Resources Connection 8K Changes in Control of Registrant | SEC 14 Nov 06

Exhibit 99.6 – Interim Management’s Discussion and Analysis

Overview

We are a Delaware limited partnership formed to capitalize on opportunities in the midstream sector of the natural gas industry. We are committed to providing high quality services to our customers and to delivering sustainable returns to our investors in the form of distributions and unit price appreciation.

We own and operate significant natural gas gathering and processing assets in north Louisiana, east Texas, south Texas, west Texas and the mid-continent region of the United States. We are engaged in gathering, processing, marketing and transporting natural gas and natural gas liquids, or NGLs. We also own and operate an intrastate natural gas pipeline in north Louisiana.

On February 3, 2006, we offered and sold 13,750,000 common units, representing a 35.3 percent limited partner interest in the Partnership, in our initial public offering at a price of $20.00 per unit. Total proceeds from the sale of the units were $275,000,000, before offering costs and underwriting commissions. Our common units began trading on the NASDAQ National Market under the symbol “RGNC.” See our annual report on Form 10-K for additional information on our initial public offering and the underwriters’ partial execution of their over allotment option.

On July 12, 2006, the Partnership entered into a definitive contribution agreement to acquire TexStar Field Services, L.P. and TexStar GP, LLC for $350,000,000, subject to working capital adjustments. See Note 11, Subsequent Events, for further discussion.

On August 15, 2006, the Partnership, through its wholly-owned subsidiary Regency Gas Services LP (“Regency Gas Services”), acquired all the outstanding equity (the “Acquisition”) of TexStar Field Services, L.P. and its general partner, TexStar GP, LLC (together, “TexStar”), from HMTF Gas Partners II, L.P. (“HMTF Gas Partners”), an affiliate of HM Capital Partners LLC (“HM Capital Partners”) for $350,000,000, subject to working capital adjustments.. The Acquisition was completed in accordance with the Contribution Agreement, dated July 12, 2006 (the “Contribution Agreement”), among the Partnership, Regency Gas Services and HMTF Gas Partners. Because the TexStar Acquisition is a transaction between commonly controlled entities, the Partnership accounted for the TexStar Acquisition in a manner similar to a pooling of interests. As a result, the historical financial statements of the Partnership and TexStar have been combined to reflect the historical operations, financial position and cash flows throughout the periods presented.

We manage our business and analyze and report our results of operations through two business segments:

•		Gathering and Processing, in which we provide “wellhead to market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate the NGLs and selling or delivering the pipeline-quality natural gas and NGLs to various markets and pipeline systems; and

•		Transportation, in which we deliver pipeline quality natural gas from northwest Louisiana to northeast Louisiana through our 320-mile Regency Intrastate Pipeline system, which has been significantly expanded and extended through our Regency Intrastate Enhancement Project. Our Transportation Segment includes certain marketing activities related to our transportation pipelines that are conducted by a separate subsidiary.

Our management uses a variety of financial and operational measurements to analyze our performance. We review these measures on a monthly basis for consistency and trend analysis. These measures include volumes, total segment margin and operating expenses on a segment basis.

Volumes.As a result of naturally occurring production declines, we must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our gathering and processing systems. Our ability to maintain existing supplies of natural gas and obtain new supplies is impacted by (1) the level of workovers or recompletions of existing connected wells

and successful drilling activity in areas currently dedicated to our pipelines, (2) our ability to compete for volumes from successful new wells in other areas and (3) our ability to obtain natural gas that has been released from other commitments. We routinely monitor producer activity in the areas served by our gathering and processing systems to pursue new supply opportunities.

To increase throughput volumes on our intrastate pipeline we must contract with shippers, including producers and marketers, for supplies of natural gas. We routinely monitor producer and marketing activities in the areas served by our transportation system to pursue new supply opportunities.

Total Segment Margin. Segment margin from Gathering and Processing, together with segment margin from Transportation comprise Total Segment Margin. We use Total Segment Margin as a measure of performance.

We calculate our Gathering and Processing segment margin as our revenue generated from our gathering and processing operations minus the cost of natural gas and NGLs purchased and other cost of sales, which also include third-party transportation and processing fees. Revenue includes revenue from the sale of natural gas and NGLs resulting from these activities and fixed fees associated with the gathering and processing natural gas.

We calculate our Transportation segment margin as revenue generated by fee income as well as, in those instances in which we purchase and sell gas for our account, gas sales revenue minus the cost of natural gas that we purchase and transport. Revenue primarily includes fees for the transportation of pipeline-quality natural gas and sales of natural gas transported for our account. Most of our segment margin is fee-based with little or no commodity price risk. In those cases in which we purchase and sell gas for our account, we generally purchase pipeline-quality natural gas at a pipeline inlet price adjusted to reflect our transportation fee and we sell that gas at the pipeline outlet. In those cases, the difference between the purchase price and the sale price customarily exceeds the economic equivalent of our transportation fee.

