exv99w1

Exhibit 99.1

Regency Energy Partners Reports Third-Quarter 2006 Financial Results

Quarterly adjusted EBITDA Increased by 20% vs. 2006 Second Quarter

DALLAS, Nov. 14, 2006 — Regency Energy Partners LP (Nasdaq: RGNC) (“Regency” or the “Partnership”) today reported its financial results for the quarter ended September 30, 2006.

Revenue for the third quarter 2006 increased 20% to $229.1 million, compared to $191.6 million for the third quarter 2005. The Partnership’s adjusted EBITDA increased 81% to $25.9 million, compared to $14.3 million in the corresponding 2005 period. Comparing third-quarter 2006 results to second-quarter 2006 results, adjusted EBITDA increased by 20% from $21.7 million. All results reflect the TexStar acquisition accounted for in a manner similar to a pooling of interests.

For the third quarter 2006, the Partnership reported a partner net loss of $11.3 million, compared to net loss of $3.9 million for third quarter 2005. Third-quarter 2006 results included the following nonrecurring expenses: $12.4 million resulting from the write-off of capitalized debt issuance expense (loss on debt financing); $3.5 million in fees related to the termination of a TexStar long-term management contract in connection with its acquisition by Regency; and $1.2 million in acquisition expenses related to the acquisition of TexStar. Third-quarter 2005 results included a $7.7 million loss resulting from the write-off of capitalized debt issuance expense.

For the first nine months of 2006, Regency had a partner net loss of $15.4 million, compared to a net loss of $12.4 million for the corresponding nine months in 2005. The nine months of 2006 results include nonrecurring charges, in addition to those recognized during the third quarter, of $9 million for fees paid to terminate two long-term management services contracts in connection with Regency’s initial public offering and an additional $0.7 million in acquisition expenses related to the acquisition of TexStar. The 2005 net loss included $12.7 million of unrealized losses from risk management activities in addition to the non-recurring charges incurred in the third quarter of 2005.

“The third quarter was characterized by improved volumes and segment margins in both our business segments,” said James W. Hunt, Chairman, President and Chief Executive Officer of Regency. “During the quarter, we achieved several significant milestones, including the closing of the TexStar Field Services acquisition, which enhances the geographic diversity of our asset base and creates numerous opportunities for near-term organic growth. We expect to have TexStar fully integrated by the end of the year.”

In September 2006, Regency completed a private equity placement. Regency issued approximately 2.9 million class C units to four institutional investors for $60 million in cash. The proceeds from the placement were used to repay indebtedness under Regency’s credit facilities that was incurred to fund a portion of the TexStar acquisition.

Also in the third quarter, Regency entered into a definitive, long-term agreement with a producer in North Louisiana, whereby Regency will provide the gathering, compression and processing infrastructure to bring the producers gas to market.

“The total current field production from this producer has grown significantly this year and now stands at approximately 42 thousand MMBTU/day,” said Mr. Hunt. “This agreement illustrates the full-service capabilities we can provide our customers to help them get their gas from the wellhead to market,” said Mr. Hunt.

CASH DISTRIBUTIONS

On October 27, 2006, the Partnership announced that it has increased its cash distribution on outstanding units to 37 cents per unit for the quarter ended September 30, 2006. This represents a 5.7% increase in the quarterly cash distribution and equates to a $1.48 per unit on an annual basis. The distribution will be paid on November 14, 2006, to unitholders of record at the close of business on November 7, 2006.

Regency’s cash available for distribution for the third quarter 2006 was $12.7 million, or 1.71 times the amount required to cover its third-quarter distribution to common unitholders and 0.87 times the amount required to cover the distribution to the general partner and all limited partners, including subordinated unitholders. For the first three quarters of this year, Regency generated $37.4 million in cash available for distribution, representing coverage of 1.99 times the amount required to cover its distribution to common unitholders and 1.01 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 pursue actively its organic growth strategy. In the first nine months of 2006, Regency has identified and is implementing near-term organic growth capital projects of approximately $120 million, of which Regency had spent $69 million as of September 30, 2006. As previously announced, the Elm Grove plant and the 16 miles of additional looping on the western segment of Regency Intrastate Gas System (RIGS) are complete and in service. The additional compression for the RIGS system will be complete in the fourth quarter 2006, and, coupled with the additional looping, will increase RIGS’ design capacity to 910 MMCF/d.

The construction of the 200-MMcf/d, dewpoint-control facility in Webster Parish, La., is expected to be completed during the fourth quarter of this year. Additionally, the construction of a 26-mile, 12-inch diameter pipeline in South Texas was completed in early November. This pipeline allows Regency to realize processing upgrades on a portion of its natural gas volumes in LaSalle County, Texas.

