Edgar Filing: Regency Energy Partners LP

regencyenergypartnerform10q.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2009

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________ to __________

Commission File Number: 000-51757

REGENCY ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

DELAWARE		16-1731691
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

2001 BRYAN STREET, SUITE 3700
DALLAS, TX		75201
(Address of principal executive offices)		(Zip Code)

(214) 750-1771

(Registrant’s telephone number, including area code)

NONE

(Former name, former address and former fiscal year, if changed since last report.)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þYes oNo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). oYes oNo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer, accelerated filer and small reporting company” in Rule 12b-2 of the Exchange Act.

þLarge accelerated filer oAccelerated filer oNon-accelerated filer (Do not check if a smaller reporting company) oSmaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). oYes þNo

The issuer had 81,116,978 common units outstanding as of October 31, 2009.

	Page
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements	3
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3. Quantitative and Qualitative Disclosures about Market Risk	43
Item 4. Controls and Procedures	44
PART II — OTHER INFORMATION	44
Item 1. Legal Proceedings	44
Item 1A. Risk Factors	44
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 6. Exhibits	44
Exhibit 10.1 Consulting agreement with Randall Dean
Exhibit 10.2 Employment agreement with David Marrs
Exhibit 10.3 Severance agreement with Paul Jolas
Exhibit 12.1 Computation of Ratio of Earnings to Fixed Charges
Exhibit 31.1 Rule 13a-14(a)/15d-14(a) Certification of CEO
Exhibit 31.2 Rule 13a-14(a)/15d-14(a) Certification of CFO
Exhibit 32.1 Section 1350 Certification of CEO
Exhibit 32.2 Section 1350 Certification of CFO

Introductory Statement

References in this report to the “Partnership,” “we,” “our,” “us” and similar terms, when used in a historical context, refer to Regency Energy Partners LP. When used in the present tense or prospectively, these terms refer to the Partnership and its subsidiaries. We use the following definitions in this quarterly report on Form 10-Q:

Name		Definition or Description
Alinda		Alinda Capital Partners LLC, a Delaware limited liability company that is an independent private investment firm specializing in infrastructure investments
Alinda Investor I		Alinda Gas Pipelines I, L.P., a Delaware limited partnership
Alinda Investor II		Alinda Gas Pipelines II, L.P., a Delaware limited partnership
Alinda Investors		Alinda Investor I and Alinda Investor II, collectively
Bbls/d		Barrels per day
Bcf		One billion cubic feet
Bcf/d		One billion cubic feet per day
BTU		A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit
CDM		CDM Resource Management LLC
EFS Haynesville		EFS Haynesville, LLC, a 100 percent owned subsidiary of GECC
El Paso		El Paso Field Services, LP
FASB		Financial Accounting Standards Board
FASB ASC		FASB Accounting Standards Codification
FASB ASU		FASB Accounting Standards Update
FERC		Federal Energy Regulatory Commission
Finance Corp.		Regency Energy Finance Corp., a wholly-owned subsidiary of the Partnership
FrontStreet		FrontStreet Hugoton LLC
GAAP		Accounting principles generally accepted in the United States
GE		General Electric Company
GE EFS		General Electric Energy Financial Services, a unit of GECC, combined with Regency GP Acquirer LP and Regency LP Acquirer LP
GECC		General Electric Capital Corporation, an indirect wholly owned subsidiary of GE
General Partner		Regency GP LP, the general partner of the Partnership, or Regency GP LLC, the general partner of Regency GP LP, which effectively manages the business and affairs of the Partnership through Regency Employees Management LLC
HPC		RIGS Haynesville Partnership Co., a general partnership that owns 100 percent of RIGS
IDRs		Incentive Distribution Rights
Lehman		Lehman Brothers Holdings, Inc.
LIBOR		London Interbank Offered Rate
LITP		Long-Term Incentive Plan
MMbtu		One million BTUs
MMbtu/d		One million BTUs per day
MMcf		One million cubic feet
MMcf/d		One million cubic feet per day
Nexus		Nexus Gas Holdings, LLC
NOE		Notice of Enforcement
NGLs		Natural gas liquids
Nasdaq		Nasdaq Stock Market, LLC
NYMEX		New York Mercantile Exchange
Partnership		Regency Energy Partners LP
Regency HIG		Regency Haynesville Intrastate Gas LLC, a wholly owned subsidiary of the Partnership
RFS		Regency Field Services LLC
RGS		Regency Gas Services LP
RIGS		Regency Intrastate Gas LP
SEC		Securities and Exchange Commission
Sonat		Southern Natural Gas Company
TCEQ		Texas Commission on Environmental Quality
Tcf		One trillion cubic feet
Tcf/d		One trillion cubic feet per day

Cautionary Statement about Forward-Looking Statements

Certain matters discussed in this report include “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may” or similar expressions help identify forward-looking statements. Although we believe our forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, we cannot give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions including without limitation the following:

·	volatility in the price of oil, natural gas, and natural gas liquids;
·	declines in the credit markets and the availability of credit for us as well as for producers connected to our system and our customers;
·	the level of creditworthiness of, and performance by, our counterparties and customers;
·	our access to capital to fund organic growth projects and acquisitions, and our ability to obtain debt or equity financing on satisfactory terms;
·	our 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 our transactions;
·	changes in commodity prices, interest rates, and demand for our services;
·	changes in laws and regulations impacting the midstream sector of the natural gas industry;
·	weather and other natural phenomena;
·	industry changes including the impact of consolidations and changes in competition;
·	our ability to obtain required approvals for construction or modernization of our facilities and the timing of production from such facilities; and
·	the effect of accounting pronouncements issued periodically by accounting standard setting boards.

If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may differ materially from those anticipated, estimated, projected or expected.

Other factors that could cause our actual results to differ from our projected results are discussed in Item 1A of our December 31, 2008 Annual Report on Form 10-K.

Each forward-looking statement speaks only as of the date of the particular statement and we undertake no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

Item 1. Financial Statements

Regency Energy Partners LP
Condensed Consolidated Balance Sheets
(unaudited)
(in thousands except unit data)
	September 30, 2009			December 31, 2008
ASSETS
Current Assets:
Cash and cash equivalents	$	12,100		$	599
Restricted cash		1,510			10,031
Trade accounts receivable, net of allowance of $1,668 and $941		25,531			40,875
Accrued revenues		65,370			96,712
Related party receivables		6,852			855
Derivative assets		33,750			73,993
Other current assets		7,381			13,338
Total current assets		152,494			236,403

Property, Plant and Equipment:
Gathering and transmission systems		462,900			652,267
Compression equipment		808,063			799,527
Gas plants and buildings		159,389			156,246
Other property, plant and equipment		156,866			167,256
Construction-in-progress		88,899			154,852
Total property, plant and equipment		1,676,117			1,930,148
Less accumulated depreciation		(225,336	)		(226,594	)
Property, plant and equipment, net		1,450,781			1,703,554

Other Assets:
Investment in unconsolidated subsidiary		454,427			-
Long-term derivative assets		6,749			36,798
Other, net of accumulated amortization of debt issuance costs of $9,228 and $5,246		20,874			13,880
Total other assets		482,050			50,678

Intangible Assets and Goodwill:
Intangible assets, net of accumulated amortization of $30,732 and $22,667		200,491			205,646
Goodwill		228,114			262,358
Total intangible assets and goodwill		428,605			468,004

TOTAL ASSETS	$	2,513,930		$	2,458,639

LIABILITIES & PARTNERS' CAPITAL AND NONCONTROLLING INTEREST
Current Liabilities:
Trade accounts payable		28,014			65,483
Accrued cost of gas and liquids		48,304			76,599
Related party payables		853			-
Deferred revenue, including related party amounts of $212 and $0		10,886			11,572
Derivative liabilities		11,897			42,691
Escrow payable		1,510			10,031
Other current liabilities		24,723			10,574
Total current liabilities		126,187			216,950

Long-term derivative liabilities		43,759			560
Other long-term liabilities		15,433			15,487
Long-term debt, net		1,202,392			1,126,229

Commitments and contingencies

Convertible redeemable preferred units, including accrued distributions of $1,945		49,888			-