The following table reconciles the non-GAAP financial measure, total segment margin, to its most directly comparable GAAP measure, net income (loss).


	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
	(in thousands)
Net income (loss)	$	3,760		$	6,528		$	(2,559	)	$	(8,534	)
Add (deduct):
Operating expenses		8,382			5,907			17,827			10,789
General and administrative		6,923			3,764			12,339			6,150
Related party expenses		753			112			1,266			132
Management services termination fee		—			—			9,000			—
Depreciation and amortization		9,378			5,317			18,547			10,555
Interest expense, net		8,389			5,031			16,390			8,227
Equity income		(130	)		(82	)		(220	)		(156	)
Other income and deductions, net		(71	)		(52	)		(163	)		(62	)
Discontinued operations		—			(694	)		—			(747	)

Total segment margin (1)	$	37,384		$	25,831		$	72,427		$	26,354


(1)		The three and six month periods ended June 30, 2005 include approximately $5,005,000 and ($13,039,000) of unrealized gains (losses) on commodity hedging transactions.

Operating Expenses.Operating expenses are a separate measure that we use to evaluate operating performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operating expenses. These expenses are largely independent of the volumes through our systems but fluctuate depending on the activities performed during a specific period. We do not deduct operating expenses from total revenues in calculating segment margin because we separately evaluate commodity volume and price changes in segment margin.

EBITDA.We define EBITDA as net income plus interest expense, provision for income taxes and depreciation and amortization expense. EBITDA is used as a supplemental 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 sector, without regard to financing or capital structure; and

	§		the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. EBITDA is the starting point in determining cash available for distribution, which is an important non-GAAP financial measure for a publicly traded master limited partnership.

The following table reconciles the non-GAAP financial measure, EBITDA, to its most directly comparable GAAP measures, net income (loss) and net cash flows provided by operating activities.


	Six Months Ended June 30,
	2006			2005
	(in thousands)
Net cash flows provided by operating activities	$	24,728		$	13,746
Add (deduct):
Depreciation and amortization		(18,975	)		(11,232	)
Equity earnings of investees		220			156
Risk management portfolio value changes		811			(13,337	)
Unit based compensation expenses		(1,089	)		—
Gain on the sale of Regency Gas Treating LP assets		—			626
Accounts receivable		(13,973	)		(4,119	)
Related party receivable		203			460
Other current assets		(109	)		506
Accounts payable and accrued liabilities		11,363			3,429
Related party payable		380			397
Accrued taxes payable		(921	)		(287	)
Other current liabilities		735			574
Proceeds from early termination of interest rate swap		(3,550	)		—
Other assets		(2,382	)		547

Net loss	$	(2,559	)	$	(8,534	)
Add:
Interest expense, net		16,390			8,227
Depreciation and amortization		18,547			10,555

EBITDA (1)	$	32,378		$	10,248


(1)		The six month period ended June 30, 2005 includes approximately $13,453,000 of unrealized losses on hedging transactions.

Cash Distributions

On May 15, 2006 the Partnership paid a distribution of $0.2217 per common and subordinated unit. The distribution constitutes the minimum quarterly distribution of $0.35 per unit (or $1.40 per unit annually), prorated for the period in the first quarter of 2006 since the Partnership’s February 3, 2006 initial public offering.

On August 14, 2006, the Partnership paid a distribution of $0.35 per common and subordinated unit. The distribution constitutes the minimum quarterly distribution of $0.35 per unit.

Recent Developments

On August 15, 2006, the Partnership, through its wholly-owned subsidiary Regency Gas Services, acquired TexStar, an affiliate of HM Capital Partners for $350,000,000, subject to working capital adjustments. See Note 11 for additional information regarding this acquisition.

Results of Operations

The results of operations for the three and six months ended June 30, 2006 were significantly affected by the following matters, which are discussed in more detail under the captions below:

	§		The volume and segment margin delivered by our transportation segment in the three months ended March 31, 2006 was adversely affected by delayed pipeline interconnections and pipeline pressure issues on the part of certain customers and downstream markets. All interconnection issues were resolved during the first quarter. Beginning in May 2006, we were able to manage the pressure issues so that their impact on operations was mitigated, and we have begun implementing plans that will effectively resolve the pipeline pressure issues and ultimately expand the design capacity of the pipeline to 910,000 Mcf/d by the fourth quarter of 2006.

