Edgar Filing: Regency Energy Partners LP

regencyenerypartnersform10q.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 March 31, 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. þ Yes o No

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). o Yes o No

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.

Large accelerated filer þ Accelerated filer o Non-accelerated filer (Do not check if a smaller reporting company) o Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes þ No

The issuer had 81,187,728 common units outstanding as of April 30, 2009.

	Page
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements		1
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		19
Item 3. Quantitative and Qualitative Disclosures About Market Risk		23
Item 4. Controls and Procedures
PART II — OTHER INFORMATION		23
Item 1. Legal Proceedings		23
Item 1A. Risk Factors		23
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		23
Item 6. Exhibits
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
EITF		Emerging Issues Task Force
El Paso		El Paso Field Services, LP
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FSP		Financial Accounting Standards Board Statement of Position
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 LLP, the general partner of Regency GP LP, which effectively manages the business and affairs of the Partnership
HPC		RIGS Haynesville Partnership Co., a general partnership that owns 100 percent of RIGS
Lehman		Lehman Brothers Holdings, Inc.
LIBOR		London Interbank Offered Rate
LTIP		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
NOE		Notice of Enforcement
NGLs		Natural gas liquids
Nasdaq		Nasdaq Stock Market, LLC
NYMEX		New York Mercantile Exchange
Partnership		Regency Energy Partners LP
RGS		Regency Gas Services LP
RIGS		Regency Intrastate Gas LP
Regency HIG		Regency Haynesville Intrastate Gas LLC, a wholly owned subsidiary of the Partnership
SEC		Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standard
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 can not 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:

·	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, 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.

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
(in thousands except unit data)

	March 31, 2009		December 31, 2008
	(unaudited)
ASSETS
Current Assets:
Cash and cash equivalents	$	6,578	$	599
Trade accounts receivable, net of allowance of $1,073 and $941		35,349		40,875
Accrued revenues		70,200		96,712
Related party receivables		4,998		855
Assets from risk management activities		67,020		73,993
Other current assets		7,911		23,369
Total current assets		192,056		236,403

Property, Plant and Equipment:
Gathering and transmission systems		449,971		652,267
Compression equipment		805,873		799,527
Gas plants and buildings		154,553		156,246
Other property, plant and equipment		152,089		167,256
Construction-in-progress		92,462		154,852
Total property, plant and equipment		1,654,948		1,930,148
Less accumulated depreciation		(204,256)		(226,594	)
Property, plant and equipment, net		1,450,692		1,703,554

Other Assets:
Investment in unconsolidated subsidiary		400,336		-
Long-term assets from risk management activities		26,944		36,798
Other, net of accumulated amortization of debt issuance costs of $6,292 and $5,246		17,723		13,880
Total other assets		445,003		50,678

Intangible Assets and Goodwill:
Intangible assets, net of accumulated amortization of $24,659 and $22,517		199,564		205,646
Goodwill		228,114		262,358
Total intangible assets and goodwill		427,678		468,004
TOTAL ASSETS	$	2,515,429	$	2,458,639

LIABILITIES & PARTNERS' CAPITAL AND NONCONTROLLING INTEREST
Current Liabilities:
Trade accounts payable	$	44,151	$	65,483
Accrued cost of gas and liquids		53,133		76,599
Related party payables		247		-
Deferred revenue, including related party amounts of $22 and $0		11,498		11,572
Liabilities from risk management activities		31,729		42,691
Other current liabilities		19,583		20,605
Total current liabilities		160,341		216,950

Long-term liabilities from risk management activities		-		560
Other long-term liabilities		15,247		15,487
Long-term debt		1,133,233		1,126,229

Commitments and contingencies

Partners' Capital and Noncontrolling Interest:
Common units (81,786,730 and 55,519,903 units authorized; 81,187,728 and 54,796,701 units issued and outstanding at March 31, 2009 and December 31, 2008)		1,108,752		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		25,495		29,283
Accumulated other comprehensive income		58,570		67,440
Noncontrolling interest		13,791		13,161
Total partners' capital and noncontrolling interest		1,206,608		1,099,413
TOTAL LIABILITIES AND PARTNERS' CAPITAL AND NONCONTROLLING INTEREST	$	2,515,429	$	2,458,639