Partners' Capital and Noncontrolling Interest:
Common units (81,761,105 and 55,519,903 units authorized; 81,116,978 and 54,796,701 units issued and outstanding at September 30, 2009 and December 31, 2008)		1,031,894			764,161
Class D common units (7,276,506 units authorized, issued and outstanding at December 31, 2008)		-			226,759
Subordinated units (19,103,896 units authorized, issued and outstanding at December 31, 2008)		-			(1,391	)
General partner interest		13,629			29,283
Accumulated other comprehensive income		16,691			67,440
Noncontrolling interest		14,057			13,161
Total partners' capital and noncontrolling interest		1,076,271			1,099,413

TOTAL LIABILITIES AND PARTNERS' CAPITAL AND NONCONTROLLING INTEREST	$	2,513,930		$	2,458,639

See accompanying notes to condensed consolidated financial statements

Regency Energy Partners LP
Condensed Consolidated Statements of Operations
Unaudited
(in thousands except unit data and per unit data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008

REVENUES
Gas sales	$	97,597		$	323,411		$	352,390		$	922,872
NGL sales		66,543			120,538			173,803			355,558
Gathering, transportation and other fees, including related party amounts of $3,823, $939, $8,300, and $2,865		66,278			74,267			208,356			206,429
Net realized and unrealized gain (loss) from derivatives		12,292			6,817			39,262			(39,600	)
Other		7,872			22,142			20,291			53,856
Total revenues		250,582			547,175			794,102			1,499,115

OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts of $4,575, $632, $6,275, and $1,878		155,586			408,165			495,461			1,168,441
Operation and maintenance		32,139			33,688			100,154			95,049
General and administrative		14,126			13,976			43,331			38,784
Loss (gain) on asset sales, net of costs of $0, $0, $5,530 and $0		(109	)		(34	)		(133,389	)		434
Management services termination fee		-			-			-			3,888
Transaction expenses		-			2			-			536
Depreciation and amortization		27,009			26,422			81,134			74,638
Total operating costs and expenses		228,751			482,219			586,691			1,381,770

OPERATING INCOME		21,831			64,956			207,411			117,345

Income from unconsolidated subsidiary		3,532			-			5,455			-
Interest expense, net		(22,173	)		(16,072	)		(55,968	)		(48,261	)
Other income and deductions, net		(13,929	)		118			(13,673	)		450
(LOSS) INCOME BEFORE INCOME TAXES		(10,739	)		49,002			143,225			69,534
Income tax (benefit) expense		(196	)		(67	)		(611	)		142
NET (LOSS) INCOME		(10,543	)		49,069			143,836			69,392
Net loss (income) attributable to noncontrolling interest		39			(162	)		(61	)		(165	)
NET (LOSS) INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	(10,504	)	$	48,907		$	143,775		$	69,227

Amounts attributable to convertible redeemable preferred units		1,996			-			1,996			-
General partner's interest, including IDR		372			1,506			4,646			3,140
Allocation of net (loss) income to non-vested common units		(134	)		448			1,083			611
Beneficial conversion feature for Class D common units		-			1,887			820			5,312
Limited partners' interest	$	(12,738	)	$	45,066		$	135,230		$	60,164

Basic and Diluted (loss) earnings per unit:
Amount allocated to common and subordinated units	$	(12,738	)	$	45,066		$	135,230		$	60,164
Weighted average number of common and subordinated units outstanding		80,637,783			70,043,614			79,498,936			63,839,053
Basic (loss) income per common and subordinated unit	$	(0.16	)	$	0.64		$	1.70		$	0.94
Diluted (loss) income per common and subordinated unit	$	(0.16	)	$	0.61		$	1.69		$	0.89
Distributions per unit	$	0.445		$	0.445		$	1.335		$	1.31

Amount allocated to Class D common units	$	-		$	1,887		$	820		$	5,312
Total number of Class D common units outstanding		-			7,276,506			7,276,506			7,276,506
Income per Class D common unit due to beneficial conversion feature	$	-		$	-		$	0.11		$	0.73
Distributions per unit	$	-		$	-		$	-		$	-

See accompanying notes to condensed consolidated financial statements

Regency Energy Partners LP
Condensed Consolidated Statements of Comprehensive Income (Loss)
Unaudited
(in thousands)

	Three Months Ended September 30,							Nine Months Ended September 30,
	2009				2008			2009				2008

Net (loss) income		$	(10,543	)		$	49,069		$	143,836			$	69,392
Net hedging amounts reclassified to earnings			(11,470	)			14,787			(39,364	)			40,389
Net change in fair value of cash flow hedges			(2,144	)			55,182			(11,385	)			5,277
Comprehensive (loss) income		$	(24,157	)		$	119,038		$	93,087			$	115,058
Comprehensive (loss) income attributable to noncontrolling interest			(39	)			162			61				165
Comprehensive (loss) income attributable to Regency Energy Partners LP		$	(24,118	)		$	118,876		$	93,026			$	114,893

See accompanying notes to condensed consolidated financial statements

Regency Energy Partners LP
Condensed Consolidated Statements of Cash Flows
Unaudited
(in thousands)

	Nine Months Ended September 30,
	2009			2008
OPERATING ACTIVITIES
Net income	$	143,836		$	69,392
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization, including debt issuance cost amortization		85,666			76,751
Noncash income from unconsolidated subsidiary		(268	)		-
Derivative valuation changes		3,040			(1,007	)
Loss (gain) on asset sales, net		(133,389	)		434
Unit based compensation expenses		4,361			3,087
Gain on insurance settlements		-			(3,282	)
Cash flow changes in current assets and liabilities:
Trade accounts receivable, accrued revenues, and related party receivables		32,121			(11,084	)
Other current assets		14,478			38
Trade accounts payable, accrued cost of gas and liquids, and related party payables		(47,943	)		(11,125	)
Other current liabilities		5,628			22,448
Other assets and liabilities		(417	)		3,628
Net cash flows provided by operating activities		107,113			149,280

INVESTING ACTIVITIES
Capital expenditures		(163,889	)		(243,660	)
Acquisitions		(63,000	)		(577,344	)
Proceeds from asset sales		100,103			696
Proceeds from insurance settlements		-			3,282
Net cash flows used in investing activities		(126,786	)		(817,026	)

FINANCING ACTIVITIES
Net (repayments) borrowings under revolving credit facilities		(160,627	)		525,000
Proceeds from issuance of senior notes, net of discount		236,240			-
Debt issuance costs		(12,121	)		(2,925	)
Partner contributions		-			11,753
Partner distributions		(109,118	)		(86,448	)
Proceeds from option exercises		-			2,700
Proceeds from equity issuances, net of issuance costs		76,800			199,514
Net cash flows provided by financing activities		31,174			649,594

Net increase (decrease) in cash and cash equivalents		11,501			(18,152	)
Cash and cash equivalents at beginning of period		599			32,971
Cash and cash equivalents at end of period	$	12,100		$	14,819

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	35,258		$	37,634
Income taxes paid		-			596
Non-cash capital expenditures in accounts payable		3,342			24,871
Issuance of common units for an acquisition		-			219,590
Release of escrow payable from restricted cash		-			4,487
Contribution of RIGS to HPC		261,019			-

See accompanying notes to condensed consolidated financial statements

Regency Energy Partners LP

Condensed Consolidated Statements of Partners' Capital and Noncontrolling Interest

Unaudited

(in thousands except unit data)

