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

Exhibit 99.1

Regency Energy Partners Reports Third Quarter 2007 Financial Results

Third-quarter 2007 Adjusted EBITDA Increased by 34%
Versus the Prior Year Period

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

Revenue for the third quarter 2007 increased 25% to $285 million, compared to $229 million for the third quarter 2006. Adjusted total segment margin increased by 27% to $53 million in the third quarter 2007, compared to $42 million in last year’s third quarter. The Partnership’s adjusted EBITDA increased 34% to $35 million for the third quarter 2007, compared to $26 million for the third quarter 2006.

The Partnership had a net loss of $13 million for the three months ended September 30, 2007, compared to a net loss of $11 million for the three months ended September 30, 2006. Third-quarter 2007 results included a $16-million charge for the early redemption premium associated with the repurchase of 35% of Regency’s senior notes and the write-off of $5 million in loan origination costs. During the third quarter 2007, Regency also recorded a $4 million increase in depreciation and amortization expense, and a $2 million increase in operation and maintenance expense.

“Regency has seen impressive year-over-year growth in our adjusted EBITDA. Comparing our year-to-date performance in 2007 to 2006, our adjusted EBITDA has increased by 41%,” said James W. Hunt, Chairman, President and Chief Executive Officer of Regency. “We are executing our growth strategy. Regency will continue to focus on growing the business through third-party acquisitions and organic growth projects, and we will complement this growth with drop-down acquisitions from GE Energy Financial Services.”

As previously announced on October 26, 2007, Regency is in advanced negotiations regarding the acquisition of FrontStreet Hugoton LLC from an affiliate of GE Energy Financial Services for approximately $150 million. FrontStreet Hugoton LLC owns a gas gathering system in Kansas and Oklahoma, also known as the Hugoton gas gathering system. Regency expects the

acquisition of FrontStreet Hugoton’s Kansas-Hugoton assets to be immediately accretive to cash available for distribution and is expected to be completed later this year.

“The acquisition would nearly double Regency’s footprint in Kansas,” Hunt added. “The Kansas-Hugoton assets also complement our existing gathering system in the Midcontinent region, providing additional synergies and opportunities for organic growth.”

CASH DISTRIBUTIONS

On October 26, 2007, the Partnership announced a cash distribution of 39 cents per unit for the third quarter ended September 30, 2007. This represents a 2.6% increase in the distribution paid for the previous quarter and an 11.4% increase over the minimum quarterly distribution. The distribution is equivalent to $1.56 on an annual basis and will be paid on November 14, 2007, to unitholders of record at the close of business on November 7, 2007.

In the third quarter 2007, Regency generated $23 million in cash available for distribution, representing coverage of 1.40 times the amount required to cover distribution to common unitholders, and 0.95 times the amount required to cover distribution to the general partner and all limited partners, including subordinated unitholders. The third-quarter 2007 cash available for distribution included a partial quarter of interest savings from paying down Regency’s remaining term loan and $193 million of its outstanding senior notes.

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 incurred $68 million of organic growth projects during the nine months ended September 30, 2007. The major projects completed to date include 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. Due to weather-related delays, the Tilden to Fashing pipeline extension in South Texas is now expected to be completed in the first half of 2008.

REVIEW OF SEGMENT PERFORMANCE

Company adjusted total segment margin for Gathering & Processing and Transportation increased by 27% from $42 million in the third quarter 2006 to $53 million in the third 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 $38 million for the quarter ended September 30, 2007, compared to $30 million for the prior year period, a 28% increase.

Total throughput volumes of natural gas for the Gathering & Processing segment increased by 27% from an average of 590 thousand MMbtu per day in the third quarter 2006 to an average of 752 thousand MMbtu per day in the third quarter 2007. Processed NGLs increased by 11% from an average of 20 thousand barrels per day in the third quarter 2006 to an average of 23 thousand barrels per day in the third quarter 2007.

