciation and amortization		11,427			9,169
EBITDA (a)	$	25,017		$	10,851
Non-cash loss (gain) from risk management activities		(684	)		(1,053	)
Non-cash put option expiration		693			803
Loss on sale of assets		1,808			—
Management services termination fee		—			9,000
Other income/expense		6			—
Management fee		—			138
Adjusted EBITDA	$	26,840		$	19,739

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)	Mar. 31, 2007
Net cash flows provided by operating activities	$	27,470
Add (deduct):
Depreciation and amortization		(11,986	)
Risk management portfolio value changes		124
Equity income		43
Loss on sale of assets		(1,808	)
Unit based compensation expenses		(1,103	)
Accounts receivable		1,959
Other current assets		(598	)
Accounts payable and accrued liabilities		(5,220	)
Accrued taxes payable		(203	)
Interest payable		(11,918	)
Other current liabilities		1,504
Other assets		441
Net loss	$	(1,295	)
Add:
Interest expense, net		14,885
Depreciation and amortization		11,427
EBITDA	$	25,017
Add (deduct):
Non-cash gain from risk management activities		(684	)
Non-cash put option expiration		693
Loss on sale of assets		1,808
Other income/expense		6
Adjusted EBITDA	$	26,840
Add (deduct):
Unit based compensation expenses		1,103
Interest expense		(14,255	)
Maintenance capital expenditures		(864	)
Proceeds from sale of assets		5,610
Cash available for distribution	$	18,434

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Non-GAAP Adjusted Segment Margin to GAAP Net Loss

	Three Months Ended Mar. 31,
($ in thousands)	2007			2006
Net loss	$	(1,295	)	$	(6,319	)
Add:
Operation and maintenance		10,925			9,445
General and administrative		6,851			5,416
Management services termination fee		—			9,000
Loss on sale of assets		1,808			—
Depreciation and amortization		11,427			9,169
Interest expense, net		14,885			8,001
Other income and deductions, net		(110	)		(182	)
Total Segment Margin	$	44,491		$	34,530
Non-cash loss (gain) from risk management activities		(684	)		(1,053	)
Non-cash put option expiration		693			803
Adjusted Total Segment Margin	$	44,500		$	34,280
Transportation segment margin		(14,313	)		(9,887	)
Adjusted Segment Margin for Gathering and Processing	$	30,187		$	24,393

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