	§		In the three months ended March 31, 2006, we recorded a one-time charge of $9,000,000 as a termination fee in connection with the termination of two long-term management services contracts, which amount was paid out of the proceeds of our IPO.

The following are matters that may affect our future results of operations:

	§		Transportation segment volumes and segment margin increased significantly as the third phase of the Regency Intrastate Enhancement Project completed its first six months of operation. Through August 1, 2006, we have signed definitive agreements for 556,800 MMBtu/d of firm transportation on the Regency Intrastate Pipeline system, of which 444,647 MMBtu/d was utilized in July 2006. During the month of July 2006 we provided 90,894 MMBtu/d of interruptible transportation.

	§		Because our hedging program locks in more favorable pricing in 2006 as compared to 2005, we expect to earn higher gathering and processing segment margins.

	§		We have identified $92,000,000 of organic growth projects, most of which we expect to be operational in 2006 or early 2007. Projects approved by our Board of Directors totaled $74,000,000 and TexStar aproved $18,000,000 prior to our TexStar Acquisition.

	§		As previously disclosed, a gathering contract with one of our suppliers representing over 10 percent of the volume in west Texas will expire in August 2006 and will not be renewed. The Partnership compared the book value of our west Texas assets to expected future cash flows and recorded no impairment.

	§		TexStar acquired two sulfur recovery plants, one NGL plant and 758 miles of pipelines in East and South Texas from Enbridge $108,282,000 inclusive of transaction expenses on December 7, 2005.

	§		On August 15, 2006, we acquired all the outstanding equity TexStar for $350,000,000, subject to working capital adjustments.

	§		On July 25, 2006, TexStar consummated the Como Acquisition Agreement dated June 16, 2006 with Valence Midstream, Ltd. and EEC Midstream, Ltd., under which TexStar acquired certain natural gas gathering, treating and processing assets from the other parties thereto for $81,807,000 including transaction costs.

Three Months Ended June 30, 2006 vs. Three Months Ended June 30, 2005

The following table contains key company-wide performance indicators related to our discussion of the results of operations.


	Three Months Ended
	June 30,
	2006			2005			Change			% Change
	(in thousands except volume data)
Revenues (a)	$	214,658		$	137,945		$	76,713			56	%
Cost of gas and liquids		177,274			112,114			(65,160	)		(58	)

Total segment margin		37,384			25,831			11,553			45

Operating expenses		8,382			5,907			(2,475	)		(42	)
General and administrative		6,923			3,764			(3,159	)		(84	)
Related party expenses		753			112			(641	)		(572	)
Depreciation and amortization		9,378			5,317			(4,061	)		(76	)


Operating income		11,948			10,731			1,217			11

Interest expense, net		(8,389	)		(5,031	)		(3,358	)		(67	)
Equity income		130			82			48			59
Other income and deductions, net		71			52			19			37


Net income from continuing operations		3,760			5,834			(2,074	)		(36	)

Discontinued operations		—			694			(694	)		n/m


Net income	$	3,760		$	6,528		$	(2,768	)		(42	)%


System inlet volumes (MMbtu/d) (b)		980,444			539,631			440,813			82	%


(a)		The three month period ended June 30, 2005 includes $5,005,000 of unrealized gains on commodity hedging transaction.

(b)		System inlet volumes include total volumes taken into our gathering and processing and transportation systems.

n/m	=	not meaningful

Net Income— Net income for the three months ended June 30, 2006 decreased $2,768,000 compared with the three months ended June 30, 2005. Total segment margin increased $11,553,000 due to increased segment margin in the gathering and processing and transportation segment of $4,363,000 and $7,190,000. The gathering and processing segment margin includes a decrease in net unrealized gains of $3,873,000 from risk management activities related to mark-to-market accounting. The increase in transportation segment margin is attributable to the completion of our Regency Intrastate Enhancement Project at the end of 2005. The remaining price and volume variances in total segment margin and segment margin are discussed below.

The table below contains key segment performance indicators related to our discussion of the results of operations.


	Three Months Ended
	June 30,
	2006		2005		Change			Percent
	(in thousands except volume data)
Segment Financial and Operating Data:
Gathering and Processing Segment
Financial data:
Segment margin	$	26,667	$	22,304	$	4,363			20	%
Operating expenses		7,280		5,458		(1,822	)		(33	)
Operating data:
Throughput (MMbtu/d)(1)		496,238		306,360		189,878			62
NGL gross production (Bbls/d)		16,972		15,615		1,357			9

Transportation Segment
Financial data:
Segment margin	$	10,717	$	3,527	$	7,190			204	%
Operating expenses		1,102		449		(653	)		(145	)
Operating data:
Throughput (MMbtu/d)(2)		577,217		245,309		331,908			135


(1)		New well connections in west Texas over the last twelve months have not fully offset natural declines in production. The net throughput loss, however, has been largely concentrated in low margin contracts, and has been partially offset by net gains in production in the north Louisiana region.

