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.

9

---

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

 

10

---

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					March 31, 2009			March 31, 2008
Net realized and unrealized gain (loss) from risk management activities for commodity contracts		$	(797)		$	(56)				$	(1,402)		$	(3,257)
SFAS 157 Credit Risk Assessment for All Derivatives								Location of :			Amount of Gain or (Loss) Recognized in Income on Derivative
											March 31, 2009			March 31, 2008
Commodity and interest rate swaps								Net realized and unrealized gain/(loss) from risk management activities		$	(480)		$	-

 

6.  Long-term Debt

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

 

		March 31, 2009			December 31, 2008
		(in thousands)
Senior notes		$	357,500		$	357,500
Revolving loans			775,733			768,729
Total			1,133,233			1,126,229
Less: current portion			-			-
Long-term debt		$	1,133,233		$	1,126,229
Availability under revolving credit facility:
Total credit facility limit		$	900,000		$	900,000
Unfunded Lehman commitments			(5,578	)		(8,646	)
Revolving loans			(775,733	)		(768,729	)
Letters of credit			(16,257	)		(16,257	)
Total available		$	102,432		$	106,368

 

11

---

On March 17, 2009, RGS closed on Amendment No. 7 to its Credit Agreement (the “Amendment”).  The Amendment authorized the contribution of RIGS to a joint venture (HPC) and allowed 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 LIBOR rate for a borrowing with a one-month interest period 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.

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 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 in 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 of March 31, 2009, the Partnership borrowed all but $5,578,000 of the amount committed by Lehman under the Credit Facility.  Lehman has declined requests to honor its remaining commitment, effectively reducing the total size of the Credit Facility’s capacity to $894,422,000.  Further, if the Partnership makes repayments of loans against the revolving 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 5.19 percent and 6.90 percent for the three months ended March 31, 2009 and 2008, respectively.  The senior notes bear interest at a fixed rate of 8.375 percent.

The senior notes are guaranteed by each of the Partnership’s current subsidiaries (the “Guarantors”) as of March 31, 2009, with the exception of WGP-KHC, LLC and Finance Corp.  Since certain wholly owned subsidiaries do not guarantee the senior notes, the condensed consolidating financial statements of the guarantors and non-guarantors are disclosed below in accordance with Rule 3-10 of Regulation S-X.

 

Condensed Consolidating Balance Sheets
March 31, 2009
Unaudited
		Guarantors			Non Guarantors			Consolidated
		(in thousands)
Assets
Total current assets		$	167,969		$	24,087		$	192,056
Property, plant and equipment, net			1,359,530			91,162			1,450,692
Total other assets			445,003			-			445,003
Total intangible and goodwill			427,678			-			427,678
Total Assets		$	2,400,180		$	115,249		$	2,515,429
Liabilities & Partners’ Capital and Noncontrolling Interest
Total current liabilities		$	154,881		$	5,460		$	160,341
Other long-term liabilities			15,247			-			15,247
Long-term debt			1,133,233			-			1,133,233
Partners' capital and noncontrolling interest			1,096,819			109,789			1,206,608
Total Liabilities & Partners’ Capital and Noncontrolling Interest		$	2,400,180		$	115,249		$	2,515,429

 

 

12

---

 

 

Condensed Consolidating Balance Sheets
December 31, 2008
Unaudited
		Guarantors			Non Guarantors			Consolidated
		(in thousands)
Assets
Total current assets		$	212,712		$	23,691		$	236,403
Property, plant and equipment, net			1,612,387			91,167			1,703,554
Total other assets			50,678			-			50,678
Total intangible and goodwill			468,004			-			468,004
Total Assets		$	2,343,781		$	114,858		$	2,458,639
Liabilities & Partners’ Capital and Noncontrolling Interest
Total current liabilities		$	210,241		$	6,709		$	216,950
Long-term liabilities from risk management activities			560			-			560
Other long-term liabilities			15,487			-			15,487
Long-term debt			1,126,229			-			1,126,229
Partners' capital and noncontrolling interest			991,264			108,149			1,099,413
Total Liabilities & Partners’ Capital and Noncontrolling Interest		$	2,343,781		$	114,858		$	2,458,639

 

Condensed Consolidating Income Statements
For the Three Months Ended March 31, 2009
Unaudited
		Guarantors			Non Guarantors			Consolidated
		(in thousands)
Total revenues		$	278,561		$	11,564		$	290,125
Total operating costs and expenses			117,826			9,926			127,752
Operating Income			160,735			1,638			162,373
Investing income from unconsolidated subsidiary			336			-			336
Interest expense, net			(14,227)			-			(14,227	)
Other income and deductions, net			41			1			42
Income before Income Taxes			146,885			1,639			148,524
Income tax expense			100			-			100
Net Income			146,785			1,639			148,424
Net income attributable to noncontrolling interest			(35)			-			(35	)
Net income attributable to Regency Energy Partners LP		$	146,750		$	1,639		$	148,389

 

Condensed Consolidating Income Statements
For the Three Months Ended March 31, 2008
Unaudited
		Guarantors			Non Guarantors			Consolidated
		(in thousands)
Total revenues		$	393,048		$	12,187		$	405,235
Total operating costs and expenses			369,882			9,452			379,334
Operating Income			23,166			2,735			25,901
Interest expense, net			(15,406	)		-			(15,406	)
Other income and deductions, net			182			(6	)		176
Income before Income Taxes			7,942			2,729			10,671
Income tax expense			251			-			251
Net Income			7,691			2,729			10,420
Net income attributable to noncontrolling interest			(72	)		-			(72	)
Net income attributable to Regency Energy Partners LP		$	7,619		$	2,729		$	10,348

 

Condensed Consolidating Statements of Cash Flows
For the Three Months Ended March 31, 2009
Unaudited
		Guarantors			Non Guarantors			Consolidated
		(in thousands)
Net cash flows provided by operating activities		$	33,356		$	2,975		$	36,331
Net cash flows provided by (used in) investing activities			5,817			(2,975	)		2,842
Net cash flows used in financing activities			(33,194	)		-			(33,194	)

 

Condensed Consolidating Statements of Cash Flows
For the Three Months Ended March 31, 2008
Unaudited
		Guarantors			Non Guarantors			Consolidated
		(in thousands)
Net cash flows provided by operating activities		$	61,220		$	(3,682	)	$	57,538
Net cash flows provided by (used in) investing activities			(671,488	)		(467	)		(671,955	)
Net cash flows used in financing activities			592,322			-			592,322

 

13

---

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 March 31, 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 our 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.