See accompanying notes to condensed consolidated financial statements

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

	Three Months Ended March 31,
	2009			2008

REVENUES
Gas sales	$	148,270		$	236,692
NGL sales		49,585			108,499
Gathering, transportation and other fees, including related party amounts of $811 and $991		72,621			61,986
Net realized and unrealized gain (loss) from risk management activities		14,455			(13,657	)
Other		5,194			11,715
Total revenues		290,125			405,235

OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts of $247 and $403		182,901			313,589
Operation and maintenance		36,042			28,845
General and administrative		14,852			11,271
Gain on asset sales, net		(133,932	)		-
Management services termination fee		-			3,888
Depreciation and amortization		27,889			21,741
Total operating costs and expenses		127,752			379,334

OPERATING INCOME		162,373			25,901

Income from unconsolidated subsidiary		336			-
Interest expense, net		(14,227	)		(15,406	)
Other income and deductions, net		42			176
INCOME BEFORE INCOME TAXES		148,524			10,671
Income tax expense		100			251
NET INCOME	$	148,424		$	10,420
Net income attributable to noncontrolling interest		(35	)		(72	)
NET INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	148,389		$	10,348

General partner's interest, including IDR		3,533			776
Net income allocated to non-vested units		1,354			95
Beneficial conversion feature for Class D common units		820			1,559
Limited partners' interest	$	142,682		$	7,918

Basic and Diluted earnings per unit:
Amount allocated to common and subordinated units	$	142,682		$	7,918
Weighted average number of common and subordinated units outstanding		77,271,886			59,229,507
Basic income per common and subordinated unit	$	1.85		$	0.13
Diluted income per common and subordinated unit	$	1.78		$	0.13
Distributions per unit	$	0.445		$	0.40

Amount allocated to Class D common units	$	820		$	1,559
Total number of Class D common units outstanding		7,276,506			7,276,506
Income per Class D common unit due to beneficial conversion feature	$	0.11		$	0.21
Distributions per unit	$	-		$	-

Amount allocated to Class E common units	$	-		$	-
Total number of Class E common units outstanding		-			4,701,034
Income per Class E common unit	$	-		$	-
Distributions per unit	$	-		$	-

See accompanying notes to condensed consolidated financial statements

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

	Three Months Ended March 31,
	2009			2008

Net income	$	148,424		$	10,420
Net hedging amounts reclassified to earnings		(14,250	)		10,435
Net change in fair value of cash flow hedges		5,380			(2,834	)
Comprehensive income		139,554			18,021
Comprehensive income attributable to noncontrolling interest		(35	)		(72	)
Comprehensive income attributable to Regency Energy Partners LP	$	139,519		$	17,949

See accompanying notes to condensed consolidated financial statements

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

	Three Months Ended March 31,
	2009			2008
OPERATING ACTIVITIES
Net income	$	148,424		$	10,420
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization, including debt issuance cost amortization		28,932			22,398
Income from unconsolidated subsidiary		(336	)		-
Risk management portfolio valuation changes		(3,565	)		3,098
Gain on asset sales, net		(133,932	)		-
Unit based compensation expenses		1,189			794
Cash flow changes in current assets and liabilities:
Trade accounts receivable, accrued revenues, and related party receivables		22,741			(19,264	)
Other current assets		10,458			2,800
Trade accounts payable, accrued cost of gas and liquids, and related party payables		(36,948	)		25,950
Other current liabilities		(1,022	)		18,249
Other assets and liabilities		390			(6,907	)
Net cash flows provided by operating activities		36,331			57,538

INVESTING ACTIVITIES
Capital expenditures		(80,255	)		(97,896	)
Acquisitions		-			(574,059	)
Proceeds from asset sales		83,097			-
Net cash flows provided by (used in) investing activities		2,842			(671,955	)

FINANCING ACTIVITIES
Net borrowings under revolving credit facilities		7,004			609,000
Partner contributions		-			7,663
Partner distributions		(34,143	)		(24,341	)
Debt issuance costs		(6,055	)		-
Net cash flows provided by (used in) financing activities		(33,194	)		592,322

Net increase (decrease) in cash and cash equivalents		5,979			(22,095	)
Cash and cash equivalents at beginning of period		599			32,971
Cash and cash equivalents at end of period	$	6,578		$	10,876

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	5,502		$	5,047
Non-cash capital expenditures in accounts payable		18,241			18,517
Issuance of common units for an acquisition		-			219,590
Contribution of fixed assets, goodwill and working capital to RIGS Haynesville Partnership Co.		266,024			-