	Regency Energy Partners LP
	Units
	Common			Class D			Subordinated			Common Unitholders			Class D Unitholders			Subordinated Unitholders			General Partner Interest			Accumulated Other Comprehensive Income			Noncontrolling Interest		Total
Balance - December 31, 2008		54,796,701			7,276,506			19,103,896		$	764,161		$	226,759		$	(1,391	)	$	29,283		$	67,440		$	13,161	$	1,099,413
Revision of partner interest		-			-			-			6,073			-			-			(6,073	)		-					-
Issuance of restricted common units, net of forfeitures		(60,125	)		-			-			-			-			-			-			-			-		-
Conversion of subordinated units		19,103,896						(19,103,896	)		(1,391	)		-			1,391			-			-			-		-
Unit based compensation expenses		-			-			-			4,361			-			-			-			-			-		4,361
Accrued distributions to phantom units		-			-			-			(114	)		-			-			-			-			-		(114	)
Acquisition of assets between entities under common control in excess of historical cost		-			-			-			-			-			-			(10,197	)		-			-		(10,197	)
Partner distributions		-			-			-			(105,128	)		-			-			(3,990	)		-			-		(109,118	)
Net income		-			-			-			138,309			820			-			4,646			-			61		143,836
Conversion of Class D common units		7,276,506			(7,276,506	)		-			227,579			(227,579	)		-			-			-			-		-
Contributions from noncontrolling interest		-			-			-			-			-			-			-			-			835		835
Accrued distributions to convertible redeemable preferred unitholders		-			-			-			(1,906	)		-			-			(39	)		-			-		(1,945	)
Accretion of redeemable preferred units		-			-			-			(50	)		-			-			(1	)		-			-		(51	)
Net cash flow hedge amounts reclassified to earnings		-			-			-			-			-			-			-			(39,364	)		-		(39,364	)
Net change in fair value of cash flow hedges		-			-			-			-			-			-			-			(11,385	)		-		(11,385	)
Balance - September 30, 2009		81,116,978			-			-		$	1,031,894		$	-		$	-		$	13,629		$	16,691		$	14,057	$	1,076,271


See accompanying notes to condensed consolidated financial statements

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements

1. Organization and Summary of Significant Accounting Policies

Organization. The unaudited condensed consolidated financial statements presented herein contain the results of Regency Energy Partners LP and its subsidiaries. The Partnership and its subsidiaries are engaged in the business of gathering and processing, contract compression, and transporting of natural gas and NGLs.

The unaudited financial information as of, and for the three and nine months ended September 30, 2009, has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2008, as amended by Form 8-K filed on May 14, 2009. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.

Use of Estimates. The unaudited condensed consolidated financial statements have been prepared in conformity with GAAP and, of necessity, include the use of estimates and assumptions by management. Actual results could differ from these estimates.

Equity Method Investments. The equity method of accounting is used to account for the Partnership’s interest in investments of greater than 20 percent voting stock of an investee and where the Partnership lacks control over the investee.

Intangible Assets. Intangible assets, net consist of the following.

	Permits and Licenses			Contracts			Trade Names			Customer Relations			Total
	(in thousands)
Balance at December 31, 2008	$	8,582		$	126,799		$	32,848		$	37,417		$	205,646
Disposals		(2,921	)		-			-			-			(2,921	)
Other		-			7,000			-			-			7,000
Amortization		(441	)		(1,755	)		(5,474	)		(1,564	)		(9,234	)
Balance at September 30, 2009	$	5,220		$	132,044		$	27,374		$	35,853		$	200,491

The weighted average amortization period for permits and licenses, customer contracts, trade names, and customer relations are 15, 23, 15, and 19 years, respectively. Permits and licenses are generally renewed with minimal expense as a charge to operating and maintenance expense in the period incurred. Regarding customer contracts, the actual remaining lives of the contracts were used to evaluate the cash flows expected with no renewal assumption. The trade name and customer relations intangible assets use the going concern assumption with no renewal cost. The expected amortization of the intangible assets for each of the five succeeding years is as follows.

Year ending December 31,	Total
	(in thousands)
2009 (remaining)	$	3,138
2010		12,553
2011		11,295
2012		11,002
2013		11,002

Revision to Partners' Capital Accounts. In 2009, the Partnership revised the allocation of net income between the general partner and common unitholders from the third quarter of 2008 to reflect the income allocation provisions of the Partnership agreement. The effect of this revision is not material to the prior financial statements.

Recently Issued Accounting Standards. In December 2007, the FASB issued guidance which significantly changed the accounting for business acquisitions both during the period of the acquisition and in subsequent periods. The Partnership adopted this guidance on January 1, 2009.

In December 2007, the FASB issued guidance which significantly changed the accounting and reporting related to noncontrolling interests in a consolidated subsidiary. The Partnership adopted this guidance for all periods presented. This guidance requires the recognition of a noncontrolling interest (formerly styled as a minority interest) in partners’ capital in the condensed consolidated financial statements and separate from the partners’ interest. Also, the amount of net income attributable to the noncontrolling interest is included in the consolidated net income on the face of the condensed consolidated income statement.

In March 2008, the FASB issued guidance which defines how to allocate net income among the various classes of equity, including IDRs. The guidance became effective on January 1, 2009. Earlier application was not permitted; however this guidance must be applied retrospectively for all financial statements presented. The adoption of this guidance changed the Partnership’s method of allocating net income for earnings per unit purposes to holders of the IDRs in periods where net income exceeds cash distributed. Because the Partnership Agreement restricts the amount of distributions to holders of IDRs based on cash available for distribution, undistributed net income will be allocated based on each class of security’s ownership interest. Further, because the IDRs are deemed to have no ownership interest, no undistributed net income will be allocated to this class of security. All prior period earnings per unit data have been adjusted.

In March 2008, the FASB issued guidance which required enhanced disclosures about derivative and hedging activities. The Partnership adopted this guidance on January 1, 2009 and the adoption had no impact on its financial position, results of operations or cash flows.

In April 2008, FASB issued guidance which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of intangible assets. The objective of this guidance is to better match the useful life of intangible assets to the cash flow generated. The guidance became effective on January 1, 2009. The adoption of this guidance did not impact the Partnership’s financial position, results of operations or cash flows.

In June 2008, the FASB issued guidance which determined whether instruments granted in share-based payment transactions are participating securities and is effective for fiscal years beginning after December 15, 2008. The adoption of this guidance was applied retrospectively and had an immaterial impact on the Partnership’s earnings per unit.

In April 2009, the FASB issued guidance about interim disclosures about fair value of financial instruments which was adopted July 1, 2009. This guidance had no impact on the Partnership’s financial position, results of operations or cash flows.

In May 2009, the FASB issued guidance requiring public entities to evaluate subsequent events through the date through which financial statements are issued. The adoption of this guidance on January 1, 2009 did not impact the Partnership’s financial position, results of operations or cash flows.

In June 2009, the FASB issued guidance that significantly changes the consolidation model for variable interest entities. The guidance is effective for annual reporting periods that begin after November 15, 2009, and for interim periods within that first annual reporting period. The Partnership has evaluated this guidance and determined that its adoption on January 1, 2010 will have no impact on the Partnership’s financial position, results of operations or cash flows.

In June 2009, the FASB issued “The FASB Accounting Standards Codification TM and the Hierarchy of Generally Accepted Accounting Principles” (the “Codification”). The Codification is the single source for GAAP that integrates existing standards and organizes them into accounting topics and is not intended to change GAAP but will change how GAAP is referenced. The Codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009, and it is not expected to have a material impact on the Partnership’s financial position, results of operations or cash flows.

2. Income (Loss) per Limited Partner Unit

The Partnership issued 7,276,506 Class D common units in connection with the CDM acquisition. At the commitment date, the sales price of $30.18 per unit represented a $1.10 discount from the fair value of the Partnership’s common units. This discount represented a beneficial conversion feature that is treated as a non-cash distribution for purposes of calculating earnings per unit. The beneficial conversion feature is reflected in income per unit using the effective yield method over the period the Class D common units are outstanding, as indicated on the statements of operations in the line item entitled “beneficial conversion feature for Class D common units.” The Class D common units converted to common units on a one-for-one basis on February 9, 2009.

On September 2, 2009, the Partnership issued 4,371,586 Series A Cumulative Convertible Preferred Units (“Convertible Redeemable Preferred Units”). The Convertible Redeemable Preferred Units will receive fixed quarterly cash distributions of $0.445 per unit beginning with the quarter ending March 31, 2010. Distributions for the quarters ending September 30, 2009 and December 31, 2009 will be accrued but not paid, effectively increasing the conversion value of the Convertible Redeemable Preferred Units. Distributions are cumulative, and must be paid before any distributions to the general partner and common unitholders. For the purpose of calculating income per limited partner unit, any form of distributions, whether paid or not, as well as the accretion of the Convertible Redeemable Preferred Units, are treated as a reduction in net income available to the general partner and limited partner interests.

The following tables provide a reconciliation of the basic and diluted earnings per unit computations.