Contingent Purchase of Sonat Assets.  In March of 2008, the Partnership, through the Nexus Acquisition, obtained the rights to a contingent commitment to purchase 136 miles of pipeline that could facilitate the Nexus’ system integration into the Partnership’s north Louisiana asset base.  The purchase commitment was contingent upon the FERC declaring that the pipeline is no longer subject to its jurisdiction, together with approval of the current owner’s abandonment and other customary closing conditions.  On April 3, 2008, Sonat filed an application with the FERC seeking authorization to abandon by sale to Nexus 136 miles of pipeline and related facilities.  The application also requested a determination that the facilities being sold to Nexus be considered non-jurisdictional, with certain facilities being gathering and certain facilities being intrastate transmission.  On March 19, 2009, FERC denied the Sonat abandonment application and this obligation has been terminated.

TCEQ Notice of Enforcement. On February 15, 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.  On April 3, 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 processing plant in southwest Kansas.  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 of which the Partnership no longer delivered any helium to Keyes.  As a result, Keyes alleges it is entitled to an unspecified amount of damages for the costs of covering its purchases of helium.  The Partnership filed an answer to this lawsuit and plans to defend itself vigorously.

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 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.  If the Kansas Department of Revenue determines that the condensate sales are taxable, then the Partnership may be subject to additional taxes for past and future condensate sales.

8.  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 $7,808,000, and $6,888,000 were recorded in the Partnership’s financial statements during the three months ended March 31, 2009 and 2008, respectively, as operating expenses or general and administrative expenses, as appropriate.

In conjunction with distributions by the Partnership to its limited and general partner interests, GE EFS and certain members of management received cash distributions of $9,578,000 and $390,000, respectively during the three months ended March 31, 2009.

The Partnership’s contract compression segment provides contract compression services to CDM MAX, LLC and HPC.  At March 31, 2009, the Partnership has a $398,000 receivable related to CDM MAX, LLC and a $59,000 receivable related to HPC.

Under a Master Services Agreement with HPC, the Partnership operates and provides all employees and services for the operation and management of the joint venture.  Under this agreement the Partnership will receive $500,000 monthly as a management fee.  In the three months ended March 31, 2009, the Partnership received a partial month management fee of $226,000.   At March 31, 2009, the Partnership has $4,354,000 in receivables from HPC.

At March 31, 2009, the Partnership had a receivable of $187,000 from GE EFS.

14

---

9.  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 contribution of RIGS to HPC, the transportation segment consists exclusively of the Partnership’s 38 percent interest in HPC, for which equity method accounting applies.  Prior periods have been restated to reflect the Partnership’s wholly owned subsidiary of Regency Intrastate Gas Pipeline 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 larger pipelines or trading hubs and other 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.  RIGS also purchases natural gas at the inlets to the pipeline and sells this gas at its outlets.  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 a small regulated interstate pipeline and the Partnership’s corporate offices.  Revenues in this segment derive from the operations of the regulated interstate pipeline which, prior to the realignment of the segments, was reported within the transportation segment.

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.

 

15

---

 

		Gathering and Processing			Transportation			Contract Compression			Corporate and Others			Eliminations			Total
		(in thousands)
External Revenue
For the three months ended March 31, 2009		$	247,822		$	3,538		$	38,488		$	277		$	-		$	290,125
For the three months ended March 31, 2008			370,425			9,343			25,267			200			-			405,235
Intersegment Revenue
For the three months ended March 31, 2009			70,764			8,791			810			-			(80,365	)		-
For the three months ended March 31, 2008			31,810			4,150			118			-			(36,078	)		-
Cost of Sales
For the three months ended March 31, 2009			259,438			775			2,317			(153	)		(79,476	)		182,901
For the three months ended March 31, 2008			346,989			239			2,364			-			(36,003	)		313,589
Segment Margin
For the three months ended March 31, 2009			59,148			11,554			36,981			430			(889	)		107,224
For the three months ended March 31, 2008			55,246			13,254			23,021			200			(75	)		91,646
Operation and Maintenance
For the three months ended March 31, 2009			22,636			2,286			12,540			28			(1,448	)		36,042
For the three months ended March 31, 2008			18,627			1,391			8,844			6			(23	)		28,845
Depreciation and Amortization
For the three months ended March 31, 2009			17,058			2,448			8,027			356			-			27,889
For the three months ended March 31, 2008			12,670			3,464			5,354			253			-			21,741
Assets
March 31, 2009			1,059,720			405,315			913,649			136,251			494			2,515,429
December 31, 2008			1,103,770			325,310			881,552			148,007			-			2,458,639
Investment in Unconsolidated Subsidiary
March 31, 2009			-			400,336			-			-			-			400,336
December 31, 2008			-			-			-			-			-			-
Goodwill
March 31, 2009			63,232			-			164,882			-			-			228,114
December 31, 2008			63,232			34,244			164,882			-			-			262,358
Expenditures for Long-Lived Assets
For the three months ended March 31, 2009			23,804			22,367			34,032			52			-			80,255
For the three months ended March 31, 2008			35,219			1,015			61,299			363			-			97,896

 

The table below provides a reconciliation of total segment margin to net income.

		Three Months Ended
		March 31, 2009			March 31, 2008
		(in thousands)
Net income attributable to Regency Energy Partners LP		$	148,389		$	10,348
Add (deduct):
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
Investing income from unconsolidated subsidiary			(336	)		-
Interest expense, net			14,227			15,406
Other income and deductions, net			(42	)		(176	)
Income tax expense			100			251
Net income attributable to the noncontrolling interest			35			72
Total segment margin		$	107,224		$	91,646

 

10.  Equity-Based Compensation

In December 2005, the General Partner approved a LTIP for the Partnership’s employees, directors, and consultants covering an aggregate of 2,865,584 common units.  LTIP awards generally vest on the basis of one-fourth of the award each year.  The Partnership expects to recognize $13,646,000 of compensation expense related to the non-vested grants over a weighted average period of approximately two-and-a-half years.  All outstanding options are vested and expire ten years after the grant date.