(2)		Excludes unused fixed transportation of 91,427 MMbtu/d in 2006.

Segment Margin— Total segment margin for the three months ended June 30, 2006 increased to $37,384,000 from $25,831,000 for the corresponding period in 2005. Gathering and processing segment margin increased $4,363,000 primarily related to our TexStar Acquisition. Transportation segment margin increased $7,190,000 primarily attributable to the Regency Intrastate Enhancement Project.

Gathering and processing segment margin for the three months ended June 30, 2006 decreased to $26,667,000 from $22,304,000 for the three months ended June 30, 2005. The elements of this decrease are as follows:

	§		a decrease of $3,873,000 attributable to non-cash gains in the fair market value of derivative contracts;

	§		an increase of $1,889,000 in segment margin attributable to increased hedged gross margins resulting from more favorable pricing of executed hedges;

	§		an increase of $1,576,000 in segment margin that is attributable to higher average margins on processed volumes;

	§		an increase of $204,000 resulting from additional marketing activities surrounding NGL production;

	§		an increase of $5,397,000 from our TexStar Acquisition; and

	§		a decrease of $830,000 attributable to reduced throughput volumes.

Transportation segment margin for the three months ended June 30, 2006 increased to $10,717,000 from $3,527,000 for the three months ended June 30, 2005, a 204 percent increase. The elements of this increase are as follows:

	§		an increase of $4,809,000 attributable to increased throughput volumes;

	§		an increase of $1,131,000 resulting from an average of 91,427 MMBtu/d of unused incremental firm transportation contracted by several shippers;

	§		an increase of $697,000 resulting from increased marketing activities around the expanded system; and

	§		an increase of $553,000 resulting from lower average transportation fees.

General and Administrative— General and administrative expense increased to $6,923,000 in the three months ended June 30, 2006 from $3,764,000 for the comparable period in 2005, an 84 percent increase. This increase was primarily

attributable to (i) the accrual of non-cash expense associated with our new long-term incentive plan of $775,000 in the three months ended June 30, 2006; (ii) higher salary expenses of $693,000, associated with hiring key personnel to assist in achieving our strategic objectives; (iii) $135,000 in payments made to HMTF Gas Partners; (iv) and acquisition related expenditures of $684,000 in the three months ended June 30, 2006 related to the acquisition of TexStar. The increases in general and administrative expenses are consistent with the level that we had anticipated as a result of becoming a publicly traded entity.

Depreciation and Amortization— Depreciation and amortization increased to $9,378,000 in the three months ended June 30, 2006 from $5,317,000 for the corresponding period in 2005, representing a 76 percent increase. Depreciation expense increased $3,690,000 primarily due to the higher depreciable basis of our transportation system with the completion of our Regency Intrastate Enhancement Project at the end of 2005 and our TexStar Acquisition.

Interest Expense, Net— Interest expense, net increased $3,358,000, or 67 percent, in the three months ended June 30, 2006 compared to the three months ended June 30, 2005. Of the increase, $3,770,000 is due to higher levels of borrowings primarily associated with growth capital expenditures, primarily offset by $563,000 of unrealized hedging gains recorded as a reduction to interest expenses for the three month period ended June 30, 2005.

Discontinued Operations— On May 2, 2005, we sold all of the Cardinal assets, together with certain related assets, for $6,000,000. The results of Cardinal are presented as discontinued operations, and we recorded a gain on the sale of $626,000 in the three months ended June 30, 2005.

Six Months Ended June 30, 2006 vs. Six Months Ended June 30, 2005

The following table contains key company-wide performance indicators related to our discussion of the results of operations.


	Six Months Ended
	June 30,
	2006			2005			Change			% Change
	(in thousands except volume data)
Revenues (a)	$	445,924		$	244,894		$	201,030			82	%
Cost of gas and liquids		373,497			218,540			(154,957	)		(71	)

Total segment margin		72,427			26,354			46,073			175

Operating expenses		17,827			10,789			(7,038	)		(65	)
General and administrative		12,339			6,150			(6,189	)		(101	)
Related party expenses		1,266			132			(1,134	)		(859	)
Management services termination fee (b)		9,000			—			(9,000	)		n/m
Depreciation and amortization		18,547			10,555			(7,992	)		(76	)


Operating income (loss)		13,448			(1,272	)		14,720			n/m

Interest expense, net		(16,390	)		(8,227	)		(8,163	)		(99	)
Equity income		220			156			64			41
Other income and deductions, net		163			62			101			163


Net loss from continuing operations		(2,559	)		(9,281	)		6,722			72

Discontinued operations		—			747			(747	)		n/m


Net loss	$	(2,559	)	$	(8,534	)	$	5,975			70	%


System inlet volumes (MMbtu/d) (c)		916,218			504,986			411,232			81	%


(a)		The six month period ended June 30, 2005 includes $13,039,000 of unrealized losses on commodity hedging transactions.