Transportation – The Transportation segment includes the Partnership’s natural gas transportation pipelines and related facilities and activities. Adjusted segment margin for Transportation was $15 million for the third quarter 2007, 26% higher than the $12 million in the prior year period. Total transportation throughput volumes for the Transportation segment averaged 789 thousand MMbtu per day of natural gas for the quarter ended September 30, 2007, 20% higher than the 656 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 third-quarter 2007 results on Wednesday, November 14, 2007, at 10 a.m. Central Time (11 a.m. Eastern Time).

The dial-in number for the call is 1-866-202-3048 in the United States, or +1-617-213-8843 outside the United States, pass code 78075037. 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 38861592. 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 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, 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 Cornelius
HCK2 Partners
972-716-0500 x26
elizabeth.browne@hck2.com

Consolidated Statements of Operations

	Three Months Ended Sep. 30,						Year to Date Sep. 30,
	2007			2006			2007			2006
($ in thousands)
REVENUE
Gas sales	$	175,107		$	135,532		$	538,360		$	425,282
NGL sales		90,605			72,997			237,382			194,176
Gathering, transportation and other fees (includes related party revenues of $541 and $1,325 in 2007 and $540 and $1,656 in 2006)		20,254			17,125			58,017			44,559
Unrealized/realized gain/(loss) from risk management activities		(8,088	)		(3,090	)		(10,798	)		(7,172	)
Other		7,563			6,568			20,443			18,211
Total revenue		285,441			229,132			843,404			675,056
OPERATING COSTS AND EXPENSES
Cost of gas and liquids (includes related party expenses of $656 and $13,829 in 2007 and $499 and $1,765 in 2006)		234,946			186,345			696,644			561,108
Operation and maintenance		12,477			10,567			34,409			28,394
General and administrative		6,818			6,932			32,962			19,271
Loss (gain) on sale of assets		(777	)		—			1,562			—
Management services termination fee		—			3,542			—			12,542
Depreciation and amortization		13,542			9,759			37,475			28,306
Total operating costs and expenses		267,006			217,145			803,052			649,621
OPERATING INCOME		18,435			11,987			40,352			25,435
OTHER INCOME AND DEDUCTIONS
Interest expense, net		(10,894	)		(10,929	)		(41,740	)		(27,319	)
Loss on debt refinancing		(21,200	)		(12,447	)		(21,200	)		(12,447	)
Other income and deductions, net		703			117			985			500
Total other income and deductions		(31,391	)		(23,259	)		(61,955	)		(39,266	)
LOSS BEFORE INCOME TAXES		(12,956	)		(11,272	)		(21,603	)		(13,831	)
Income tax expense (benefit)		(160	)		—			65			—
NET LOSS		(12,796	)		(11,272	)		(21,668	)		(13,831	)
Less:
Net income from January 1-31, 2006		—			—			—			1,564
NET LOSS FOR PARTNERS	$	(12,796	)	$	(11,272	)	$	(21,668	)	$	(15,395	)

Segment Financial and Operating Data

	Three Months Ended Sep. 30,				Year to Date Sep. 30,
($ in thousands)	2007		2006		2007		2006
Gathering and Processing Segment
Financial data
Segment margin	$	35,207	$	30,694	$	103,790	$	81,251
Adjusted segment margin	$	38,197	$	29,929	$	107,089	$	79,557
Operating data
Throughput (MMbtu/d)		751,911		590,192		745,823		503,952
NGL gross production (BBls/d)		22,655		20,376		21,233		18,286

	Three Months Ended Sep. 30,				Year to Date Sep. 30,
($ in thousands)	2007		2006		2007		2006
Transportation Segment
Financial data:
Segment margin	$	15,288	$	12,093	$	42,970	$	32,697
Adjusted segment margin	$	15,250	$	12,093	$	42,275	$	32,697
Operating data
Throughput (MMbtu/d)		788,789		656,494		757,367		558,168