 

16

---

 

The Partnership makes distributions to non-vested restricted common units at the same rate as the common units. Restricted common units are subject to contractual restrictions against transfer which lapse over time; non-vested restricted units are subject to forfeitures on termination of employment. Upon exercise of the common unit options, the Partnership anticipates settling these obligations with common units.

The restricted (non-vested) units and common unit options activity for the three months ended March 31, 2009 are as follows.

 

Restricted (Non-Vested) Units	Units			Weighted Average Grant Date Fair Value
Outstanding at beginning of period		704,050		$	29.26
Granted		20,000			10.81
Vested		(45,500	)		30.99
Forfeited or expired		(9,375	)		31.58
Outstanding at end of period		669,175		$	28.56

 

Common Unit Options		Units			Weighted Average Exercise Price			Weighted Average Contractual Term (Years)			Aggregate Intrinsic Value* (in thousands)
Outstanding at beginning of period			431,918		$	21.31
Granted			-			-
Exercised			-			-
Forfeited or expired			(103,300	)		21.05
Outstanding at end of period			328,618			21.40			7.04		$	-
Exercisable at end of period			328,618

* Intrinsic value equals the closing market price of a unit less the option strike price, multiplied by the number of unit options outstanding as of the end of the period presented.  Unit options with an exercise price greater than the end of the period closing market price are excluded.

17

---

11.  Fair Value Measures

On January 1, 2008, the Partnership adopted the provisions of SFAS 157 for financial assets and liabilities.  On January 1, 2009, the Partnership applied the provisions of SFAS 157 for non-recurring fair value measurements of non-financial assets and liabilities, such as goodwill, indefinite-lived intangible assets, property, plant and equipment and asset retirement obligations.  SFAS 157 establishes a three-tiered fair value hierarchy that prioritizes inputs to valuation techniques used in fair value calculations.  The three levels of inputs are defined as follows:

·	Level 1- unadjusted quoted prices for identical assets or liabilities in active markets accessible by the Partnership;
·	Level 2- inputs that are observable in the marketplace other than those classified as Level 1; and
·	Level 3- inputs that are unobservable in the marketplace and significant to the valuation.

SFAS 157 encourages entities to maximize the use of observable inputs and minimize the use of unobservable inputs.  If a financial instrument uses inputs that fall in different levels of the hierarchy, the instrument will be categorized based upon the lowest level of input that is significant to the fair value calculation.

The Partnership’s financial assets and liabilities measured at fair value on a recurring basis are risk management assets and liabilities related to interest rate and commodity swaps.  Risk management assets and liabilities are valued using discounted cash flow techniques.  These techniques incorporate Level 1 and Level 2 inputs such as future interest rates and commodity prices.  These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk and are classified as Level 2 in the hierarchy.  The Partnership has no financial assets and liabilities as of March 31, 2009 valued based on inputs classified as Level 3 in the hierarchy.

The estimated fair value of financial instruments was determined using available market information and valuation methodologies.  The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to their short-term maturities.  Restricted cash and related escrow payable approximates fair value due to the relatively short-term settlement period of the escrow payable.  Risk management assets and liabilities are carried at fair value.  Long-term debt other than the senior notes is comprised of borrowings under which, accrues interest under a floating interest rate structure.  Accordingly, the carrying value approximates fair value for the long term debt amounts outstanding.  The estimated fair value of the senior notes based on third party market value quotations was $307,450,000 as of March 31, 2009.

12.  Subsequent Event

On April 27, 2009, the Partnership declared a distribution of $0.445 per outstanding common unit including units equivalent to the General Partner’s two percent interest in the Partnership, and an aggregate distribution of approximately $634,000, with respect to incentive distribution rights, payable on May 14, 2009 to unitholders of record at the close of business on May 7, 2009.

 

Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion analyzes our financial condition and results of operations.  You should read the following discussion of our financial condition and results of operations in conjunction with our unaudited condensed consolidated financial statements and notes included elsewhere in this document.

 

 

18

---

 

OVERVIEW. We are a growth-oriented publicly-traded Delaware limited partnership engaged in the gathering, processing, contract compression, marketing, and transportation of natural gas and NGLs. We provide these services through systems located in Louisiana, Texas, Arkansas, and the mid-continent region of the United States, which includes Kansas and Oklahoma.

RECENT DEVELOPMENTS.

Joint Venture Formation.  On March 17, 2009, the Partnership announced the completion of the transactions included in 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.

HPC was formed to finance the construction and development of the Partnership’s previously announced expansion of its existing natural gas pipeline in north Louisiana and to operate the Regency Intrastate Gas System.

Drilling and Pricing Pressure Trends.

General.  Other than in north Louisiana, south Texas and Arkansas where prolific natural gas shale reservoirs are believed to exist, we continue to see a decline in drilling activity in our operating regions.  As long as oil and gas prices remain at current levels, we believe that drilling activity will continue to remain low.  Currently, we believe that drilling levels are not sufficient to meet ongoing demand and that higher prices will be needed for drilling levels to rise to recent historical levels.  Management cannot predict the timing of higher natural gas prices, but if prices remain at current levels for an extended period of time, our business operations could be adversely impacted.

Contract Compression Segment.  As a result of depressed natural gas prices, decreased drilling activity, and overall deteriorating economic conditions, our natural gas contract compression segment is experiencing a challenging environment in re-applying horsepower that comes up for contract renewal.  Though overall applied horsepower increased slightly for the three month period ending March 31, 2009, compared to levels experienced during 2008, we anticipate continued challenges in redeploying horsepower that comes up for renewal as well as new horsepower sets during the near term.

OUR OPERATIONS.  We manage our business and analyze and report our results of operations through three business segments.