(b)		The management services termination fee was paid with proceeds from our IPO.

(c)		System inlet volumes include total volumes taken into our gathering and processing and transportation systems.

n/m	=	not meaningful

Net Loss— Net loss for the six months ended June 30, 2006 decreased $5,975,000 compared with the six months ended June 30, 2005. Total segment margin increased $46,073,000 or 175 percent. The segment margin for the six months ended June 30, 2005 includes an unrealized loss of $13,039,000 from risk management activities related to mark-to-market accounting. Including the $13,039,000 unrealized loss, gathering and processing segment margin increased $31,431,000 and transportation segment margin increased $14,642,000. The increase in transportation segment margin is attributable to the completion of our Regency Intrastate Enhancement Project at the end of 2005. The remaining price and volume variances in total segment margin and segment margin are discussed below.

Earnings for the six months ended June 30, 2006 were adversely affected by a one-time $9,000,000 charge incurred as a termination fee in connection with the termination of two long-term management services contracts. The contracts were terminated in connection with our IPO and the payment of this charge was made out of the proceeds from the IPO.

The table below contains key segment performance indicators related to our discussion of the results of operations.


	Six Months Ended
	June 30,
	2006		2005		Change			Percent
	(in thousands except volume data)
Segment Financial and Operating Data:
Gathering and Processing Segment
Financial data:
Segment Margin	$	51,822	$	20,391	$	31,431			154	%
Operating expenses		15,578		10,042		(5,536	)		(55	)
Operating data:
Throughput (MMbtu/d)(1)		460,116		308,755		151,361			49
NGL gross production (Bbls/d)		17,224		15,833		1,391			9

Transportation Segment
Financial data:
Segment Margin	$	20,605	$	5,963	$	14,642			246	%
Operating expenses		2,249		747		(1,502	)		(201	)
Operating data:
Throughput (MMbtu/d)(2)		508,190		209,675		298,515			142


(1)		New well connections in west Texas over the last twelve months have not fully offset natural declines in production. The net throughput loss, however, has been largely concentrated in low margin contracts, and has been partially offset by net gains in production in the north Louisiana region.

(2)		Excludes unused fixed transportation of 81,000 MMbtu/d in 2006.

Segment Margin— Total segment margin for the six months ended June 30, 2006 increased to $72,427,000 from $26,354,000 for the corresponding period in 2005. The $46,073,000 increase in total segment margin includes a $13,039,000 unrealized loss from risk management activities related to mark-to-market accounting in 2005. For further information, please see “— Critical Accounting Policies – Risk Management Activities.”

Gathering and processing segment margin for the six months ended June 30, 2006 increased to $51,822,000 from $20,391,000 for the six months ended June 30, 2005. The elements of this increase are as follows:

	§		an increase of $14,680,000 attributable to a reduction in non-cash losses in the fair market value of derivative contracts;

	§		an increase of $12,806,000 related to margin contributed by our TexStar Acquisition;

	§		an increase of $3,756,000 in segment margin attributable to increased hedged gross margins resulting from more favorable pricing of executed hedges;

	§		an increase of $1,576,000 in segment margin that is attributable to higher average margins on processed volumes;

	§		an increase of $204,000 resulting from additional marketing activities surrounding NGL production; and

	§		a decrease of $1,429,000 in segment margin attributable to reduced throughput volumes.

Transportation segment margin for the six months ended June 30, 2006 increased to $20,605,000 from $5,963,000 for the comparable period in 2005, a 246 percent increase. The elements of this increase are as follows:

	§		an increase of $8,461,000 attributable to increased throughput volumes;

	§		an increase of $2,797,000 resulting from increased marketing activities around the expanded system;

	§		an increase of $2,035,000 resulting from an average of 81,000 MMBtu/d of unused incremental firm transportation contracted by several shippers; and

	§		an increase of $1,451,000 resulting from higher average transportation fees.