	For the Three Months Ended September 30, 2009								For the Three Months Ended September 30, 2008
	(Loss) Income (Numerator)			Units (Denominator)		Per-Unit Amount			Income (Numerator)		Units (Denominator)		Per-Unit Amount
	(in thousands except unit and per unit data)
Basic (Loss) Earnings per Unit
Net (loss) income attributable to Limited Partner interests	$	(12,738	)		80,637,783	$	(0.16	)	$	45,066		70,043,614	$	0.64
Effect of Dilutive Securities
Non-vested common units		(134	)		-					-		-
Common unit options		-			-					-		37,969
Phantom units		-			-					-		-
Class D common units		-			-					1,887		7,276,506
Diluted (Loss) Earnings per Unit	$	(12,872	)		80,637,783	$	(0.16	)	$	46,953		77,358,089	$	0.61

The following table shows securities that could potentially dilute earnings per unit in the future that were not included in the computation of diluted earnings per unit because to do so would have been antidilutive.

	For the Nine Months Ended September 30, 2009						For the Nine Months Ended September 30, 2008
	Income (Numerator)		Units (Denominator)		Per-Unit Amount		Income (Numerator)		Units (Denominator)		Per-Unit Amount
	(in thousands except unit and per unit data)
Basic Earnings per Unit
Net income attributable to Limited Partner interests	$	135,230		79,498,936	$	1.70	$	60,164		63,839,053	$	0.94
Effect of Dilutive Securities
Common unit options		-		-				-		111,134
Phantom units		-		32,692				-		-
Class D common units		820		1,066,155				5,312		7,276,506
Class E common units		-		-				-		2,161,789
Diluted Earnings per Unit	$	136,050		80,597,783	$	1.69	$	65,476		73,388,482	$	0.89

Anti-dilutive securities:
	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Non-vested common units		-		18,331		-		40,654
Phantom units		250,258		-		-		-
Convertible redeemable preferred units		1,378,000		-		464,381		-

3. Acquisitions and Disposition

On March 17, 2009, the Partnership announced the completion of the transactions contemplated by the Contribution Agreement (the “Contribution Agreement”) relating to a joint venture arrangement among Regency HIG, EFS Haynesville, LLC, and the Alinda Investors. The Partnership contributed RIGS, which owns the Regency Intrastate Gas System, valued at $401,356,000, to HPC, in exchange for a 38 percent interest in HPC. EFS Haynesville and Alinda Investors contributed $126,928,000 and $528,284,000 in cash, respectively, to HPC in return for a 12 percent and a 50 percent interest, respectively. The disposition and deconsolidation resulted in the recording of a $133,451,000 gain (of which $52,813,000 represents the remeasurement of the Partnership’s retained 38 percent interest to its fair value), net of transaction costs of $5,530,000.

On September 2, 2009, the Partnership purchased a five percent interest in HPC from EFS Haynesville for $63,000,000, increasing the Partnership’s ownership percentage from 38 percent to 43 percent. Because the transaction occurred between two entities that are under common control, partners’ capital was reduced by $10,197,000, which represented a deemed distribution of the excess purchase price over EFS Haynesville’s carrying amount.

The following unaudited pro forma financial information has been prepared as if the acquisitions of FrontStreet, CDM and Nexus and the contribution of RIGS to HPC as well as the acquisition of additional five percent HPC interest had occurred as of the beginning of the earliest period presented. Such unaudited pro forma financial information does not purport to be indicative of the results of operations that would have been achieved if the transactions to which the Partnership is giving pro forma effect actually occurred on the date referred to above or the results of operations that may be expected in the future.

	Pro Forma Results for the					Pro Forma Results for the
	Three Months Ended					Nine Months Ended
	September 30, 2009			September 30, 2008		September 30, 2009			September 30, 2008
	(in thousands except unit and per unit data)
Revenue	$	250,582		$	534,794	$	782,129		$	1,470,588

Net income (loss) attributable to Regency Energy Partners LP	$	(10,158	)	$	43,252	$	6,579		$	189,833
Less:
Amounts attributable to convertible redeemable preferred units		1,996			-		1,996			-
General partner's interest, including IDR		378			1,392		1,901			5,552
Allocation of net income to non-vested common units		(132	)		394		(98	)		2,013
Beneficial conversion feature for Class D common units		-			1,887		820			5,312
Limited partners' interest	$	(12,400	)	$	39,579	$	1,960		$	176,956

Basic and Diluted earnings (loss) per unit:
Amount allocated to common and subordinated units	$	(12,404	)	$	39,579	$	1,956		$	176,956
Weighted average number of common and subordinated units outstanding		80,637,783			70,043,532		79,498,936			63,838,515
Basic income (loss) per common and subordinated unit	$	(0.15	)	$	0.57	$	0.02		$	2.77
Diluted income (loss) per common and subordinated unit	$	(0.15	)	$	0.54	$	0.02		$	2.50
Distributions per unit	$	0.445		$	0.445	$	0.445		$	1.31

Amount allocated to Class D common units	$	-		$	1,887	$	820		$	5,312
Total number of Class D common units outstanding		-			7,276,506		7,276,506			7,276,506
Basic and diluted income per Class D common unit due to beneficial conversion feature	$	-		$	0.26	$	0.11		$	0.73
Distributions per unit	$	-		$	-	$	-		$	-

4. Investment in Unconsolidated Subsidiary

As described in the Acquisitions and Disposition footnote, the Partnership contributed RIGS to HPC for a 38 percent partner interest in HPC. Subsequently, on September 2, 2009, the Partnership purchased an additional five percent partner’s interest in HPC from EFS Haynesville for $63,000,000. The summarized financial information of HPC as of September 30, 2009 and for the period from inception (March 18, 2009) to September 30, 2009 is disclosed below. The Partnership recognized $5,455,000 in income from unconsolidated subsidiary for its ownership interest from inception (March 18, 2009) to September 30, 2009. In addition, the Partnership received $5,187,000 of distributions from HPC during the period from March 18, 2009 to September 30, 2009.

RIGS Haynesville Partnership Co.
Condensed Balance Sheet
September 30, 2009
Unaudited
(in thousands)
	September 30, 2009
ASSETS
Total current assets	$	191,707
Property, plant and equipment, net		761,648
Total other assets		150,200
TOTAL ASSETS	$	1,103,555

LIABILITIES & PARTNERS' CAPITAL
Total current liabilities	$	46,558
Partners' capital		1,056,997
TOTAL LIABILITIES & PARTNERS' CAPITAL	$	1,103,555

RIGS Haynesville Partnership Co.
Condensed Income Statement
From Inception (March 18, 2009) to September 30, 2009
Unaudited
(in thousands)

	Three Months Ended			March 18, 2009 to
	September 30, 2009			September 30, 2009
Total revenues	$	14,188		$	30,095
Total operating costs and expenses		5,702			17,160
OPERATING INCOME		8,486			12,935
Interest expense		(65	)		(65	)
Other income and deductions, net		597			1,209
NET INCOME	$	9,018		$	14,079

5. Derivative Instruments

Policies. The Partnership established comprehensive risk management policies and procedures to monitor and manage the market risks associated with commodity prices, counterparty credit, and interest rates. The Partnership’s General Partner is responsible for delegation of transaction authority levels, and the Risk Management Committee of the General Partner is responsible for the overall management of these risks, including monitoring exposure limits. The Risk Management Committee receives regular briefings on exposures and overall risk management in the context of market activities.

The Partnership primarily deals with financial institutions when entering into financial derivatives.

Commodity Price Risk. The Partnership is exposed to the impact of market fluctuations in the prices of natural gas, NGLs, and other commodities as a result of our gathering and processing activities, and the Partnership is a net seller of natural gas, NGLs and condensate. The Partnership attempts to mitigate commodity price risk exposure by matching pricing terms between its purchases and sales of commodities. To the extent that the Partnership sells commodities in which pricing terms cannot be matched and there is a substantial risk of price exposure, the Partnership attempts to use financial hedges to mitigate the risk. It is the Partnership’s policy not to take any speculative positions with its derivative contracts. In some cases, the Partnership may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk.

Both the Partnership’s profitability and cash flows are affected by volatility in prevailing natural gas and NGL prices. Natural gas and NGL prices are impacted by changes in the supply and demand for NGLs and natural gas, as well as price volatility. Adverse effects on cash flows from reductions in natural gas and NGL product prices could adversely affect the Partnership’s ability to make distributions to unitholders. The Partnership manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts.