·	Gathering and Processing:  We provide “wellhead-to-market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs from the raw natural gas and selling or delivering the pipeline-quality natural gas and NGLs to various markets and pipeline systems;
·	Transportation:  We own a 38 percent interest in HPC that delivers natural gas from northwest Louisiana to more favorable markets in northeast Louisiana through a 320-mile intrastate pipeline system; and
·	Contract Compression:  We provide customers with turn-key natural gas compression services to maximize their natural gas and crude oil production, throughput, and cash flow.  Our 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.  We are responsible for the installation and ongoing operation, service, and repair of our compression units, which we modify as necessary to adapt to our customers’ changing operating conditions.

HOW WE EVALUATE OUR OPERATIONS.  Our management uses a variety of financial and operational measurements to analyze our performance.  We view these key performance indicators as important tools for evaluating the success of our operations and review these key performance indicators on a monthly basis for consistency and trends.  For our gathering and processing and transportation segments, the key performance indicators include volumes, segment margin, and operating and maintenance expenses.  For our contract compression segment, the key performance indicators include revenue generating horsepower, average horsepower per revenue generating compression unit, segment margin, and operation and maintenance expenses.  Management also reviews EBITDA for each reportable segment and in total to analyze performance.

Volumes.  We must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our gathering and processing systems.  Our ability to maintain existing supplies of natural gas and obtain new supplies is affected by (a) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our pipelines, (b) our ability to compete for volumes from successful new wells in other areas and (c) our ability to obtain natural gas that has been released from other commitments.  We routinely monitor producer activities in the areas served by our gathering and processing systems to pursue new supply opportunities.

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

Revenue Generating Horsepower.  Revenue generating horsepower growth is the primary driver for revenue growth in the contract compression segment, and it is also the base measure for evaluating our operational efficiency.  Revenue generating horsepower is our total available horsepower less horsepower under contract that is not generating revenue and idle horsepower.

 

Average Horsepower per Revenue Generating Compression Unit.  We calculate average horsepower per revenue generating compression unit as our revenue generating horsepower divided by the number of revenue generating compression units.

Segment Margin.  We calculate our gathering and processing segment margin as our revenue generated from our gathering and processing operations minus the cost of natural gas and NGLs purchased and other cost of sales, including third-party transportation and processing fees.  Revenue includes revenue from the sale of natural gas and NGLs resulting from these activities and fixed fees associated with the gathering and processing of natural gas. We also generally purchase pipeline-quality natural gas at a pipeline inlet price adjusted to reflect our transportation fee and we sell that gas at the pipeline outlet.

Prior to our contribution of our Regency Intrastate Gas System to HPC, we calculated our transportation segment margin as revenue generated by fee income as well as, in those instances in which we purchase and sell gas for our account, gas sales revenue minus the cost of natural gas that we purchase and transport.  Revenue primarily includes fees for the transportation of pipeline-quality natural gas and the margin generated by sales of natural gas transported for our account.  Most of our segment margin is fee-based with little or no commodity price risk.

After our contribution of RIGS to HPC, we will not record segment margin for the transportation segment because the income attributable to HPC will be recorded as income from unconsolidated subsidiary.  Because of the materiality of HPC to the Partnership, we are providing a discussion of HPC’s results of operations and cash distributions.

We calculate our contract compression segment margin as our revenues generated from our contract compression operations minus the direct costs, primarily compressor unit repairs, associated with those revenues.

Total Segment Margin.  Segment margin from gathering and processing, transportation, contract compression and inter-segment eliminations comprise total segment margin.  We use total segment margin as a measure of performance.  The reconciliation of the non-GAAP financial measure, total segment margin, to its most directly comparable GAAP measure, net income, is included in Note 9, Segment Information, within the condensed consolidated financial statements included in Item 1 of this report.

 

19

---

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

EBITDA.  We define EBITDA as net income plus interest expense, provision for income taxes and depreciation and amortization expense.  EBITDA is used as a supplemental measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

·	financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
·	the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our unitholders and general partners;
·	our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and
·	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

 

EBITDA should not be considered as an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP.  EBITDA is the starting point in determining cash available for distribution, which is an important non-GAAP financial measure for a publicly traded master limited partnership.  The following table reconciles the non-GAAP financial measure, EBITDA, to its most directly comparable GAAP measures, net income and net cash flows provided by operating activities.

 

		Three Months Ended
		March 31, 2009			March 31, 2008
		(in thousands)
Net cash flows provided by operating activities		$	36,331		$	57,538
Add (deduct):
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			133,932			-
Unit based compensation expenses			(1,189)			(794	)
Changes in current assets and liabilities:
Trade accounts receivables and accrued revenues			(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 income attributable to the noncontrolling interest			(35)			(72	)
Net income attributable to Regency Energy Partners LP		$	148,389		$	10,348
Add:
Interest expense, net			14,227			15,406
Depreciation and amortization			27,889			21,741
Income tax expense			100			251
EBITDA		$	190,605		$	47,746

 

CASH DISTRIBUTIONS.  On April 27, 2009, the Partnership declared a distribution of $0.445 per outstanding common unit including units equivalent to the General Partner’s two percent interest in the Partnership, and an aggregate distribution of approximately $634,000, with respect to incentive distribution rights, payable on May 14, 2009 to unitholders of record at the close of business on May 7, 2009.

20

---

RESULTS OF OPERATIONS

Partnership

Three Months Ended March 31, 2009 vs. Three Months Ended March 31, 2008

 

		Three Months Ended
		March 31, 2009			March 31, 2008			Change			Percent
		(in thousands except percentages and volume data)
Revenues		$	290,125		$	405,235		$	(115,110	)		28	%
Cost of sales			182,901			313,589			(130,688	)		42
Total segment margin (1)			107,224			91,646			15,578			17
Operation and maintenance			36,042			28,845			7,197			25
General and administrative			14,852			11,271			3,581			32
Gain on asset sales, net			(133,932	)		-			(133,932	)		N/M
Management services termination fee			-			3,888			(3,888	)		N/M
Depreciation and amortization			27,889			21,741			6,148			28
Operating income			162,373			25,901			136,472			527
Income from unconsolidated subsidiary			336			-			336			N/M
Interest expense, net			(14,227	)		(15,406	)		1,179			8
Other income and deductions, net			42			176			(134	)		76
Income tax expense			(100	)		(251	)		151			60
Net income attributable to noncontrolling interest			(35	)		(72	)		37			51
Net income attributable to Regency Energy Partners LP		$	148,389		$	10,348		$	138,041			1,334	%
System inlet volumes (MMbtu/d) (2)			1,618,342			1,378,932			239,410			17
Revenue generating horsepower (3)			789,494			615,852			173,642			28

(1) For a reconciliation of total segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Item 1. Financial Statements – Note 9, Segment Information.”