During the first quarter of 2006, one of our firm transport customers did not use all of the transportation capacity to which it was entitled due to pressure losses on their gathering system. In the second quarter of 2006, these pressure issues were alleviated by the seasonal demand for electricity. For a long-term solution, the customer has informed us of their intent to add compression in the third and fourth quarters of 2006 so that they can transport more gas on our pipeline. Compounding the first quarter 2006 problem was an interstate pipeline’s loss of two compressor turbines causing the pressure at our interconnect to exceed historical parameters significantly. The operators of the interstate pipeline have informed us that they expect the compressor turbines to return to service in the latter part of the fourth quarter of 2006. The addition of compression by our customer, together with the reconfiguration of their gathering system will allow them to deliver gas into our pipeline even if the interstate pipeline operates at their maximum allowable operating pressure.

To the extent that inlet pressure at the south westernmost point on the Gulf States Transmission Corporation (“GSTC”) pipeline exceeds a certain pressure that is determined by a competitor, the competitor can divert gas into its own system. In turn, this reduces the volume of gas coming into our north Louisiana intrastate pipeline. We have signed firm transportation contracts on GSTC with some of the gas producers whose deliveries of gas into GSTC are affected by our competitor. We plan to reduce significantly the relevant inlet pressure by installing additional pipeline looping on our pipeline and by adding compression. The additional pipeline looping went into service in early August 2006 and the compression is scheduled for installation in the fourth quarter of 2006.

Operating Expenses— Operating expenses for the six months ended June 30, 2006 increased to $17,827,000 from $10,789,000 for the corresponding period in 2005, representing a 65 percent increase. The primary reason for the increase is the additional operating expense of $5,851,000 related to our TexStar Acquisition. This increase also resulted in part from an increase in non-income taxes of $1,034,000, mainly associated with property taxes on our Regency Intrastate Enhancement Project in our transportation segment. The remaining $153,000 is attributable to employee expenses, utilities for gathering and processing, overtime related to maintenance events in the north Louisiana region, and higher employee related costs partially offset by lower contractor expenses.

General and Administrative— General and administrative expense increased to $12,339,000 in the six months ended June 30, 2006 from $6,150,000 for the comparable period in 2005. This increase was primarily attributable to higher employee-related expenses of $2,111,000, including higher salary expense associated with hiring key personnel to assist in achieving our strategic objectives. This increase is also attributable to the additional general and administrative of $1,614,000 related to the TexStar Acquisition. Also contributing to the increase was the accrual of non-cash expense associated with our new long-term incentive plan of $1,089,000 in the six months ended June 30, 2006. Further contributing to the increase were increased professional and consulting expenses of $434,000, consisting primarily of audit fees and consulting fees for Sarbanes-Oxley compliance support. The six month period ended June 30, 2006 includes acquisition expenditures of $684,000 related to the TexStar acquisition. Other general and administrative expenses increased $351,000 primarily due to outside directors fees and expenses in the six months ended June 30, 2006 that were not present in the six months ended June 30, 2005. Rent expense increased $117,000 due to the leasing of additional office space in the second half of 2005. Insurance expense increased $115,000 due to higher costs associated with directors’ and officers’ insurance.

The increases in operating expenses and general and administrative expenses are consistent with the level that we had anticipated as a result of becoming a publicly traded entity.

Depreciation and Amortization— Depreciation and amortization increased to $18,547,000 in the six months ended June 30, 2006 from $10,555,000 for the corresponding period in 2005, representing a 76 percent increase. Depreciation expense increased $7,992,000 primarily due to the higher depreciable basis of our transportation system with the completion of our Regency Intrastate Enhancement Project at the end of 2005 and our TexStar Acquisition.

Interest Expense, Net— Interest expense, net increased $8,163,000, or 99 percent, in the six months ended June 30, 2006 compared to the six months ended June 30, 2005. Of the increase, $7,226,000 is due to higher levels of borrowings primarily associated with our Regency Intrastate Enhancement Project and growth capital expenditures, $405,000 is due to higher interest rates and $414,000 is attributable to an unrealized gain recorded in the prior period when we used mark-to-market accounting for interest rate swaps.

Critical Accounting Policies

Conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be different from those estimates. We believe that the following are the more critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations.

Revenue and Cost of Sales Recognition. We record revenue and cost of sales on the gross basis for those transactions where we act as the principal and take title to gas that we purchase for resale. When our customers pay us a fee for providing a service such as gathering or transportation we record the fees separately in revenues. In March 2006, the Partnership implemented a process for estimating certain revenue and expenses as actual amounts are not confirmed until after the financial closing process due to the standard settlement dates in the gas industry. Estimated revenues are calculated using actual pricing and nominated volumes. In the subsequent production month, we reverse the accrual and record the actual results. Prior to the settlement date, we record actual operating data to the extent available, such as actual operating and maintenance and other expenses. We do not expect actual results to differ materially from our estimates.

Risk Management Activities.In order to protect ourselves from commodity and interest rate risk, we pursue hedging activities to minimize those risks. These hedging activities rely upon forecasts of our expected operations and financial structure over the next four years. If our operations or financial structure are significantly different from these forecasts, we could be subject to adverse financial results as a result of these hedging activities. We mitigate this potential exposure by retaining an operational cushion between our forecasted transactions and the level of hedging activity executed. We monitor and review hedging positions regularly.

From the inception of our hedging program in December 2004 through June 30, 2005, we used mark-to-market accounting for our commodity and interest rate swaps as well as for crude oil puts. We recorded realized gains and losses on hedge instruments monthly based upon the cash settlements and the expiration of option premiums. The settlement amounts varied due to the volatility in the commodity market prices throughout each month.

Effective July 1, 2005, we elected hedge accounting under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended and determined the then current hedges outstanding, excluding crude oil put options, qualified for hedge accounting whereby the unrealized changes in fair value are recorded in other comprehensive income (loss) to the extent the hedge is effective. Prior to July 1, 2005, we had recorded unrealized losses in the fair market value of commodity-related derivative contracts and unrealized gains on an interest rate swap into revenues and interest expense, net respectively.

Equity Based Compensation. On December 12, 2005, the compensation committee of the board of directors of Regency GP LLC approved a long-term incentive plan (“LTIP”) for the Partnership’s employees, directors and consultants covering an aggregate of 2,865,584 common units. Awards under the LTIP have been made since the completion of the Partnership’s IPO. LTIP awards generally vest on the basis of one-third of the award each year. The options have a maximum contractual term, expiring ten years after the grant date.

As of June 30, 2006, grants have been made in the amount of 432,500 restricted common units and 749,800 common unit options with weighted average grant-date fair values of $20.46 per unit and $1.20 per option. The options were valued with the Black-Scholes Option Pricing Model assuming 15 percent volatility in the unit price, a ten year term, a strike price equal to the grant-date price per unit, a distribution per unit of $1.40 per year, a risk-free rate of 4.25 percent, and an average

exercise of the options of four years after vesting is complete. The assumption that option exercises, on average, will be four years from the vesting date is based on the average of the mid-points from vesting to expiration of the options. In aggregate, outstanding awards represent 1,164,000 potential common units.

The Partnership will make distributions to non-vested restricted common units on a one-for-one ratio with the per unit distributions paid to common units. Restricted common units are subject to contractual restrictions which lapse over time. Upon the vesting and exercise of the common unit options, the Partnership intends to settle these obligations with common units. Accordingly, the Partnership expects to recognize an aggregate of $9,243,000 of compensation expense related to the grants under LTIP, or $3,081,000 for each of the three years of the vesting period for such grants. We adopted SFAS 123(R) “Share-Based Payment” in the first quarter of 2006 which resulted in no change in accounting principles as no LTIP awards were outstanding during 2005.

Other Matters

El Paso Claims— Under the purchase and sale agreement, or PSA, pursuant to which we purchased our north Louisiana and Midcontinent assets from affiliates of El Paso Field Services, LP, or El Paso, in 2003, El Paso indemnified us (subject to a limit of $84,000,000) for environmental losses as to which El Paso was deemed responsible. Of the cash escrowed for this purpose at the time of sale, $5,654,000 remained in escrow at June 30, 2006. Upon completion of a Phase II investigation of various assets so acquired (the Phase II Assets), we notified El Paso of indemnity claims of approximately $5,400,000 for environmental liabilities. In related discussions, El Paso denied all but $280,000 of these claims (which it evaluated at $75,000 and agreed to cure itself). In these discussions, we agreed, at El Paso’s request, to install permanent monitoring wells at the facilities where ground water impacts were indicated by the Phase II activities. We also agreed to withdraw our claims with respect to all but seven of the Phase II Assets (which comprise those subject to accepted claims).

A Final Site Investigations Report with respect to those Phase II Assets has since been prepared and issued based on information obtained from the permanent monitoring wells. Environmental issues exist with respect to four facilities, including the two subject to accepted claims and two of the Partnership’s processing plants. The estimated remediation costs associated with the processing plants aggregate $2,750,000. The Partnership believes that any of its obligations to remediate the properties is subject to the indemnity under the El Paso PSA, and intends to reinstate the claims for indemnification for these plant sites.

Texas Tax Legislation— In the three months ended June 30, 2006, the State of Texas passed legislation that imposes a “margin tax” on partnerships and master limited partnerships. We currently estimate that the effect of this legislation will not have a material effect on our results of operations, cash flows, or financial condition.

Liquidity and Capital Resources

Working Capital (Deficit).— Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. During periods of growth capital expenditures, we experience working capital deficits when we fund construction expenditures out of working capital until they are permanently financed. Our working capital is also influenced by current risk management assets and liabilities due to fair market value changes in our derivative positions being reflected on our balance sheet. These represent our expectations for the settlement of risk management rights and obligations over the next twelve months, and so must be viewed differently from trade receivables and payables which settle over a much shorter span of time. These factors affect working capital but not our ability to pay bills as they come due.

Our working capital deficit was $23,280,000 at June 30, 2006 and $33,572,000 at December 31, 2005. The $10,292,000 net decrease from December 31, 2005 to June 30, 2006 resulted primarily from:

a decrease in accounts payable of $23,082,000 resulting primarily from lower levels on construction-related payables of $12,075,00 and the timing of bill payments and

	§		a $2,837,000 increase in cash and cash equivalents primarily driven by a $3,550,000 cash inflow from the early termination of an interest rate swap in June 2006; partially offset by

	§		a decrease in accounts receivable of $13,577,000 primarily due to the timing of receipt collections and

	§		a $2,814,000 increase in the net current liability valuation of our risk management contracts due to higher index NGL prices and the early termination of an interest rate swap.

Cash Flows from Operations— Net cash flows provided by operating activities increased $10,982,000, or 80 percent, in the six months ended June 30, 2006 compared to the corresponding period in 2005. The increase was primarily the result of increased segment margin related to the completion of our Regency Intrastate Enhancement project of $14,642,000 and our TexStar Acquisition of $12,806,000. Also contributing to the increase in cash flows from operations was $3,550,000 cash received from the early termination of an interest rate swap. Partially offsetting these increases were the payment of $9,000,000 to an affiliate of HM Capital Partners to terminate two management services contracts and the payment of additional interest expense of $7,990,000 primarily due to increased levels of borrowing related to our Regency Intrastate Enhancement Project.

Cash Flows Used in Investing Activities— Net cash flows used in investing activities increased $33,584,000, or 122 percent, in the six months ended June 30, 2006 compared to the six months ended June 30, 2005. The increase is primarily due to higher levels of capital expenditures related to the completion of our Regency Intrastate Enhancement Project and growth and maintenance capital expenditures.

Cash Flows Provided by Financing Activities— Net cash flows provided by financing activities increased $16,445,000 or 73 percent, in the six months ended June 30, 2006 compared to the corresponding period in 2005. The increase is due to working capital and growth capital expenditures financed with additional borrowings under our credit facility and net proceeds related to our initial public offering, offset by partner distributions.

Capital Requirements

Growth Capital Expenditures. In the six months ended June 30, 2006, we incurred $32,329,000 of growth capital expenditures. Growth capital expenditures for the six months ended June 30, 2006 primarily relate to the completion of our Regency Intrastate Enhancement Project, a new 200 MMcf/d dewpoint control facility in Bossier Parish, Louisiana, additional gas compressors, approximately 16 miles of 24-inch pipeline and related compression associated with a scheduled loop of a western segment of our intrastate pipeline and approximately 6 miles of 12-inch pipeline in Lincoln Parish, Louisiana.

We have identified $92,000,000 for organic growth capital expenditures, including $32,329,000 already spent. This compares to our estimate of $25,100,000 disclosed in our Annual Report on Form 10-K for the year ended December 31, 2005. Substantially all of the increased balance relates to new projects recently approved by our Board of Directors. These expenditures are for:

	§		approximately 16 miles of 24-inch pipeline and related compression associated with a scheduled loop of a western segment of our intrastate pipeline;

	§		a new 200 MMcf/d dewpoint control facility scheduled for installation on our intrastate pipeline in Webster Parish, Louisiana;

	§		the expansion of existing compression and gathering capacity to accommodate producers in Lincoln Parish, Louisiana;

	§		the addition of standby compressor capacity; and

	§		approximately 26 miles of 12 inch pipeline in south Texas.

We expect these new growth projects to be operational during 2006. We expect to fund these growth capital expenditures out of borrowings under our existing credit agreement.

Maintenance Capital Expenditures— In the six months ended June 30, 2006, we incurred $12,051,000 of maintenance capital expenditures, approximately $6,939,000 of which was incurred by TexStar to refurbish the Eustace Plant prior to our acquisition. Maintenance capital expenditures primarily consist of compressor and plant overhauls, as well as new well connects to our gathering systems, which replace volumes from naturally occurring depletion of wells already connected.

Resources Connection Inactive 8-KChanges in Control of Registrant