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			Class D			Subordinated			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		10,625		-			-			-			-			-			-			-			-		-
Conversion of subordinated units		19,103,896		-			(19,103,896	)		(1,391	)		-			1,391			-			-			-		-
Unit based compensation expenses		-		-			-			1,189			-			-			-			-			-		1,189
Partner distributions		-		-			-			(32,895	)		-			-			(1,248	)		-			-		(34,143	)
Net income		-		-			-			144,036			820			-			3,533			-			35		148,424
Conversion of Class D common units		7,276,506		(7,276,506	)		-			227,579			(227,579	)		-			-			-			-		-
Contributions from noncontrolling interest		-		-			-			-			-			-			-			-			595		595
Net hedging amounts reclassified to earnings		-		-			-			-			-			-			-			(14,250	)		-		(14,250	)
Net change in fair value of cash flow hedges		-		-			-			-			-			-			-			5,380			-		5,380
Balance - March 31, 2009		81,187,728		-			-		$	1,108,752		$	-		$	-		$	25,495		$	58,570		$	13,791	$	1,206,608

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 wholly owned subsidiaries. The Partnership and its subsidiaries are engaged in the business of gathering, processing, contract compression, transporting, and marketing natural gas and NGLs.

The unaudited financial information as of, and for the three months ended March 31, 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. 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 greater than 20 percent and where the Partnership lacks control over the investee.

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

	Permits and Licenses			Customer Contracts			Trade Names			Customer Relations			Total
	(in thousands)
Balance at December 31, 2008	$	8,582		$	126,799		$	32,848		$	37,417		$	205,646
Disposals		(2,932	)		-			-			-			(2,932	)
Amortization		(174	)		(1,807	)		(585	)		(584	)		(3,150	)
Balance at March 31, 2009	$	5,476		$	124,992		$	32,263		$	36,833		$	199,564

The weighted average amortization period for permits and licenses, customer contracts, trade names, and customer relations are 15, 24, 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 life 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)	$	9,064
2010		12,086
2011		10,828
2012		10,535
2013		10,535

Revision to Partners' Capital Accounts. In 2009, the Partnership revised the allocation of net income between the general partner and common unit holders from a previous period 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 SFAS No. 141(R), “Business Combinations” (“SFAS 141(R)”), which significantly changes the accounting for business acquisitions both during the period of the acquisition and in subsequent periods. The Partnership adopted SFAS 141(R) on January 1, 2009.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (“SFAS No. 160”), which significantly changes the accounting and reporting related to noncontrolling interests in a consolidated subsidiary. The Partnership adopted SFAS No. 160 for all periods presented. This statement requires the recognition of a noncontrolling interest (formerly styled as a minority interest) in partners’ capital in the 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 income statement.

In March 2008, the FASB issued EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships” (“EITF 07-4”). EITF 07-4 defines how to allocate net income among the various classes of equity, including incentive distribution rights (or “IDRs”), narrowing the number of currently acceptable methods. The standard became effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Earlier application was not permitted, and EITF 07-4 must be applied retrospectively for all financial statements presented. The adoption of this standard changes the Partnership’s method of allocating net income 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 IDR's 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 April 2008, FASB issued FSP No. 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP 142-3”), 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 FSP 142-3 is to better match the useful life of intangible assets to the cash flow generated. FSP 142-3 became effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. The adoption of FSP 142-3 did not impact the Partnership’s financial position, results of operations, or cash flows.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”), which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements that are presented in conformity of GAAP. SFAS 162’s effective date is November 15, 2008. The adoption of SFAS 162 did not have a material impact on the Partnership’s financial position, results of operations, or cash flows.

In June 2008, the FASB issued FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”) and is effective for fiscal years beginning after December 15, 2008. The adoption of this standard was applied retrospectively and had an imaterial impact on the Partnership’s earnings per unit.

2. Income 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. Under EITF No. 98-5, “Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios,” the 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.

The following table provides a reconciliation of the basic and diluted earnings per unit computations.

	For the Three Months Ended March 31, 2009						For the Three Months Ended March 31, 2008
	Income		Units		Per-Unit Amount		Income		Units		Per-Unit Amount
	(in thousands except unit and per unit data)
Basic Earnings per Unit
Limited Partners’ interest in net income	$	142,682		77,271,886	$	1.85	$	7,918		59,229,507	$	0.13
Effect of Dilutive Securities
Common unit options		-		-				-		207,817
Class D common units		820		3,234,003				1,559		7,276,506
Class E common units		-		-				-		4,701,034
Diluted Earnings per Unit	$	143,502		80,505,889	$	1.78	$	9,477		71,414,864	$	0.13

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.