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

(3) Revenue generating horsepower is our total available horsepower less horsepower under contract that is not generating revenue and idle horsepower.

N/M – not meaningful

 

 

21

---

 

 

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

 

		Three Months Ended
		March 31, 2009			March 31, 2008			Change			Percent
		(in thousands except percentage and volume data)
Segment Financial and Operating Data:
Gathering and Processing Segment
Financial data:
Segment margin (1) (2)		$	59,148		$	55,246		$	3,902			7	%
Operation and maintenance (3)			22,636			18,627			4,009			22
Operating data:
Throughput (MMbtu/d) (4)			1,038,707			918,950			119,757			13
NGL gross production (Bbls/d)			22,721			23,068			(347	)		2
Transportation Segment
Financial data:
Segment margin (1) (2)		$	11,554		$	13,254		$	(1,700	)		13	%
Operation and maintenance (3)			2,286			1,391			895			64
Operating data:
Throughput (MMbtu/d) (4)			812,332			732,006			80,326			11
Contract Compression Segment
Financial data:
Segment margin (1)		$	36,981		$	23,021		$	13,960			61	%
Operation and maintenance (3)			12,540			8,844			3,696			42
Operating data:
Revenue generating horsepower (5)			789,494			615,852			173,642			28
Average horsepower per revenue
generating compression unit			858			849			9			1
Corporate and Others
Financial data:
Segment margin (1) (2)		$	430		$	200		$	230			115	%
Operation and maintenance (3)			28			6			22			367

 

(1) For a reconciliation of segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read "Item 1. Financial Statements-Note 9, Segment Information."  Combined segment margin varies from consolidated total segment margin due to inter-segment eliminations between the contract compression, transportation, and gathering and processing segments.

(2) Segment margins differ from previously disclosed amounts due to functional reorganization of our operating segments.

(3) Combined operation and maintenance expense varies from consolidated operation and maintenance expense due to inter-segment eliminations between the contract compression, transportation, and gathering and processing segments.

(4) Combined throughput volumes for the gathering and processing and transportation segments vary from consolidated system inlet volumes due to inter-segment eliminations.

(5) Revenue generating horsepower is our total available horsepower less horsepower under contract that is not generating revenue and idle horsepower

 

In addition to the revenue generating horsepower and units owned and operated by the contract compression segment disclosed below, the contract compression segment operates 170,000 horsepower owned by the gathering and processing and transportation segments as of March 31, 2009.

		March 31, 2009
					Percentage of
		Revenue Generating			Revenue Generating			Number of
Horsepower Range		Horsepower			Horsepower			Units
0-499			62,147			8	%		360
500-999			80,587			10	%		129
1,000			646,760			82	%		431
			789,494			100	%		920

 

Net Income Attributable to the Partnership.  Net income attributable to the Partnership for the three months ended March 31, 2009 was $148,389,000 compared to $10,348,000 in the three months ended March 31, 2008, a 1,334 percent increase.  The increase in net income attributable to the Partnership was primarily due to the recording of a $133,932,000 gain primarily associated with the assets of RIGS which we contributed to HPC, and an increase in total segment margin of $15,578,000 discussed below.  Also contributing to the increase was the absence in 2009 of $3,888,000 in the management services termination fee related to the acquisition of our FrontStreet assets in 2008 and a $1,179,000 decrease in interest expense, net due to lower interest rates. This increase was partially offset by:

·	an increase in operation and maintenance expense of $7,197,000 primarily due to an increase in consumable and employee related expense in the contract compression and gathering and processing segments; and
·	an increase in depreciation and amortization expense of $6,148,000 related primarily to organic growth projects in the contract compression and gathering and processing segments and the acquisition of Nexus on March 25, 2008.

Segment Margin.  Total segment margin for the three months ended March 31, 2009 increased $15,578,000 compared with the three months ended March 31, 2008.  This increase was attributable to an increase of $3,902,000 in the gathering and processing segment, an increase of $13,960,000 in the contract compression segment margin, partially offset by a $1,700,000 decrease in transportation segment margin.  Combined segment margin varies from consolidated total segment margin due to inter-segments eliminations of $889,000 and $75,000 in the three months ended March 31, 2009 and 2008, respectively.  Segment margins differ from previously disclosed amounts due to functional reorganization of our operating segments.

Gathering and processing segment margin increased to $59,148,000 in the three months ended March 31, 2009 from $55,246,000 for the three months ended March 31, 2008.  The major components of this increase were as follows:

·	$6,654,000 from non-cash changes in the value of certain risk management contracts related to our hedging programs;
·	$3,544,000 related to our producer services function, previously reported under the transportation segment.;
·	$1,957,000 from the operations of our Nexus assets; and were partially offset by
·	$5,521,000 related to lower commodity prices compared to 2008 price levels; and
·	$2,732,000 decrease from various other sources.

Transportation segment margin decreased to $11,554,000 for the three months ended March 31, 2009 from $13,254,000 for the three months ended March 31, 2008.  The major component of this decrease relates to the contribution of RIGS to HPC on March 17, 2009.

Contract compression segment margin increased to $36,981,000 in the three months ended March 31, 2009 from $23,021,000 for the three months ended months ended March 31, 2008.  The increase is primarily attributable to a 173,642 increase in revenue generating horsepower, a 28 percent increase, enhanced by the exclusion of 15 days in 2008 of activity due to the timing of the CDM acquisition.  This 15 days also impacts other contract compression segment explanations below.

Operation and Maintenance.  Operation and maintenance expense increased to $36,042,000 in the three months ended March 31, 2009 from $28,845,000 for the corresponding period in 2008, a 25 percent increase.  This increase is primarily the result of the following factors:

·	$4,187,000 increase in consumable expense primarily in the gathering and processing segment and contract compression segment due to increased focus on maintenance of our compression fleet and increase in revenue generating horsepower in the contract compression segment; and
·	$3,358,000 increase in employee related expenses primarily in the contract compression and gathering and processing segments due to increase in operating personnel since March 31, 2008 in the contract compression segment associated with the increase in revenue generating horsepower and a change in employee vehicle policy in the gathering and processing segment; and were partially offset by
·	$348,000 decrease in various operation and maintenance expense.