Reconciliation of Non-GAAP Measures to GAAP Measures

	Three Months Ended Sep. 30,						Year to Date Sep. 30,
($ in thousands)	2007			2006			2007			2006
Net loss	$	(12,796	)	$	(11,272	)	$	(21,668	)	$	(13,831	)
Income tax expense (benefit)		(160	)		—			65			—
Interest expense, net		10,894			10,929			41,740			27,319
Depreciation and amortization		13,542			9,759			37,475			28,306
EBITDA (a)	$	11,480		$	9,416		$	57,612		$	41,794
Non-cash loss (gain) from risk management activities		2,160			(1,725	)		377			(4,346	)
Non-cash put option expiration		792			960			2,227			2,652
LTIP accelerated vesting charge		—			—			11,928			—
Loss (gain) on sale of assets		(777	)		—			1,562			—
Loss on debt refinancing		21,200			12,447			21,200			12,447
Management services termination fee		—			3,542			—			12,542
Acquisition expenses		—			1,201			—			1,885
Other income/expense		—			—			6			—
Management fee		—			88			—			360
Adjusted EBITDA	$	34,855		$	25,929		$	94,912		$	67,334

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 loss

	Three Months Ended
($ in thousands)	Sep. 30, 2007
Net cash flows provided by operating activities	$	13,840
Add (deduct):
Depreciation and amortization		(14,353	)
Loss on debt refinancing		(5,078	)
Risk management portfolio value changes		(2,225	)
Gain on sale of assets		778
Unit based compensation expenses		(705	)
Accrued revenues and accounts receivable		(4,591	)
Other current assets		(49	)
Accounts payable and accrued liabilities		6,741
Accrued taxes payable		(1,706	)
Interest payable		(6,052	)
Other current liabilities		156
Other assets		448
Net loss	$	(12,796	)
Add (deduct):
Income tax expense (benefit)		(160	)
Interest expense, net		10,894
Depreciation and amortization		13,542
EBITDA	$	11,480
Add (deduct):
Non-cash loss from risk management activities		2,160
Non-cash put option expiration		792
Gain on sale of assets		(777	)
Loss on debt refinancing		21,200
Adjusted EBITDA	$	34,855
Add (deduct):
Unit based compensation expenses		705
Interest expense, excluding capitalized interest		(11,806	)
Maintenance capital expenditures		(2,388	)
Proceeds from sale of assets		1,300
Income taxes		(127	)
Cash available for distribution	$	22,539

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

	Three Months Ended Sep. 30,						Year to Date Sep. 30,
($ in thousands)	2007			2006			2007			2006
Net loss	$	(12,796	)	$	(11,272	)	$	(21,668	)	$	(13,831	)
Add:
Operation and maintenance		12,477			10,567			34,409			28,394
General and administrative		6,818			6,932			32,962			19,271
Management services termination fee		—			3,542			—			12,542
Loss (gain) on sale of assets		(777	)		—			1,562			—
Depreciation and amortization		13,542			9,759			37,475			28,306
Interest expense, net		10,894			10,929			41,740			27,319
Loss on debt refinancing		21,200			12,447			21,200			12,447
Other income and deductions, net		(703	)		(117	)		(985	)		(500	)
Income tax expense (benefit)		(160	)		—			65			—
Total Segment Margin	$	50,495		$	42,787		$	146,760		$	113,948
Non-cash loss (gain) from risk management activities		2,160			(1,725	)		377			(4,346	)
Non-cash put option expiration		792			960			2,227			2,652
Adjusted Total Segment Margin	$	53,447		$	42,022		$	149,364		$	112,254
Transportation segment margin		15,288			12,093			42,970			32,697
Non-cash loss (gain) from risk management activities		(38	)		—			(695	)		—
Adjusted Segment Margin for Transportation		15,250			12,093			42,275			32,697
Adjusted Segment Margin for Gathering and Processing	$	38,197		$	29,929		$	107,089		$	79,557