	Three Months Ended
	March 31, 2009		March 31, 2008
Common unit options		328,618		-
Restricted common units		699,175		555,000

3. Disposition

On March 17, 2009, the Partnership announced the completion of the transactions contemplated by the Contribution Agreement (the “Contribution Agreement”) relating to a new joint venture arrangement among Regency HIG, GECC and the Alinda Investors. The Partnership contributed to HPC RIGS, which owns the Regency Intrastate Gas System, valued at $400,000,000, in exchange for a 38 percent general partnership interest in HPC. GECC and the Alinda Investors contributed $126,500,000 and $526,500,000 in cash, respectively, to HPC in return for a 12 percent and a 50 percent general partnership interest, respectively. In accordance with SFAS No. 160, the disposition and deconsolidation resulted in the recording of a $133,940,000 gain (of which $52,857,000 represents the remeasurement of the Partnership retained 38 percent interest to its fair value), net of transaction costs of $5,158,000.

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 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
	Three Months Ended
	March 31, 2009		March 31, 2008
	(in thousands except unit and per unit data)
Revenue	$	277,796	$	398,950

Net income attributable to Regency Energy Partners LP	$	10,970	$	145,803
Less:
General partner's interest, including IDR		785		2,920
Non-vested common unit holders' interest		90		1,404
Beneficial conversion feature for Class D common units		820		1,559
Limited partners' interest in net income	$	9,275	$	139,919

Basic and Diluted earnings per unit:
Amount allocated to common and subordinated units	$	9,275	$	139,919
Weighted average number of common and subordinated units outstanding		77,271,886		59,229,507
Basic income per common and subordinated unit	$	0.12	$	2.36
Diluted income per common and subordinated unit	$	0.12	$	2.01
Distributions per unit	$	0.445	$	0.40

Amount allocated to Class D common units	$	820	$	1,559
Total number of Class D common units outstanding		7,276,506		7,276,506
Basic and diluted income per Class D common unit due to beneficial conversion feature	$	0.11	$	0.21
Distributions per unit	$	-	$	-

Amount allocated to Class E common units	$	-	$	-
Weighted average number of Class E common units outstanding		-		4,701,034
Basic and diluted income per Class E common unit	$	-	$	-
Distributions per unit	$	-	$	-

4. Investment in Unconsolidated Subsidiary

As described in the Disposition footnote, the Partnership contributed RIGS to HPC for a 38 percent general partner interest in HPC. The summarized financial information of HPC as of March 31, 2009 and for the period from inception (March 18, 2009) to March 31, 2009 is disclosed below in accordance with Rule 4-08 of Regulation S-X. The Partnership recognized $336,000 in investing income from unconsolidated subsidiary for its 38 percent ownership interest from inception (March 18, 2009) to March 31, 2009.

Condensed Consolidated Balance Sheet
March 31, 2009
Unaudited
(in thousands)
ASSETS
Total current assets	$	537,178
Property, plant and equipment, net		481,143
Total other assets		61,564
TOTAL ASSETS	$	1,079,885
LIABILITIES & PARTNERS' CAPITAL
Total current liabilities	$	26,001
Partners' capital		1,053,884
TOTAL LIABILITIES & PARTNERS' CAPITAL	$	1,079,885

Condensed Consolidated Income Statement
From Inception (March 18, 2009) to March 31, 2009
Unaudited
(in thousands)
Total revenues	$	1,826
Total operating costs and expenses, including depreciation expense of $669		1,046
OPERATING INCOME		780
Other income and deductions, net		104
NET INCOME	$	884

5. Risk Management Activities

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 requires enhanced disclosures about derivative and hedging activities. The Partnership adopted this standard as of January 1, 2009 and its adoption had no impact on the results of operations or cash flows.

Risk and Accounting Policies. The Partnership is exposed to market risks associated with commodity prices, counterparty credit, and interest rates. The Partnership established comprehensive risk management policies and procedures to monitor and manage these market risks. 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 credit risk and commodity price risk, including monitoring exposure limits. The Risk Management Committee receives regular briefings on positions and exposures, credit 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, processing and marketing 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 markets 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 marketing positions. 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 market uncertainty. 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 our 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 natural gas, NGLs and condensate volumes produced for its account in the approximate percentages set for below:

	2009			2010
NGL		97	%		36	%
Condensate		75			76
Natural gas		83			-

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 dedesignated swaps continued to serve as economic hedges against price exposure for the Partnership. At March 31, 2009, the Partnership has the following commodity hedging programs that qualify as cash flow hedges: the 2009 NGLs, natural gas and West Texas Intermediate crude oil hedging programs and the 2010 West Texas Intermediate crude oil hedging program.