General and Administrative.  General and administrative expense increased to $14,852,000 in the three months ended March 31, 2009 from $11,271,000 for the same period in 2008, a 32 percent increase.  This increase is primarily due to:

·	$2,557,000 increase in employee related expenses due to increased employer benefit payments and bonus accrual;
·	$972,000 increase in professional and consulting service primarily due to legal fees and fees paid for Sarbanes Oxley compliance in the contract compression segment;
·	$383,000 increase in rent expense primarily due to the new office lease for corporate headquarters; and offset by
·	$331,000 decrease in general and administrative expense primarily related to reimbursement for the operation and management of HPC.

Gain on Asset Sales, Net.  Gain on asset sales net of $133,932,000 (of which $52,857,000 represents the remeasurement of the Partnership retained 38 percent interest to its fair value) in the three months ended March 31, 2009 was primarily associated with assets contributed to HPC, net of transaction costs of $5,158,000.

Depreciation and Amortization.  Depreciation and amortization expense increased to $27,889,000 in the three months ended March 31, 2009 from $21,741,000 for the three months ended March 31, 2008, a 28 percent increase.  The following factors contributed to this increase:

·	$5,993,000 related to various organic growth projects completed since March 31, 2008  in the gathering and processing and contract compression segments;
·	$1,067,000 related to our Nexus assets acquired on March 25, 2008; and were partially offset by a
·	$1,016,000 decrease in depreciation expense related to the contribution of RIGS to HPC.

Interest Expense, Net.  Interest expense, net decreased by $1,179,000, or 8 percent, in the three months ended March 31, 2009 compared to the same period in 2008.  Interest expense, net decreased by $4,029,000 due to lower interest rates and was partially offset by an increase of $2,850,000 primarily due to increased levels of borrowing.

 

22

---

HPC

We own a 38 percent interest in HPC and the following management discussion and analysis is for 100 percent of HPC’s results of operations.  For comparative purposes only, we have combined the results of operations of RIGS from January 1, 2009 to March 17, 2009, with the results of operations of HPC for inception (March 18, 2009) to March 31, 2009 to compare to RIGS for the three months ended March 31, 2008.

 

		Three Months Ended
		March 31, 2009			March 31, 2008			Change			Percent
		(in thousands except percentages and volume data)
Revenues		$	14,155		$	13,493		$	662			5	%
Cost of sales			599			240			359			150
Segment margin (1)			13,556			13,253			303			2
Operation and maintenance			2,611			1,390			1,221			88
General and administrative			248			-			248			N/M
Depreciation and amortization			3,117			3,464			(347	)		10
Operating income			7,580			8,399			(819	)		10
Other income and deductions, net			104			(43	)		147			342
Net income		$	7,684		$	8,356		$	(672	)		8	%
System inlet volumes (MMbtu/d)			810,848			732,006			78,842			11

 

(1) The following provides a reconciliation of segment margin to net income.

		Three Months Ended
		March 31, 2009			March 31, 2008
		(in thousands)
Net income		$	7,684		$	8,356
Add (deduct):
Operation and maintenance			2,611			1,390
General and administrative			248			-
Depreciation and amortization			3,117			3,464
Other income and deductions, net			(104)			43
Total segment margin		$	13,556		$	13,253

 

Results of Operations Discussion.  Net income for the three months ended March 31, 2009 was $7,684,000 compared to $8,356,000 in the three months ended March 31, 2008, an 8 percent decrease.  The decrease in net income was primarily attributable to an increase in operation and maintenance expense of $1,221,000 mainly resulting from increased contractor expense related to compression operations.  Also contributing to the decrease in net income was an increase in general and administrative expense of $248,000 primarily due to the recording of a management fee paid to the Partnership for the 14 days HPC owned RIGS in the three months ended March 31, 2009.  Partially offsetting these decreases in net income were the following factors:

·	a decrease in depreciation and amortization expense of $347,000 primarily due to the fact that RIGS’ assets prior to contribution to HPC were classified as held for sale and therefore no depreciation or amortization expense was recorded from March 1, 2009 to March 17, 2009;
·	an increase in segment margin of $303,000 primarily due to an increase in system inlet volumes; and
·	an increase in other income and deductions, net of $147,000 due to interest income earned the last 14 days of March 2009 by HPC from the unused portion of capital contributed by GECC and the Alinda Investors.

EBITDA.  We define EBITDA as net income plus interest expense, provision for income taxes and depreciation and amortization expense.  EBITDA is used as a supplemental measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

·	financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
·	the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our unitholders and general partners;
·	our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and
·	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDA should not be considered as an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP.  EBITDA is the starting point in determining cash available for distribution, which is an important non-GAAP financial measure for a publicly traded master limited partnership.  The following table reconciles the non-GAAP financial measure, EBITDA, to its most directly comparable GAAP measures, net income and net cash flows provided by operating activities.

HPC’s EBITDA for the three months ended March 31, 2009 and 2008 is presented below.

		Three Months Ended
		March 31, 2009				March 31, 2008
		(in thousands)
Net income		$	7,684			$	8,356
Add:
Depreciation and amortization			3,117				3,464
EBITDA		$	10,801			$	11,820

 

Cash Distributions. On April 14, 2009, the HPC management committee declared as a distribution of $5,000,000 payable on April 30, 2009, of which the Partnership received its pro-rata share of $1,900,000.

 

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Information regarding the Partnership’s critical accounting policies and estimates is included in Item 7 of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2008.

OTHER MATTERS

Information regarding the Partnership’s commitments and contingencies are included in Note 7-Commitments and Contingencies to the condensed consolidated financial statements included in Item 1 of this report.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

We expect our sources of liquidity to include:

·	cash generated from operations;
·	borrowings under our credit facility;
·	distributions received from unconsolidated subsidiaries;
·	operating lease facilities;
·	debt offerings; and
·	issuance of additional partnership units.