The Partnership has executed swap contracts settled against condensate, ethane, propane, butane, natural gas, and natural gasoline market prices. The Partnership hedged its expected exposure to declines in prices for NGLs, condensate and natural gas volumes produced for its account in the approximate percentages set for below:

	2009		2010		2011
NGL		99%		56%		18%
Condensate		76%		76%		18%
Natural gas		86%		44%		0%

Effective June 19, 2007, the Partnership elected to account for all outstanding commodity hedging instruments on a mark-to-market basis except for the portion pursuant to which all NGL products for a particular year were hedged and the hedging relationship was, for accounting purposes, effective. The swaps continued to serve as economic hedges against price exposure for the Partnership. The Partnership uses West Texas Intermediate crude oil program to hedge condensate. At September 30, 2009, the Partnership has the following commodity swaps that qualify as cash flow hedges: the 2009 NGLs, natural gas and West Texas Intermediate crude oil hedging programs and the 2010 NGLs, natural gas and West Texas Intermediate crude oil hedging programs.

In March 2008, the Partnership entered offsetting trades against its existing 2009 NGL portfolio of mark-to-market hedges, which it believes will substantially reduce the volatility of its 2009 NGL hedges. This group of trades, along with the pre-existing 2009 NGL portfolio, will continue to be accounted for on a mark-to-market basis. Simultaneously, the Partnership executed additional 2009 NGL swaps which were designated as cash flow hedges. In May 2008, the Partnership entered into commodity swaps to hedge a portion of its 2010 NGL commodity risk, except for ethane, which are accounted for using the mark-to-market accounting treatment.

The Partnership accounts for a portion of its West Texas Intermediate crude oil swaps using mark-to-market accounting. In August 2008, the Partnership entered into an offsetting trade against its existing 2009 West Texas Intermediate crude oil swap to minimize the volatility of the original 2009 swap. Simultaneously, the Partnership executed an additional 2009 West Texas Intermediate crude oil swap, which was designated as a cash flow hedge. In May 2008, the Partnership entered into a West Texas Intermediate crude oil swap to hedge its 2010 condensate price risk, which was designated as a cash flow hedge.

In December 2008, the Partnership entered into two natural gas swaps to hedge its equity exposure to natural gas for 2009. In May 2009, the Partnership entered into a natural gas swap to hedge a portion of its equity exposure to natural gas for 2010. These natural gas swaps were designated as cash flow hedges.

In July 2009, the Partnership entered offsetting trades against half of its existing 2010 NGL portfolio of mark-to-market hedges, which it believes will substantially reduce the volatility of its 2010 NGL hedges. This group of trades, along with the pre-existing 2010 NGL portfolio, will continue to be accounted for on a mark-to-market basis. Simultaneously, the Partnership executed additional 2010 NGL swaps which were designated as cash flow hedges.

Additionally, in July 2009, the Partnership entered into swap transactions to hedge a portion of its forecasted NGLs and condensate equity exposure for the first half of 2011. These swaps are accounted for using the mark-to-market accounting treatment.

Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of borrowings under its existing credit facility. As of September 30, 2009, the Partnership had $608,102,000 of outstanding long-term balances exposed to variable interest rate risk. An increase of 100 basis points in the LIBOR rate would increase the Partnership’s annual payment by $6,081,000. On February 29, 2008, the Partnership entered into two-year interest rate swaps related to $300,000,000 of borrowings under its revolving credit facility, effectively locking the base rate for these borrowings at 2.4 percent, plus the applicable margin (3 percent as of September 30, 2009) through March 5, 2010. These interest rate swaps were designated as cash flow hedges.

Credit Risk. The Partnership’s resale of natural gas exposes it to credit risk, as the margin on any sale is generally a very small percentage of the total sales price. Therefore, a credit loss can be very large relative to overall profitability on these transactions. The Partnership attempts to ensure that it issues credit only to credit-worthy counterparties and that in appropriate circumstances any such extension of credit is backed by adequate collateral such as a letter of credit or a guarantee from a parent company with potentially better credit.

The Partnership is exposed to credit risk from its derivative counterparties. The Partnership does not require collateral from these counterparties. The Partnership has entered into Master International Swap Dealers Association (“ISDA”) Agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If the Partnership's counterparties failed to perform under existing swap contracts, the Partnership's maximum loss is $40,719,000, which would be reduced by $10,882,000 due to the netting feature. The Partnership has elected to present assets and liabilities under Master ISDA Agreements gross on the condensed consolidated balance sheet.

Embedded Derivatives. The Convertible Redeemable Preferred Units contain embedded derivatives, such as the holders’ conversion option and the Partnership’s call option. These embedded derivatives are accounted for using mark-to-market accounting treatment. Changes in the fair value are recorded in other income and deductions, net within the statement of operations. The Partnership does not expect the embedded derivatives to affect its cash flows. During the three months ended September 30, 2009, the total amount of loss recognized was $13,986,000.

Quantitative Disclosures. The Partnership expects to reclassify $12,470,000 of net hedging gains to revenues or interest expense from accumulated other comprehensive income in the next 12 months.

The Partnership’s derivative assets and liabilities, including its credit risk adjustment, are detailed below as of September 30, 2009 and December 31, 2008 and for the three and nine months ended September 30, 2009 and 2008.

	Assets						Liabilities
	September 30, 2009			December 31, 2008			September 30, 2009			December 31, 2008
	(in thousands)
Derivatives designated as cash flow hedges
Current amounts
Interest rate contracts	$	-		$	-		$	2,677		$	4,680
Commodity contracts		19,640			59,882			3,048			-
Long-term amounts
Interest rate contracts		-			-			-			560
Commodity contracts		2,681			13,373			99			-
Total cash flow hedging instruments		22,321			73,255			5,824			5,240

Derivatives not designated as cash flow hedges
Current amounts
Interest rate contracts		-			-			-			-
Commodity contracts		14,330			16,001			6,292			38,402
Long-term amounts
Interest rate contracts		-			-			-			-
Commodity contracts		4,068			23,425			766			-
Embedded derivatives in convertible redeemable preferred units		-			-			(42,894	)		-
Total derivatives not designated as cash flow hedges		18,398			39,426			(35,836	)		38,402

Credit Risk Assessment
Current amounts		(220	)		(1,890	)		(120	)		(391	)
Total derivatives	$	40,499		$	110,791		$	(30,132	)	$	43,251

Derivatives designated as cash flow hedges
	Three Months Ended September 30, 2009									Three Months Ended September 30, 2008
	Interest Rate			Commodity			Total			Interest Rate			Commodity			Total
Gain (loss) recorded in accumulated OCI (Effective)	$	(522	)	$	(3,005	)	$	(3,527	)	$	(751	)	$	57,444		$	56,693
Gain (loss) reclassified from accumulated OCI into income (Effective)*		(1,612	)		13,514			11,902			51			(14,773	)		(14,722	)
Gain (loss) recognized in income (Ineffective)*		-			(1,383	)		(1,383	)		-			1,511			1,511

	Nine Months Ended September 30, 2009									Nine Months Ended September 30, 2008
	Interest Rate			Commodity			Total			Interest Rate			Commodity			Total
Gain (loss) recorded in accumulated OCI (Effective)	$	(2,035	)	$	(8,501	)	$	(10,536	)		3,693			3,581		$	7,274
Gain (loss) reclassified from accumulated OCI into income (Effective)*		(4,597	)		45,578			40,981			410			(40,617	)		(40,207	)
Gain (loss) recognized in income (Ineffective)*		-			849			849			-			1,997			1,997

Derivatives not designated as cash flow hedges
	Three Months Ended September 30, 2009									Three Months Ended September 30, 2008
	Embedded Derivative			Commodity			Total			Embedded Derivative			Commodity			Total
Loss from dedesignation amortized from accumulated OCI into income*	$	-		$	(432	)	$	(432	)	$	-		$	(65	)	$	(65	)
(Loss) gain recognized in income*		(13,986	)		143			(13,843	)		-			19,982			19,982

	Nine Months Ended September 30, 2009									Nine Months Ended September 30, 2008
	Embedded Derivative			Commodity			Total			Embedded Derivative			Commodity			Total
Loss from dedesignation amortized from accumulated OCI into income*	$	-		$	(1,617	)	$	(1,617	)	$	-		$	(182	)	$	(182	)
Loss recognized in income*		(13,986	)		(6,948	)		(20,934	)		-			(1,908	)		(1,908	)

Credit risk assessment for commodity and interest rate swaps
	Three Months Ended				Nine Months Ended
	September 30, 2009			September 30, 2008	September 30, 2009		September 30, 2008
Gain recognized in income*	$	450	$	162	$	1,400	$	1,110

* Gain and loss related to commodity swaps, interest swaps and embedded derivatives were included in revenue, interest expense, and other income and deductions, net, respectively, in the Partnership’s condensed consolidated statements of operations for the three and nine months of September 30, 2009 and 2008.

6. Long-term Debt, net

Obligations in the form of senior notes and borrowings under the credit facilities are as follows.

	September 30, 2009			December 31, 2008
	(in thousands)
Senior notes	$	594,290		$	357,500
Revolving loans		608,102			768,729
Total		1,202,392			1,126,229
Less: current portion		-			-
Long-term debt	$	1,202,392		$	1,126,229

Availability under revolving credit facility:
Total credit facility limit	$	900,000		$	900,000
Unfunded Lehman commitments		(7,030	)		(8,646	)
Revolving loans		(608,102			(768,729	)
Letters of credit		(16,257	)		(16,257	)
Total available	$	268,611		$	106,368

On May 20, 2009, the Partnership and Finance Corp. issued $250,000,000 senior notes in a private placement that matures on June 1, 2016. The senior notes bear interest at 9.375 percent with interest payable semiannually on June 1 and December 1. The proceeds were used to partially repay revolving loans under the Partnership’s credit facility.

At any time before June 1, 2012, up to 35 percent of the senior notes can be redeemed at a price of 109.375 percent plus accrued interest. Beginning June 1, 2013, the Partnership may redeem all or part of the notes for the principal amount plus a declining premium until June 1, 2015, and thereafter at par, plus accrued and unpaid interest. At any time prior to June 1, 2013, the Partnership may also redeem all or part of the notes at a price equal to 100 percent of the principal amount of notes redeemed plus accrued interest and the applicable premium, which equals to the greater of (1) 1 percent of the principal amount of the note; or (2) the excess of the present value at such redemption date of (i) the redemption price of the note at June 1, 2013 plus (ii) all required interest payments due on the note through June 1, 2013, computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points over the principal amount of the note.

Upon a change of control, each noteholder will be entitled to require the Partnership to purchase all or a portion of its notes at a purchase price of 101 percent plus accrued interest. The senior notes contain various covenants that limit, among other things, the Partnership’s ability, and the ability of certain of its subsidiaries, to:

·	incur additional indebtedness;
·	pay distributions on, or repurchase or redeem equity interests;
·	make certain investments;
·	incur liens;
·	enter into certain types of transactions with affiliates; and
·	sell assets, consolidate or merge with or into other companies.

The senior notes are jointly and severally guaranteed by all of the Partnership’s current consolidated subsidiaries, other than Finance Corp., and by certain of its future subsidiaries. The senior notes and the guarantees are unsecured and rank equally with all of the Partnership’s and the guarantors’ existing and future unsubordinated obligations. The senior notes and the guarantees will be senior in right of payment to any of the Partnership’s and the guarantors’ future obligations that are, by their terms, expressly subordinated in right of payment to the notes and the guarantees. The senior notes and the guarantees will be effectively subordinated to the Partnership’s and the guarantors’ secured obligations, including the Partnership’s Credit Facility, to the extent of the value of the assets securing such obligations.

Finance Corp. has no operations and will not have revenue other than as may be incidental as co-issuer of the senior notes. Since the Partnership has no independent operations, the guarantees are fully unconditional and joint and several of its subsidiaries, except certain wholly owned subsidiaries, the Partnership has not included condensed consolidated financial information of guarantors of the senior notes.

The carrying value of the Partnership’s senior notes due 2016 is as follows.

	September 30, 2009			December 31, 2008
	(in thousands)
Principal amount	$	250,000		$	-
Less: Unamortized discount		(13,210	)		-
Carrying value	$	236,790		$	-

On March 17, 2009, RGS amended its credit agreement to authorize the contribution of RIGS to a joint venture (HPC) and allow for future investment up to $135,000,000 in a joint venture. The amendment imposed additional financial restrictions that limit the ratio of senior secured indebtedness to EBITDA. The alternate base rate used to calculate interest on base rate loans will be calculated based on the greatest to occur of a base rate, a federal funds effective rate plus 0.50 percent and an adjusted one-month LIBOR rate plus 1.50 percent. The applicable margin shall range from 1.50 percent to 2.25 percent for base rate loans, 2.50 percent to 3.25 percent for Eurodollar loans, and commitment fees will range from 0.375 percent to 0.500 percent.

On July 24, 2009, RGS further amended its credit agreement to allow for a $25,000,000 working capital facility for the RIGS Haynesville Joint Venture.

GECC Credit Facility. On February 26, 2009, the Partnership entered into a $45,000,000 unsecured revolving credit agreement with GECC. The proceeds of the GECC Credit Facility were available for expenditures made in connection with the Haynesville Expansion Project prior to the effectiveness of the above March 17, 2009 amendment. The commitments under the Revolving Credit Facility terminated on March 17, 2009. The Partnership paid a commitment fee of $2,718,000 to GECC related to this GECC Credit Facility, which was recorded as a decrease to gain on asset sales, net.

On September 15, 2008, Lehman filed a petition in the United States Bankruptcy Court seeking relief under Chapter 11 of the United States Bankruptcy Code. As a result, a subsidiary of Lehman that is a committed lender under our Credit Facility has declined requests to honor its commitment to lend. The total amount committed by Lehman was $20,000,000 and as of September 30, 2009, the Partnership had borrowed all but $7,030,000 of that amount. Since Lehman has declined requests to honor its remaining commitment, our total size of the Credit Facility’s capacity has been reduced from $900,000,000 to $892,970,000. Further, if the Partnership makes repayments of loans against the Credit Facility which were, in part, funded by Lehman, the amounts funded by Lehman may not be reborrowed.

The outstanding balance of revolving debt under the Credit Facility bears interest at LIBOR plus a margin or Alternate Base Rate (equivalent to the U.S prime rate lending rate) plus a margin or a combination of both. The weighted average interest rates for the revolving loans and senior notes, including interest rate swap settlements, commitment fees, and amortization of debt issuance costs were 6.44 percent and 6.37 percent for the nine months ended September 30, 2009 and 2008, respectively, and 7.42 percent and 6.15 percent for the three months ended September 30, 2009 and 2008, respectively. The senior notes pay fixed interest rates and the weighted average rate is 8.787 percent.

7. Commitments and Contingencies

Legal. The Partnership is involved in various claims and lawsuits incidental to its business. These claims and lawsuits in the aggregate should not have a material adverse effect on the Partnership’s business, financial condition, results of operations or cash flows.

Escrow Payable. At September 30, 2009, $1,510,000 remained in escrow pending the completion by El Paso of environmental remediation projects pursuant to the purchase and sale agreement (“El Paso PSA”) related to assets in north Louisiana and the mid-continent area. In the El Paso PSA, El Paso indemnified the predecessor of the Partnership’s operating partnership, RGS, against losses arising from pre-closing and known environmental liabilities subject to a limit of $84,000,000 and certain deductible limits. Upon completion of a Phase II environmental study, the Partnership notified El Paso of remediation obligations amounting to $1,800,000 with respect to known environmental matters and $3,600,000 with respect to pre-closing environmental liabilities. This escrow amount will be further reduced under a specified schedule as El Paso completes its cleanup obligations and the remainder will be released upon completion.

Environmental. A Phase I environmental study was performed on certain assets located in west Texas in connection with the pre-acquisition due diligence process in 2004. Most of the identified environmental contamination had either been remediated or was being remediated by the previous owners or operators of the properties. The aggregate potential environmental remediation costs at specific locations were estimated to range from $1,900,000 to $3,100,000. No governmental agency has required the Partnership to undertake these remediation efforts. Management believes that the likelihood that it will be liable for any significant potential remediation liabilities identified in the study is remote. Separately, the Partnership acquired an environmental pollution liability insurance policy in connection with the acquisition to cover any undetected or unknown pollution discovered in the future. The policy covers clean-up costs and damages to third parties, and has a 10-year term (expiring 2014) with a $10,000,000 limit subject to certain deductibles. No claims have been made against the Partnership or under the policy.

TCEQ Notice of Enforcement. In February 2008, the TCEQ issued a NOE concerning one of the Partnership’s processing plants located in McMullen County, Texas (the “Plant”). The NOE alleges that, between March 9, 2006, and May 8, 2007, the Plant experienced 15 emission events of various durations from four hours to 41 days, which were not reported to TCEQ and other agencies within 24 hours of occurrence. In April 2008, TCEQ presented the Partnership with a written offer to settle the allegation in the NOE in exchange for payment of an administrative penalty of $480,000, and it later reduced its settlement demand to $360,000 in July 2008. The Partnership was unable to settle this matter on a satisfactory basis and the TCEQ has referred the matter to its litigation division for further administrative proceedings.

Keyes Litigation. In August 2008, Keyes Helium Company, LLC (“Keyes”) filed suit against Regency Gas Services LP, the Partnership, and the General Partner. Keyes entered into an output contract with the Partnership’s predecessor in 1996 under which it purchased all of the helium produced at the Lakin, Kansas processing plant. In September 2004, the Partnership decided to shut down its Lakin plant and contract with a third party for the processing of volumes processed at Lakin; as a result, the Partnership no longer delivered any helium to Keyes. In this suit, Keyes alleges it is entitled to an unspecified amount of damages for the costs of covering its purchases of helium. Discovery ended in October 2009 and trial is scheduled for December 2009.

Kansas State Severance Tax. In August 2008, a customer began remitting severance tax to the state of Kansas based on the value of condensate purchased from one of the Partnership’s Mid-Continent gathering fields and deducting the tax from its payments to the Partnership. The Kansas Department of Revenue advised the customer that it was appropriate to remit such taxes and withhold the taxes from its payments to the Partnership, absent an order or legal opinion from the Kansas Department of Revenue stating otherwise. The Partnership has requested a determination and refund from the Kansas Department of Revenue regarding the matter since severance taxes were already paid on the gas from which the condensate is collected and no additional tax is due. The Kansas Department of Revenue has initiated an audit of the Partnership’s condensate sales in Kansas. If the Kansas Department of Revenue determines that the condensate sales are taxable, then the Partnership may be subject to additional taxes, interest and possibly penalties for past and future condensate sales.

Caddo Gas Gathering LLC v. Regency Intrastate Gas LLC. Caddo Gas Gathering LLC (“Caddo Gas”) claims that RIGS breached a 1988 natural gas transportation agreement (the “Transportation Agreement”). Caddo Gas alleges that the Transportation Agreement requires RIGS to take receipt of gas at any receipt point on the “Regency Gas System” and redeliver that gas for $0.05 per MMbtu. Caddo Gas further alleges that RIGS’ obligation to provide transportation to Caddo Gas is unconditional and that RIGS breached the Transportation Agreement when it refused to let Caddo Gas access a fully-subscribed receipt point interconnect at the Centerpoint Energy Sligo Plant (“Sligo Point”), but offered to install a new interconnect at Caddo Gas’ cost. RIGS filed an answer denying that Caddo Gas was entitled to access the Regency Gas System through the Sligo Point and denying that its actions constituted a breach of the Transportation Agreement. No trial date has been set.

Remediation of Groundwater Contamination at Calhoun and Dubach Plants. RFS currently owns the Dubach and Calhoun gas processing plants in north Louisiana (the “Plants”). The Plants each have groundwater contamination as result of historical operations. At the time that RFS acquired the Plants from El Paso, Kerr-McGee Corporation (Kerr-McGee) was performing remediation of the groundwater contamination, because the Plants were once owned by Kerr-McGee and when Kerr-McGee sold the Plants to a predecessor of El Paso in 1988, Kerr-McGee retained liability for any environmental contamination at the Plants. In 2005, Kerr-McGee created and spun off Tronox and Tronox allegedly assumed certain of Kerr-McGee’s environmental remediation obligations (including its obligation to perform remediation at the Plants) prior to the acquisition of Kerr-McGee by Anadarko Petroleum Corporation. In January 2009, Tronox filed for Chapter 11 bankruptcy protection. RFS filed a claim in the bankruptcy proceeding relating to the environmental remediation work at the Plants. Tronox has thus far continued its remediation efforts at the Regency facilities.

8. Convertible Redeemable Preferred Units

On September 2, 2009, the Partnership issued 4,371,586 Convertible Redeemable Preferred Units at a price of $18.30 per unit, less a four percent discount of $3,200,000, for net proceeds of $76,800,000. The Convertible Redeemable Preferred Units are convertible to common units under terms described below, and if outstanding, are redeemable on September 2, 2029. The Convertible Redeemable Preferred Units will receive fixed quarterly cash distributions of $0.445 per unit beginning with the quarter ending March 31, 2010.

Distributions on the Convertible Redeemable Preferred Units will be accrued for the quarters ending September 30, 2009 and December 31, 2009 (and not paid in cash) and will result in an increase in the number of common units issuable upon conversion. If on any distribution payment date beginning March 31, 2010, the Partnership (1) fails to pay distributions on the Convertible Redeemable Preferred Units, (2) reduces the distributions on the common units to zero and (3) is prohibited by its material financing agreements from paying cash distributions, such distributions shall automatically accrue and accumulate until paid in cash. If the Partnership has failed to pay cash distributions in full for two quarters (whether or not consecutive) from and including the quarter ending on March 31, 2010, then if the Partnership fails to pay cash distributions on the Convertible Redeemable Preferred Units, all future distributions on the Convertible Redeemable Preferred Units that are accrued rather than being paid in cash by the Partnership will consist of the following: (1) $0.35375 per Convertible Redeemable Preferred Unit per quarter, (2) $0.09125 per Convertible Redeemable Preferred Unit per quarter (the “Common Unit Distribution Amount”), payable solely in common units, and (3) $0.09125 per Convertible Redeemable Preferred Unit per quarter (the “PIK Distribution Additional Amount”), payable solely in common units. The total number of common units payable in connection with the Common Unit Additional Amount or the PIK Distribution Additional Amount cannot exceed 1,600,000 in any period of twenty consecutive fiscal quarters.

Upon the Partnership’s breach of certain covenants related to the 9.375 percent Senior Notes due 2016 (a “Covenant Default”), the holders of the Convertible Redeemable Preferred Units will be entitled to an increase of $0.1825 per quarterly distribution, payable solely in common units (the “Covenant Default Additional Amount”). All accumulated and unpaid distributions will accrue interest (i) at a rate of 2.432 percent per quarter, or (ii) if the Partnership has failed to pay all PIK Distribution Additional Amounts or Covenant Default Additional Amounts or any Covenant Default has occurred and is continuing, at a rate of 3.429 percent per quarter while such failure to pay or such Covenant Default continues.

The Convertible Redeemable Preferred Units are convertible, at the holder’s option, into common units commencing on March 2, 2010, provided that the holder must request conversion of at least 375,000 Convertible Redeemable Preferred Units. The conversion price will initially be $18.30, subject to adjustment for customary events (such as unit splits) and until December 31, 2011, based on a weighted average formula in the event the Partnership issues any common units (or securities convertible or exercisable into common units) at a per Common Unit price below $16.47 per common unit. The number of common units issuable is equal to the issue price of the Convertible Redeemable Preferred Units (i.e. $18.30) being converted plus all accrued but unpaid distributions and accrued but unpaid interest thereon (the “Redeemable Face Amount”), divided by the applicable conversion price.

Commencing on September 2, 2014, if at any time the volume-weighted average trading price of the common units over the trailing 20-trading day period (the “VWAP Price”) is less than the then-applicable conversion price, the conversion ratio will be increased to: the quotient of (1) the Redeemable Face Amount on the date that the holder’s conversion notice is delivered, divided by (2) the product of (x) the VWAP Price set forth in the applicable conversion notice and (y) 91 percent, but will not be less than $10.

Also commencing on September 2, 2014, the Partnership will have the right at any time to convert all or part of the Convertible Redeemable Preferred Units into common units, if (1) the daily volume-weighted average trading price of the common units is greater than 150 percent of the then-applicable conversion price for twenty (20) out of the trailing thirty (30) trading days, and (2) certain minimum public float and trading volume requirements are satisfied.

The Convertible Redeemable Preferred Units are mandatorily redeemable on September 2, 2029 for $80,000,000 plus all accrued but unpaid distributions thereon (the “Series A Liquidation Value”).

In the event of a change of control followed by a ratings decline, the Partnership will be required to make an offer to the holders of the Convertible Redeemable Preferred Units to purchase their Convertible Redeemable Preferred Units for an amount equal to 101 percent of their Series A Liquidation Value. In addition, until and including the fifth anniversary of the issuance date, in the event of certain business combinations or other transactions involving the Partnership in which the holders of common units receive cash consideration exclusively in exchange for their common units (a “Cash Event”), the Partnership must use commercially reasonable efforts to ensure that the holders of the Convertible Redeemable Preferred Units will be entitled to receive a security issued by the surviving entity in the Cash Event with comparable powers, preferences and rights to the Convertible Redeemable Preferred Units. If the Partnership is unable to ensure that the holders of the Convertible Redeemable Preferred Units will be entitled to receive such a security, then the Partnership will be required to make an offer to the holders of the Convertible Redeemable Preferred Units to purchase their Convertible Redeemable Preferred Units for an amount equal to 120 percent of their Series A Liquidation Value. If the Partnership enters into any recapitalization, reorganization, consolidation, merger, spin-off that is not a Cash Event, the Partnership will make appropriate provisions to ensure that the holders of the Convertible Redeemable Preferred Units receive a security with comparable powers, preferences and rights to the Convertible Redeemable Preferred Units upon consummation of such transaction.

The September 30, 2009 accrued distributions of $1,945,000 was added to the value of Convertible Redeemable Preferred Units and will increase the number of common units that Convertible Redeemable Preferred may be converted beginning March 2, 2010 to 4,477,890 upon conversion.

Net proceeds from the issuance of Convertible Redeemable Preferred Units on September 2, 2009 was $76,800,000, of which $28,908,000 was allocated to the initial fair value of the embedded derivatives and recorded into long-term derivative liabilities on the balance sheet. The remaining $47,892,000 represented the initial value of the Convertible Redeemable Preferred Units and will be accreted to $80,000,000 by deducting the accretion amounts from partners’ capital over 20 years.

The following table presents the change in Convertible Redeemable Preferred Units for the nine months ended September 30, 2009.

	For the Nine Months Ended September 30, 2009
	(in thousands)
Beginning Balance		$	-
Issuance			47,892
Accretion			51
Accrued distribution			1,945
Ending Balance		$	49,888

9. Related Party Transactions

The employees operating the assets of the Partnership and its subsidiaries and all those providing staff or support services are employees of the General Partner. Pursuant to the Partnership Agreement, our General Partner receives a monthly reimbursement for all direct and indirect expenses incurred on behalf of the Partnership. Reimbursements of $8,289,000, $7,284,0000, $24,563,000, and $22,605,000 were recorded in the Partnership’s financial statements during the three and nine months ended September 30, 2009 and 2008, respectively, as operation and maintenance expenses or general and administrative expenses, as appropriate.

In conjunction with distributions by the Partnership to its limited and general partner interests, during the three and nine months ended September 30, 2009 and 2008, GE EFS received cash distributions of $1,865,000, $5,429,000, $1,679,000 and $2,801,000.

Under a Master Services Agreement with HPC, the Partnership operates and provides all employees and services for the operation and management of HPC. Under this agreement the Partnership will receive $500,000 monthly as a partial reimbursement of its general and administrative costs. The amount is recorded as fee revenue in the Partnership’s corporate and other segment. The Partnership also incurs expenditures on behalf of HPC and these amounts are billed to HPC on a monthly basis. Additionally, the Partnership’s gathering and processing and contract compression segments provide processing and contract compression services to HPC. As of and for the three and nine months ended September 30, 2009, the Partnership’s related party receivables, related party payables, related party revenues and related party cost of sales were primarily a result of the transactions described above.

On September 2, 2009, the Partnership purchased 52,650 units representing a five percent partner’s interest in HPC from EFS Haynesville for $63,000,000.

On February 26, 2009, the Partnership entered into a $45,000,000 unsecured revolving credit agreement with GECC. The proceeds of the GECC Credit Facility were available for expenditures made in connection with the Haynesville Expansion Project prior to the effectiveness of the above March 17, 2009 amendment. The commitments under the Revolving Credit Facility terminated on March 17, 2009. The Partnership paid a commitment fee of $2,718,000 to GECC related to this GECC Credit Facility, which was recorded as a decrease to gain on asset sales, net.

10. Segment Information

With the completion of the Contribution Agreement, the Partnership’s management realigned the composition of its segments. Accordingly, the Partnership has restated the items of segment information for earlier periods to reflect this new alignment.

The Partnership has three principal reportable segments: (a) gathering and processing, (b) transportation, and (c) contract compression. Gathering and processing involves collecting raw natural gas from producer wells and transporting it to treating plants where water and other impurities such as hydrogen sulfide and carbon dioxide are removed. Treated gas is then processed to remove the natural gas liquids. The treated and processed natural gas is then transported to market separately from the natural gas liquids. Revenues and the associated cost of sales from the gathering and processing segment directly expose the Partnership to commodity price risk, which is managed through derivative contracts and other measures. The Partnership aggregates the results of its gathering and processing activities across five geographic regions into a single reporting segment. The Partnership, through its producer services function, primarily purchases natural gas from producers at gathering systems and plants connected to its pipeline systems and sells this gas at downstream outlets.

Following the initial contribution of RIGS to HPC in March 2009, as well as the subsequent acquisition of an additional five percent interest in HPC, the transportation segment consists exclusively of the Partnership’s 43 percent interest in HPC, for which equity method accounting applies. Prior periods have been restated to reflect the Partnership’s then wholly owned subsidiary of Regency Intrastate Gas LLC as the exclusive reporting unit within this segment. The transportation segment uses pipelines to transport natural gas from receipt points on its system to interconnections with other pipelines, storage facilities or end-use markets. RIGS performs transportation services for shipping customers under firm or interruptible arrangements. In either case, revenues are primarily fee based and involve minimal direct exposure to commodity price fluctuations. The north Louisiana intrastate pipeline operated by this segment serves the Partnership’s gathering and processing facilities in the same area and those transactions create a portion of the intersegment revenues shown in the table below.

The contract compression segment provides customers with turn-key natural gas compression services to maximize their natural gas and crude oil production, throughput, and cash flow. The Partnership’s integrated solutions include a comprehensive assessment of a customer’s natural gas contract compression needs and the design and installation of a compression system that addresses those particular needs. The Partnership is responsible for the installation and ongoing operation, service, and repair of its compression units, which are modified as necessary to adapt to customers’ changing operating conditions. The contract compression segment also provides services to certain operations in the gathering and processing segment, creating a portion of the intersegment revenues shown in the table below.

The corporate and others segment comprises regulated entities and the Partnership’s corporate offices. Revenues in this segment include the collection of the partial reimbursement of general and administrative costs from HPC.

Management evaluates the performance of each segment and makes capital allocation decisions through the separate consideration of segment margin and operation and maintenance expenses. Segment margin, for the gathering and processing and for the transportation segments, is defined as total revenues, including service fees, less cost of sales. In the contract compression segment, segment margin is defined as revenues minus direct costs, which primarily consist of compressor repairs. Management believes segment margin is an important measure because it directly relates to volume, commodity price changes and revenue generating horsepower. Operation and maintenance expenses are a separate measure used by management to evaluate performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of operation and maintenance expenses. These expenses fluctuate depending on the activities performed during a specific period. The Partnership does not deduct operation and maintenance expenses from total revenues in calculating segment margin because management separately evaluates commodity volume and price changes in segment margin.

Results for each income statement period, together with amounts related to balance sheets for each segment are shown below.

	Gathering and Processing		Transportation		Contract Compression		Corporate and Others		Eliminations		Total
	(in thousands)
External Revenue
For the three months ended September 30, 2009	$	211,787	$	-	$	36,367	$	2,428	$	-	$	250,582
For the three months ended September 30, 2008		500,425		9,366