REVIEW OF SEGMENT PERFORMANCE

Gathering & Processing — The Gathering & Processing segment includes the Partnership’s natural gas processing and treating plants, low pressure gathering pipelines, NGL pipeline and related NGL marketing activities. Adjusted segment margin for Gathering & Processing, which excludes non-cash hedging gains and losses, was $30.4 million for third quarter 2006, compared to $19.2 million for the third quarter 2005, a 59% increase.

Total throughput volumes for the Gathering & Processing segment averaged 590 thousand MMBtu per day of natural gas, and processed NGLs averaged 20 thousand barrels per day for the quarter ended September 30, 2006, compared to 307 thousand MMBtu per day of natural gas and 14 thousand barrels for produced NGLs for the same quarter in 2005.

Transportation — The Transportation segment includes the Partnership’s natural gas transportation pipelines and related facilities and activities. Segment margin for Transportation was $12.1 million in the third quarter 2006, compared to $4.1 million for the third quarter 2005. Total transportation throughput volumes for the Transportation segment averaged 656 thousand MMBtu per day of natural gas for the quarter, compared to 327 thousand MMBtu per day of natural gas for the corresponding quarter in 2005.

TELECONFERENCE

Regency will hold a teleconference to discuss third-quarter results today, November 14, 2006, at 10 a.m. CT (11 a.m. ET). The dial-in number for the call is 1-800-573-4754 in the United States, or +1-617-224-4325 outside the United States, pass code 95716113. 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 seven days by dialing 1-888-286-8010 (from outside the U.S., +1-617-801-6888), pass code 83245949. 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, unrealized loss (gain) from risk management activities, non-cash commodity put option expirations and loss on debt refinancing.

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 adjustments for two 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 also made an adjustment for management fees paid under these contracts that we consider to be non-recurring.

Additionally, in deriving adjusted EBITDA for the third quarter 2006, we made an adjustment for acquisition expenses related to the TexStar transaction. Because TexStar and Regency are controlled by a common owner, we account for the acquisition in a manner similar to the pooling of interests method of accounting which requires Regency to expense acquisition costs that would have been capitalized if purchase accounting had been used.

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 cash 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.

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 unrealized losses (gains) 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 unrealized losses (gains) from risk management activities and non-cash commodity put option expirations. Our adjusted total segment margin equals the sum of our Gas Gathering and Processing adjusted segment margin and Gas 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.

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. Information contained in this press release is unaudited and is subject to change.

Regency Energy Partners LP (NASDAQ: RGNC) is a growth-oriented, midstream energy partnership that gathers, treats, compresses, processes, transports and markets natural gas and transports and markets 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

Consolidated Statement of Operations


	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2006			2005			2006			2005
($ in thousands)

REVENUE
Gas sales	$	135,532		$	134,057		$	425,282		$	301,620
NGL sales		72,997			48,694			194,176			123,742
Gathering, transportation and other fees		16,585			8,593			42,903			19,860
Related party revenues		540			227			1,656			574
Unrealized/realized loss from risk management activities		(3,090	)		(3,665	)		(7,172	)		(19,891	)
Other		6,568			3,648			18,211			10,543

Total revenue		229,132			191,554			675,056			436,448

EXPENSE
Cost of gas and liquids		185,846			168,514			559,343			387,054
Related party expenses		499			217			1,765			349
Operating expenses		10,567			5,619			28,394			16,408
General and administrative		6,932			3,672			19,271			9,822
Management services termination fee		3,542			—			12,542			—
Depreciation and amortization		9,759			5,521			28,306			16,076

Total operating expense		217,145			183,543			649,621			429,709

OPERATING INCOME		11,987			8,011			25,435			6,739

OTHER INCOME AND DEDUCTIONS
Interest expense, net		(10,929	)		(4,490	)		(27,319	)		(12,717	)
Loss on debt refinancing		(12,447	)		(7,724	)		(12,447	)		(7,724	)
Equity income		177			91			397			246
Other income and deductions, net		(60	)		221			103			284

Total other income and deductions		(23,259	)		(11,902	)		(39,266	)		(19,911	)

LOSS FROM CONTINUING OPERATIONS		(11,272	)		(3,891	)		(13,831	)		(13,172	)

DISCONTINUED OPERATIONS
Income from operations of Regency Gas Treating LP (including gain on disposal of $626 )		—			(15	)		—			732


NET LOSS		(11,272	)	$	(3,906	)		(13,831	)	$	(12,440	)


Less:
Net income through January 31, 2006		—						1,564

Net loss for partners	$	(11,272	)				$	(15,395	)

Segment Financial and Operating Data


	Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
($ in thousands, except where noted)	2006		2005		2006		2005


Gathering and Processing Segment
Financial data
Segment margin (a)	$	31,195	$	18,899	$	83,016	$	39,626
Adjusted segment margin	$	30,428	$	19,154	$	81,322	$	53,631
Operating data
Throughput (MMbtu/d)		590,192		307,097		503,952		308,196
NGL gross production (BBls/d)		20,376		14,375		18,286		15,341


a)		In the three months ended September 30, 2006 and 2005, revenues include unrealized gains of $1.7 million and $0.3 million. In the nine months ended September 30, 2006 and 2005 revenues include an unrealized gain of $4.3 million and an unrealized loss of $12.7 million.


	Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
(in thousands)	2006		2005		2006		2005


Transportation Segment
Financial data:
Segment margin	$	12,093	$	4,141	$	32,697	$	9,768
Operating data
Throughput (MMbtu/d)		656,494		327,185		558,168		249,275

Reconciliation of Non-GAAP Measures to GAAP Measures


	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
($ in thousands)	2006			2005			2006			2005


Net loss		($11,272	)		($3,906	)		($13,831	)		($12,440	)
Interest expense, net		10,929			4,490			27,319			12,717
Depreciation and amortization		9,759			5,521			28,306			16,076

EBITDA (a)	$	9,416		$	6,105		$	41,794		$	16,353
Unrealized loss (gain) from risk management activities		(1,725	)		(327	)		(4,346	)		12,712
Non-cash put option expiration		960			582			2,652			1,293
Acquisition expenses		1,201			—			1,885			—
Loss on debt financing		12,447			7,724			12,447			7,724
Management services termination fee		3,542			—			12,542			—
Management fee		88			253			360			760

Adjusted EBITDA	$	25,929		$	14,337		$	67,334		$	38,842


a)		Earnings before interest, taxes, depreciation and amortization


	Three Months Ended June 30,						Six Months Ended June 30,
($ in thousands)	2006			2005			2006			2005

Net income (loss)	$	3,760		$	6,528			($2,559	)		($8,534	)
Interest expense, net		8,389			5,031			16,390			8,227
Depreciation and amortization		9,378			5,317			18,547			10,555

EBITDA (a)	$	21,527		$	16,876		$	32,378		$	10,248
Unrealized loss (gain) from risk management activities		(1,568	)		(5,005	)		(2,621	)		13,039
Non-cash put option expiration		888			453			1,692			711
Acquisition expenses		684			—			684			—
Management services termination fee		—			—			9,000			—
Management fee		135			253			272			507

Adjusted EBITDA	$	21,666		$	12,577		$	41,405		$	24,505


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)	Sept. 30, 2006


Net cash flows provided by operating activities	$	8,274
Add (deduct):
Depreciation and amortization		(8,994	)
Loss on debt refinancing		(12,447	)
Risk management portfolio value changes		705
Equity income		177
Unit based compensation expenses		(863	)
Accounts receivable		14,881
Other current assets		221
Accounts payable and accrued liabilities		(8,444	)
Accrued taxes payable		(383	)
Other current liabilities		(4,653	)
Other assets		254

Net Loss	$	(11,272	)

Add:
Interest expense, net		10,929
Depreciation and amortization		9,759

EBITDA	$	9,416

Add (deduct):
Unrealized gain from risk management activities		(1,725	)
Non-cash put option expiration		960
Acquisition expenses		1,201
Loss on debt refinancing		12,447
Management services termination fee		3,542
Management fee		88

Adjusted EBITDA	$	25,929

Add (deduct):
Unit based compensation expenses		863
Cash interest expense (1)		(9,566	)
Maintenance capital expenditures (1)		(1,955	)
Adjustment to EBITDA for TexStar results prior to August 15th		(2,580	)

Cash available for distribution	$	12,691


(1)		Excludes amounts paid by TexStar prior to August 15th

Non-GAAP Adjusted Segment Margin to GAAP Net Loss


	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
($ in thousands)	2006			2005			2006			2005


Net loss		($11,272	)		($3,906	)		($13,831	)		($12,440	)
Add:
Related party expenses		499			217			1,765			349
Operating expenses		10,567			5,619			28,394			16,408
General and administrative		6,932			3,672			19,271			9,822
Management services termination fee		3,542			—			12,542			—
Depreciation and amortization		9,759			5,521			28,306			16,076
Interest expense, net		10,929			4,490			27,319			12,717
Loss on debt refinancing		12,447			7,724			12,447			7,724
Equity income		(177	)		(91	)		(397	)		(246	)
Other income and deductions, net		60			(221	)		(103	)		(284	)
Discontinued operations		—			15			—			(732	)

Total Segment Margin	$	43,286			$23,040			$115,713			$49,394
Unrealized loss (gain) from risk management activities		(1,725	)		(327	)		(4,346	)		12,712
Non-cash put option expiration		960			582			2,652			1,293

Adjusted Total Segment Margin	$	42,521			$23,295			$114,019			$63,399
Transportation Segment Margin		($12,093	)		($4,141	)		($32,697	)		($9,768	)

Adjusted Segment Margin for Gathering and Processing	$	30,428			$19,154			$81,322			$53,631