We have experienced, and expect to continue to experience, substantial capital expenditure and working capital needs.  At March 31, 2009, the Partnership has purchase obligations totaling approximately $39,787,000 for the purchase of major compression components that extend until the year ending December 31, 2009.

In the future, the HPC management committee may request that we make additional capital contributions to support the joint venture’s capital expenditures.  If such capital contributions are required, we may not be able to obtain the financing necessary to satisfy our obligations.  In addition, we have agreed to reimburse the joint venture for the first $20,000,000 of cost overruns relating to the Haynesville Expansion Project.

Global financial markets and economic conditions have been, and continue to be, disrupted and volatile.  The debt and equity capital markets have been exceedingly distressed.  These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions have made, and will likely continue to make it difficult to obtain funding.  The cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly.  We expect that our ability to issue debt and equity at prices that are similar to offerings in recent years will be limited as long as capital markets remain constrained.

Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers.  For example, as a result of Lehman filing a petition under Chapter 11 of the U.S. Bankruptcy Code, a subsidiary of Lehman that is a committed lender under our credit facility has declined requests to honor its commitment to lend under our credit facility.  The total amount available to us under our credit facility as of April 30, 2009 was $93,632,000, which has been reduced by the amount of Lehman’s commitment of $5,578,000 that is no longer available to us.  If we repay any of the amounts we have already borrowed from Lehman, we may not be able to reborrow such amounts.  We may be unable to utilize the full borrowing capacity under our credit facility if other lenders are not willing to provide additional funding to make up the portion of the credit facility commitments that Lehman’s subsidiary has refused to fund or if any of the remaining committed lenders are unable or unwilling to fund their respective portion of any funding request we make under our credit facility.

We expect our growth capital expenditures to be approximately $107,000,000 in 2009 and $100,000,000 in 2010, exclusive of growth capital expenditures related to the Haynesville Expansion Project.  Our anticipated 2009 organic growth capital expenditures of $107,000,000 include $82,000,000 for additional compression for our contract compression segment and $25,000,000 for the expansion of our gathering and processing facilities.  We expect a significant portion of our anticipated 2009 contract compression capital expenditures to be made via our $75,000,000 CDM operating lease facility with Caterpillar Financial Services.

Although we intend to move forward with certain planned internal growth projects, we may further revise the timing and scope of these projects as necessary to adapt to existing economic conditions, and the benefits expected to accrue to our unitholders from our expansion activities may be diminished by substantial cost of capital increases during this period.  As a result of these costs, our cash flows may decrease, which could impair our liquidity position and require us to reduce our distributions to unitholders.

Finally, if there is a significant lessening in demand for our services as a result of extended declines in the actual and longer term expected price of oil and gas and gas related drilling activity, we may see a further reduction in our own capital expenditures and lesser requirements for working capital, both of which could generate operating cash flow and liquidity compared to the prior period and offset reduced cash generated from operations excluding working capital changes.

Working Capital Surplus (Deficit). Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due.  When we incur growth capital expenditures, we may experience working capital deficits as we fund construction expenditures out of working capital until they are permanently financed.  Our working capital is also influenced by current risk management assets and liabilities due to fair market value changes in our derivative positions being reflected on our balance sheet.  These represent our expectations for the settlement of risk management rights and obligations over the next 12 months, and so must be viewed differently from trade accounts receivable and accounts payable which settle over a much shorter span of time.  When our derivative positions are settled, we expect an offsetting physical transaction, and, as a result, we do not expect risk management assets and liabilities to affect our ability to pay bills as they come due.  Our contract compression segment records deferred revenues as a current liability.  The deferred revenues represent billings in advance of services performed.  As the revenues associated with the deferred revenues are earned, the liability is reduced.

Our working capital increased by $12,262,000 from December 31, 2008 to March 31, 2009, primarily due to:

·	an increase in net accounts receivable and payable of $16,656,000 due primarily to increased total segment margin and the timing of cash receipts and disbursements;
·	an increase in cash and cash equivalents of $5,979,000;
·	an increase in net risk management asset and liabilities of $3,989,000 due primarily to lower commodity prices associated with our derivatives portfolio; and
·	a decrease in other current liabilities of $1,022,000 primarily due to a decrease in escrow payable of $8,521,000 associated with environmental remediation and past acquisitions, mostly offset by an increase in interest payable of $7,485,000 due to interest accrued on our senior notes paid semi-annually in June and December.

Partially offsetting these increases in working capital was a decrease in other current assets due primarily to a decrease in restricted cash of $8,521,000 related to the reduced escrow payable as previously discussed.

Cash Flows from Operations.  Net cash flows provided by operating activities decreased $21,207,000, or 37 percent, for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008.  Although total segment margin increased and was partially offset by increased operation and maintenance and general and administrative expenses, our cash flows from operations decreased, primarily due to the timing of cash receipts and disbursements associated with receivables and payables.

Cash Flows from Investing Activities.  Net cash flows provided by investing activities was $2,842,000 in the three months ended March 31, 2009 compared to net cash flows used in investing activities of $671,955,000 in the three months ended March 31, 2008.  In the three months ended March 31, 2009, proceeds from an asset sale more than offset our capital expenditures.  In the three months ended March 31, 2008, we acquired FrontStreet, CDM and Nexus.

Cash Flows from Financing Activities.  Net cash flows used in financing activities was $33,194,000 in the three months ended March 31, 2009 compared to net cash flows provided by financing activities of $592,322,000 in the three  months ended March 31, 2008.  In the three months ended March 31, 2009, cash flows used in financing activities primarily related to partner distributions associated with fourth quarter 2008 activity.  In the three months ended March 31, 2008, cash flows provided by financing activities were primarily associated with borrowings for our FrontStreet, CDM and Nexus acquisitions.

We categorize our capital expenditures as either:

·	Growth capital expenditures, which are made to acquire additional assets to increase our business, to expand and upgrade existing systems and facilities or to construct or acquire similar systems or facilities; or
·	Maintenance capital expenditures, which are made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives or to maintain existing system volumes and related cash flows.