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 under SFAS 133 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 do not qualify for cash flow hedging 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.

On December 2, 2008, the Partnership entered into two natural gas swaps to hedge its equity exposure to natural gas for 2009. These natural gas swaps were designated as cash flow hedges on December 2, 2008.

Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of borrowings under our existing credit facility. As of March 31, 2009, we had $475,733,000 of outstanding long-term balances exposed to variable interest rate risk. An increase of 100 basis points in the LIBOR rate would increase our annual payment by $4,757,000. 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 March 31, 2009) through March 5, 2010. These interest rate swaps were designated as cash flow hedges in March 2008.

Credit Risk. The Partnership’s purchase and 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. 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 parental guarantee.

The Partnership is exposed to credit risk from it derivative counterparties. The Partnership does not require collateral from these counterparties. If the Partnership’s counterparties failed to perform under existing swap contracts, the Partnership would experience a loss of $96,213,000 based on commodity forward curve pricing as of March 31, 2009. The Partnership has entered into Master International Swap Dealers Association 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 maximium loss of $96,213,000 would be reduced by $27,394,000 due to the netting feature.

Quantitative Disclosures. The Partnership expects to reclassify $49,112,000 of net hedging gains to revenues or interest expense from accumulated other comprehensive income in the next twelve months.

The Partnership’s risk management activities assets and liabilities, including its SFAS No. 157, “Fair Value Measurements” (“SFAS 157”) credit risk adjustment, are detailed below for the periods ended March 31, 2009 and December 31, 2008.

	Asset Derivatives Fair Value
	March 31, 2009			December 31, 2008
	(in thousands)
Derivatives designated as cash flow hedging instruments
Current assets from risk management activities
Commodity contracts	$	53,436		$	59,882
Long-term assets from risk management activities
Commodity contracts		10,133			13,373
Total cash flow hedging instruments		63,569			73,255

Derivatives not designated as hedging instruments
Current assets from risk management activities
Commodity contracts		15,833			16,001
Long-term assets from risk management activities
Commodity contracts		16,811			23,425
Total derivatives not designated as hedging instruments		32,644			39,426

SFAS 157 Credit Risk Assessment
Current assets from risk management activities		(2,249	)		(1,890	)
Total assets from risk management activities	$	93,964		$	110,791

	Liability Derivatives Fair Value
	March 31, 2009			December 31, 2008
	(in thousands)
Derivatives designated as cash flow hedging instruments
Current liabilities from risk management activities
Interest rate contracts	$	4,605		$	4,680
Long-term liabilities from risk management activities
Interest rate contracts		-			560
Total cash flow hedging instruments		4,605			5,240

Derivatives not designated as hedging instruments
Current liabilities from risk management activities
Commodity contracts		27,394			38,402
Total derivatives not designated as hedging instruments		27,394			38,402

SFAS 157 credit risk assessment
Current liabilities from risk management activities		(270	)		(391	)
Total liabilities from risk management activities	$	31,729		$	43,251

The Partnership’s statement of operations for the periods ended March 31, 2009 and 2008 were impacted by risk management activities as follows.

Derivatives in Cash Flow Hedging Relationships
	Amount of Gain (Loss) Recognized in OCI on Derivative (Effective Portion)				Location of:	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)					Amount of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion)
		March 31, 2009		March 31, 2008			March 31, 2009		March 31, 2008			March 31, 2009		March 31, 2008
(in thousands)
Interest rate contracts		$ (838)	$	(421)	Interest expense, net		$ (1,472)	$	188	$		-	$	-
Commodity contracts		6,218		(2,413)	Net realized and unrealized gain(loss) from risk management activities		16,519		(10,567)		$	615		223

Total	$	5,380	$	(2,834)		$	$15,047	$	(10,567)		$	615	$	223
Derivatives Not in SFAS 133 Hedging Relationships
		Amount of Loss from Dedesignation Amortized from Accumulated OCI into Income					Amount of Gain (Loss) Recognized in Income on Derivative
		March 31, 2009		March 31, 2008