Growth Capital Expenditures.  In the three months ended March 31, 2009, we incurred $45,208,000 of growth capital expenditures, which excludes growth capital expenditures related to the Haynesville Expansion Project.  The expenditures primarily related to:

·	$38,660,000 for the fabrication of new compression packages and ancillary assets for our contract compression segment; and
·	$6,548,000 for various projects in the gathering and processing segment.

Expenditures incurred by us for the Haynesville Expansion project prior to contribution of RIGS to HPC in the amount of $80,607,000 were reimbursed by HPC upon contribution.

Maintenance Capital Expenditures.  In the three months ended March 31, 2009, we incurred $4,864,000 of maintenance capital expenditures.  Maintenance capital expenditures primarily consist of compressor and equipment overhauls, as well as new well connects to our gathering systems, which replace volumes from naturally occurring depletion of wells already connected.

Capital Resources

Credit Ratings.  Our credit ratings as of March 31, 2009 are provided below.

 

		Moody's		Standard & Poor's
Regency Energy Partners LP
Outlook		Negative Outlook		Negative Outlook
Senior notes		B1		B
Corporate rating/total debt		Ba3		BB-

 

Fourth Amended and Restated Credit Agreement.  RGS is a party to the Fourth Amended and Restated Credit Agreement dated as of August 15, 2006 among RGS, the Partnership, the guarantors party thereto, (as amended, the “Credit Agreement”), and on March 17, 2009, RGS closed Amendment Agreement No. 7 (the “Amendment”) to amend the Credit Agreement.

The Amendment, among other things, (a) authorizes the contribution by Regency HIG of its ownership interests in RIGS to the HPC and future investments in HPC of up to $135,000,000 in the aggregate, (b) permits distributions by RGS to the Partnership in an amount equal to the outstanding loans, interest and fees under a $45,000,000 revolving credit facility with GECC entered into on February 26, 2009, (c) adds an additional financial covenant that limits the ratio of senior secured indebtedness to EBITDA, (d) provides for certain EBITDA adjustments in connection with the Haynesville Expansion Project and (e) increases the applicable margins and commitment fees applicable to the credit facility, as further described below.

The Amendment provides, (a) 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 LIBOR rate for a borrowing with a one-month interest period plus 1.50 percent, (b) the applicable margin that is used in calculating interest shall range from 1.50 percent to 2.25 percent for base rate loans and from 2.50 percent to 3.25 percent for Eurodollar loans and (c) commitment fees will range from 0.375 percent to 0.500 percent.

The Amendment prohibits RGS or its subsidiaries from allowing HPC to incur or permit to exist any preferred interests or indebtedness for borrowed money of HPC prior to the completion date of the Haynesville Expansion Project.  RGS and GECC have agreed with the lenders that, after the closing of the Contribution Agreement, they will not permit their representatives on the management committee of HPC to violate such restriction.

GECC Credit Facility.  Upon the closing of our contribution of RIGS to HPC, the $45,000,000 GECC credit facility terminated.

 

Contractual Obligations.  The following table summarizes our contractual cash obligations for long-term debt and purchase obligations as of March 31, 2009.

 

		Payment Period
		Total				2009					2010-2011				2012-2013			Thereafter
		(in thousands)
Long-term debt (including interest) (1)		$	1,376,012			$	59,333			$	899,298			$	417,381			$	-
Purchase obligations			39,787				39,787				-				-				-
Total (2) (3)		$	1,415,799			$	99,120			$	899,298			$	417,381			$	-

(1) Assumes a constant LIBOR interest rate of 2.0 percent plus the applicable margin (3 percent as of March 31, 2009) for our revolving credit facility.  The principal of our outstanding senior notes ($357,500,000) bears a fixed interest rate of 8 3/8 percent.

(2) Excludes physical and financial purchases of natural gas, NGLs, and other commodities due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis.  Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount.

(3) Excludes deferred tax liabilities of $8,080,000 as the amount payable by period can not be reasonably estimated.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk.  We are a net seller of natural gas, NGLs and condensate and, as such, our financial results are exposed to fluctuations in commodity pricing.  We have executed swap contracts settled against condensate, ethane, propane, butane, natural gas, and natural gasoline.  We have hedged our expected exposure to declines in prices for NGLs, condensate, and natural gas volumes produced for our account in the approximate percentages set forth below:

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

 

We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.

The following table sets forth certain information regarding our NGL and interest rate swaps outstanding at March 31, 2009.  The relevant index price for commodities that we pay is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas as reported by the Oil Price Information Service (OPIS).

Period		Underlying		Notional Volume/Amount					We Pay			We Receive				Fair Value Asset/(Liablity)
																(in thousands)
April 2009-December 2009		Ethane			701		(MBbls)		Index			$	0.80	($/gallon)		$	10,100
April 2009-December 2010		Propane			694		(MBbls)		Index			$	0.9815-$1.5325	($/gallon)			14,786
April 2009-December 2010		Iso Butane			157		(MBbls)		Index			$	1.685-$1.915	($/gallon)			4,893
April 2009-December 2010		Normal Butane			299		(MBbls)		Index			$	1.166-$1.895	($/gallon)			6,273
April 2009-December 2010		Natural Gasoline			310		(MBbls)		Index			$	1.4975-$2.53	($/gallon)			10,122
April 2009-December 2010		West Texas Intermediate Crude			475		(MBbls)		Index			$	68.17-$121.3	($/Bbls)			16,047
April 2009-December 2010		Natural gas			3,650,000		(MMBtu)		Index			$	6.67-$6.705	($/MMBtu)			6,599
April 2009-December 2010		Interest Rate		$	300,000,000					2.40%		One-month		LIBOR			(4,605	)
Credit risk adjustment																	(1,980	)
													Total Fair Value			$	62,235

 

Item 4.  Controls and Procedures

Disclosure controls.  At the end of the period covered by this report, an evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a–15(e) and 15d–15(e) of the Exchange Act). Based on that evaluation, management, including the Chief Executive Officer and Chief Financial Officer of our managing general partner, concluded that our disclosure controls and procedures were effective as of March 31, 2009 to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is properly recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Internal control over financial reporting. There have been no changes in the Partnership’s internal controls over financial reporting that have materially affected, or are reasonably likely to affect, the Partnership’s internal controls over financial reporting.

Item 1.  Legal Proceedings

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds