Regency Energy Partners Reports Third Quarter 2014 Results

Regency Energy Partners LP (NYSE: RGP), (“Regency” or the “Partnership”), announced today its financial results for the third-quarter ended September 30, 2014.

For third quarter 2014, adjusted EBITDA increased 100 percent to $344 million, compared to $172 million in 2013, primarily due to contributions from the PVR Partners, L.P. (“PVR”) and Eagle Rock Energy Partners, L.P. (“Eagle Rock”) midstream assets, volume growth in the gathering and processing segment, volume growth at the Lone Star Joint Venture, as well as an increase in revenue generating horsepower in the contract services segment.

For third quarter 2014, Regency generated $215 million in distributable cash flow (“DCF”), compared to $115 million for third quarter 2013.

For the third quarter of 2014, Regency reported net income of $103 million, compared to net income of $39 million for the third quarter of 2013. Increases in segment margin and investment in unconsolidated affiliates were offset by increases in depreciation, depletion, and amortization, interest expense, general and administrative expenses, and operation and maintenance expenses as a result of the Hoover Energy Partners, LP (“Hoover”), PVR and Eagle Rock midstream acquisitions.

“Regency’s legacy assets experienced strong growth in the third quarter driven by continued ramp up in volumes in the gathering and processing and NGL logistics businesses, and a further increase in revenue generating horsepower,” said Mike Bradley, president and chief executive officer of Regency. “In addition, volumes on the PVR assets continued to increase compared to the second quarter of 2014.”

“The integration of the PVR and Eagle Rock midstream assets continues to progress very well, and we are already uncovering incremental synergy opportunities on top of those previously identified.”

REVIEW OF SEGMENT PERFORMANCE

Adjusted total segment margin increased to $412 million for third quarter 2014, compared to $194 million for third quarter 2013.

Gathering and Processing - Regency provides “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, selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems, gathering, transportation and terminaling of oil (crude and/or condensate, a lighter oil) received from producers, the gathering and disposing of salt water, and natural gas and NGL marketing and treating. This segment also includes our 60% membership interest in ELG, which operates natural gas gathering, oil pipeline, and oil stabilization facilities in south Texas, the Partnership’s 33.33% membership interest in Ranch JV, which processes natural gas delivered from NGL - rich shale formations in west Texas, our 50% partnership interest in Sweeny JV, the Partnership’s 51% membership interest in Aqua - PVR, which transports and supplies fresh water to natural gas producers in the Marcellus shale in Pennsylvania and our 75% membership interest in ORS, which will operate a natural gas gathering system in the Utica Shale in Ohio.

Adjusted segment margin for the Gathering and Processing segment, which excludes non-cash gains and losses from commodity derivatives, was $329 million for third quarter 2014, compared to $142 million for third quarter 2013. The increase was primarily due to volume growth in south and west Texas, and north Louisiana, including a $161 million contribution from the PVR, Eagle Rock and Hoover acquisitions.

Total throughput volumes for the Gathering and Processing segment increased to 5.7 million MMbtu per day of natural gas for third quarter 2014, including 3.1 million MMbtu per day related to the PVR, Eagle Rock and Hoover acquisitions, compared to 2.2 million MMbtu per day of natural gas for third quarter 2013. Processed NGLs increased to 178,000 barrels per day for third quarter 2014, compared to 97,000 barrels per day for third quarter 2013.

Contract Services – Regency owns and operates a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. We also own and operate a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling and dehydration.

Segment margin for the Contract Services segment, including both revenues from external customers as well as intersegment revenues, was $66 million for third quarter 2014, compared to $52 million for third quarter 2013. The increase in segment margin is primarily due to an increase in revenue generating horsepower, inclusive of intersegment revenue generating horsepower. As of September 30, 2014, the Contract Services segment’s revenue generating horsepower, including intersegment revenue generating horsepower, increased to 1,251,000, compared to 1,014,000 as of September 30, 2013, inclusive of 35,000 and 40,000, respectively, of revenue generating horsepower utilized by the Gathering and Processing segment.

Natural Resources - Regency is involved in the management of coal properties and the related collection of royalties. The Partnership also earns revenues from other land management activities, including selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. This segment also includes the Partnership’s 50% interest in Coal Handling, which owns and operates end-user coal handling facilities.

Natural Resources segment margin was $18 million for the three months ended September 30, 2014. Coal royalty tonnage for the same period was 3,544,000 for an average royalty per ton of $4.04.

Corporate – The Corporate segment comprises our corporate offices. Segment margin in the Corporate segment was $2 million for third quarter 2014, and $4 million for third quarter 2013.

Natural Gas Transportation – Regency owns a 49.99% general partner interest in RIGS Haynesville Partnership Co. (“HPC”), which owns the Regency Intrastate Gas System (“RIGS”), a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets, and a 50% membership interest in Midcontinent Express Pipeline (“MEP”), which owns a 500-mile interstate natural gas pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipe Line system in Butler, Alabama. This segment also includes Gulf States, which owns a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.

HPC consists solely of the Regency Intrastate Gas System and is operated by Regency. Income from unconsolidated affiliates for HPC was $8 million for third quarter 2014 and for third quarter 2013. Total throughput volumes for HPC averaged 696,000 MMbtu per day of natural gas for third quarter 2014, compared to 697,000 MMbtu per day for third quarter 2013.

The MEP Joint Venture consists solely of the Midcontinent Express Pipeline and is operated by Kinder Morgan Energy Partners L.P. Income from unconsolidated affiliates for the MEP Joint Venture was $11 million for third quarter 2014 and for third quarter 2013. Total throughput volumes for the MEP Joint Venture averaged 1.2 million MMbtu per day of natural gas for third quarter 2014 and 1.3 million MMbtu per day for third quarter 2013.

NGL Services – Regency owns a 30% membership interest in the Lone Star Joint Venture, which owns a diverse set of midstream energy assets including pipelines, transportation, storage, fractionation and processing facilities located in Texas, Mississippi and Louisiana. The Lone Star Joint Venture owns and operates NGL storage, fractionation and transportation assets and is operated by Energy Transfer Partners, L.P.

Income from unconsolidated affiliates for NGL Services was $31 million for third quarter 2014 and $18 million for third quarter 2013. Transportation volumes averaged 232,000 barrels per day for third quarter 2014, compared to 172,000 barrels per day for third quarter 2013. Refinery Services throughput averaged 16,000 barrels per day for third quarter 2014, compared to 12,000 barrels per day for third quarter 2013. NGL Fractionation volumes for the first two fractionators, which came online in December 2012 and November 2013, respectively, averaged 209,000 barrels per day for third quarter 2014, compared to 72,000 barrels per day for third quarter 2013.

ORGANIC GROWTH

For the nine-months ended September 30, 2014, Regency incurred $770 million of growth capital expenditures: $442 million for the Gathering and Processing segment, $256 million for the Contract Services segment, $68 million for the NGL Services segment and $4 million for the Transportation segment.

For the nine-months ended September 30, 2014, Regency incurred $61 million of maintenance capital expenditures.

In 2014, Regency expects to invest approximately $1.1 billion in growth capital expenditures, of which $650 million is related to the Gathering and Processing segment, inclusive of expenditures related to the recently acquired Hoover midstream business and PVR business, $350 million is related to the Contract Services segment and $100 million is related to the NGL Services segment.

In addition, Regency expects to invest approximately $80 million in maintenance capital expenditures in 2014, including its proportionate share related to joint ventures.

CASH DISTRIBUTIONS

On October 28, 2014, Regency announced a cash distribution of $0.5025 per outstanding common unit for the third-quarter ended September 30, 2014. This distribution is equivalent to $2.01 per outstanding common unit on an annual basis and will be paid on November 14, 2014, to unitholders of record at the close of business on November 7, 2014.

Based on the terms of the partnership agreement, the Series A Preferred Units were paid a quarterly distribution of $0.445 per unit for the third quarter-ended September 30, 2014, on the same schedule as set forth above.

For the third quarter 2014, Regency generated $215 million in distributable cash flow, representing 1.01 times the amount required to cover its announced distribution to unitholders.

Regency makes distribution determinations based on its distributable cash flow and the perceived sustainability of distribution levels over an extended period. In addition to considering the cash available for distribution generated during the quarter, Regency takes into account cash reserves established with respect to prior distributions, seasonality of results, timing of organic growth projects and its internal forecasts of adjusted EBITDA and distributable cash flow over an extended period. Distributions are determined by the Board of Directors and are driven by the long-term sustainability of the business.

TELECONFERENCE

Regency Energy Partners will hold a quarterly conference call to discuss its third-quarter 2014 results Thursday, November 6, 2014, at 10 a.m. Central Time (11 a.m. Eastern Time).

The dial-in number for the call is 1-877-546-5021 in the United States, or +1-857-244-7553 outside the United States, passcode 20205236. A live webcast of the call may be accessed on the Investor Relations page of Regency’s website at www.regencyenergy.com. The call will be available for replay for seven days by dialing 1-888-286-8010 (from outside the U.S., +1-617-801-6888) passcode 61226157. A replay of the broadcast will also be available on the Partnership’s website for 30 days.

NON-GAAP FINANCIAL INFORMATION

This press release and the accompanying financial schedules include the non-GAAP financial measures of:

• EBITDA;
• adjusted EBITDA;
• cash available for distribution;
• segment margin;
• total segment margin;
• adjusted segment margin; and
• adjusted total segment margin.

These financial metrics are key measures of the Partnership’s financial performance. The accompanying schedules provide reconciliations of these non-GAAP financial measures to their most directly-comparable financial measures calculated and presented in accordance with accounting principles generally accepted in the United States of America ("GAAP"). Our non-GAAP financial measures should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as a measure of operating performance, liquidity or ability to service debt obligations. Reconciliations of these non-GAAP financial measures to our GAAP financial statements are included in the Appendix.

We define EBITDA as net income (loss) plus interest expense, provision for income taxes and depreciation, depletion and amortization expense. We define adjusted EBITDA as EBITDA plus or minus the following:

• non-cash loss (gain) from commodity and embedded derivatives;
• non-cash unit-based compensation;
• loss (gain) on asset sales, net;
• (gain) loss on debt refinancing;
• other non-cash (income) expense, net;
• our interest in ELG and ORS adjusted EBITDA less EBITDA attributable to ELG and ORS;
• our interest in adjusted EBITDA from unconsolidated affiliates less income from unconsolidated affiliates; and
• other adjustments.

These measures are used as supplemental measures by our management and by external users of our financial statements such as investors, banks, research analysts and others, to assess:

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

Adjusted EBITDA is the starting point in determining cash available for distribution, which is an important non-GAAP financial measure for a publicly traded partnership.

We define distributable cash flow as adjusted EBITDA:

• minus interest expense, excluding capitalized interest;
• minus maintenance capital expenditures;
• minus distributions to Series A Preferred Units;
• plus cash proceeds from asset sales, if any; and
• other adjustments.

Distributable cash flow is used as a supplemental liquidity measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to approximate the amount of operating surplus generated by us during a specific period and to assess our ability to make cash distributions to our unitholders and our general partner. Distributable cash flow is not the same measure as operating surplus or available cash, both of which are defined in our partnership agreement.

Neither EBITDA nor adjusted EBITDA should be considered an alternative to, or more meaningful than net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. EBITDA and adjusted EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate EBITDA or adjusted EBITDA in the same manner. EBITDA and adjusted EBITDA do not include interest expense, income tax expense or depreciation, depletion and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we use capital assets, depreciation, depletion and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net earnings determined under GAAP, as well as EBITDA and adjusted EBITDA, to evaluate our performance.

We define segment margin, generally, as revenues minus cost of sales. We calculate our Gathering and Processing segment margin and Natural Gas Transportation segment margin as revenues generated from operations less the cost of natural gas and NGLs purchased and other costs of sales, including third-party transportation and processing fees. We do not record segment margin for our investments in unconsolidated affiliates (HPC, MEP, Lone Star, Ranch JV, Aqua – PVR, Coal Handling and Sweeny JV) because we record our ownership percentages of their net income as income from unconsolidated affiliates in accordance with the equity method of accounting. We calculate our Contract Services segment margin as revenues generated from our contract compression and treating operations minus direct costs, primarily repairs, associated with those revenues. Segment margin for the Natural Resources segment margin is generally equal to total revenues as there is typically minimal cost of sales associated with the management and leasing of properties. We calculate total segment margin as the sum of segment margin of our segments less intersegment eliminations. We define adjusted segment margin as segment margin adjusted for non-cash (gains) losses from commodity derivatives, the 40% of ELG margin attributable to the holder of the noncontrolling interest, the 25% ORS margin attributable to the holder of the noncontrolling interest, and our 33.33% portion of Ranch JV margin. Adjusted total segment margin equals the sum of our operating segments’ adjusted segment margins or segment margins, as applicable, including intersegment eliminations.

Total segment margin and adjusted total segment margin are included as a supplemental disclosure because they are primary performance measures used by our management as they represent the result of product sales, service fee revenues and product purchases, a key component of our operations. We believe total segment margin and adjusted total segment margin are important measures because they are directly related to our volumes and commodity price changes.

Operation and maintenance expense is a separate measure used by management 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 operation and maintenance expenses. These expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. We do not deduct operation and maintenance expenses from total revenue in calculating total segment margin and adjusted total segment margin because we separately evaluate commodity volume and price changes in these margin amounts.

As an indicator of our operating performance, total segment margin or adjusted total segment margin should not be considered an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Our total segment margin and adjusted total segment margin may not be comparable to a similarly titled measure of another company because other entities may not calculate these measures in the same manner.

FORWARD-LOOKING INFORMATION AND OTHER DISCLAIMERS

These and other risks and uncertainties are discussed in more detail in filings made by the Partnership with the Securities and Exchange Commission, which are available to the public. The Partnership undertakes no obligation to update publicly or to revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Regency Energy Partners LP (NYSE:RGP) is a growth-oriented, master limited partnership engaged in the gathering and processing, compression, treating and transportation of natural gas; the transportation, fractionation and storage of natural gas liquids; the gathering, transportation and terminaling of oil (crude and/or condensate) received from producers; and the management of coal and natural resource properties in the United States. Regency’s general partner is owned by Energy Transfer Equity, L.P. (NYSE:ETE). For more information, please visit Regency’s website at www.regencyenergy.com.

Condensed Consolidated Balance Sheets
Regency Energy Partners LP
Condensed Consolidated Balance Sheets
($ in millions)
		September 30, 2014			December 31, 2013
Assets
Current assets		$	716		$	400
Property, plant and equipment, net			8,993			4,418
Investment in unconsolidated affiliates			2,371			2,097
Other assets, net			100			57
Intangible assets, net			3,472			682
Goodwill			1,528			1,128
Total Assets		$	17,180		$	8,782
Liabilities and Partners' Capital and Noncontrolling Interest
Current liabilities		$	825		$	475
Other long-term liabilities			105			49
Long-term debt			6,427			3,310
Total Liabilities		$	7,357		$	3,834
Series A Preferred Units			32			32
Partners' capital			9,674			4,814
Noncontrolling interest			117			102
Total Partners' Capital and Noncontrolling Interest			9,791			4,916
Total Liabilities and Partners' Capital and Noncontrolling Interest		$	17,180		$	8,782

Condensed Consolidated Statements of Operations
Condensed Consolidated Statements of Operations
($ in millions)
		Three Months Ended September 30,
			2014				2013
REVENUES		$	1,483			$	665
OPERATING COSTS AND EXPENSES
Cost of sales			1,051				477
Operation and maintenance			129				78
General and administrative			36				13
Loss (gain) on asset sales, net			1				(1	)
Depreciation, depletion and amortization			122				74
Total operating costs and expenses			1,339				641
OPERATING INCOME			144				24
Income from unconsolidated affiliates			53				37
Interest expense, net			(86	)			(41	)
Gain on debt refinancing, net			2				-
Other income and deductions, net			(2	)			24
INCOME BEFORE INCOME TAXES			111				44
Income tax expense			4				2
NET INCOME		$	107			$	42
Net income attributable to noncontrolling interest			(4	)			(3	)
NET INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP		$	103			$	39
Amount allocated to common units		$	91			$	33
Weighted average number of common units outstanding			397,961,321				209,559,854
Basic income per common unit		$	0.23			$	0.16
Diluted income per common unit		$	0.23			$	0.05

Segment Financial and Operating Data
		Three Months Ended September 30,
			2014			2013
		($ in millions)
Gathering and Processing Segment
Financial data:
Segment margin		$	349		$	136
Adjusted segment margin			329			142
Operating data:
Throughput (MMbtu/d)			5,680,000			2,178,000
NGL gross production (Bbls/d)			178,000			96,700

		Three Months Ended September 30,
			2014			2013
		($ in millions)
Contract Services
Financial data:
Segment margin		$	66		$	52
Operating data:
Revenue generating horsepower, including intercompany revenue generating horsepower			1,251,000			1,014,000

		Three Months Ended September 30,
			2014			2013
		($ in millions)
Natural Resources
Financial data:
Segment margin *		$	18		$	-
Operating data:
Coal royalty tonnage			3,544,000			-
Average coal royalties per ton		$	4.04		$	-
* The Natural Resources segment was acquired in the PVR acquisition on March 21, 2014.

		Three Months Ended September 30,
			2014			2013
		($ in millions)
Corporate Segment
Financial data:
Segment margin		$	2		$	4

Reconciliation of Non-GAAP Measures to GAAP Measures
			Three Months Ended September 30,
				2014				2013
			($ in millions)
Net income			$	107			$	42
	Add (deduct):
		Interest expense, net		86				41
		Depreciation, depletion and amortization		122				74
		Income tax expense		4				2
EBITDA (1)			$	319			$	159
	Add (deduct):
		Partnership's interest in unconsolidated affiliates' adjusted EBITDA (2)		86				66
		Income from unconsolidated affiliates		(53	)			(37	)
		Non-cash gain from commodity and embedded derivatives		(16	)			(14	)
		Other income, net		8				(2	)
Adjusted EBITDA			$	344			$	172
(1) Earnings before interest, taxes, depreciation and amortization.
(2) The following table presents reconciliations of net income to adjusted EBITDA for our unconsolidated affiliates, on a 100% basis, and our interest in adjusted EBITDA for the three months ended September 30, 2014 and 2013:
			Three months ended September 30, 2014
			HPC				MEP				Lone Star				Ranch JV				Aqua JV				Coal Handling					Total
Net Income (Loss)			$	19			$	21			$	104			$	7			$	(2	)		$	2
Add:
	Depreciation and amortization			8				17				27				1				4				1
	Interest expense, net			4				12				-				-				-				-
	Other expenses, net			-				-				2				1				-				-
Adjusted EBITDA				31				50				133				9				2				3
Ownership interest				49.99	%			50	%			30	%			33.33	%			51	%			50	%
Partnership's interest in Adjusted EBITDA			$	15			$	25			$	40			$	3			$	1			$	2				$	86
Operating data
	Throughput (MMbtu/d)			696,000				1,165,000				N/A				143,000				N/A				N/A
	NGL Transportation - Throughput (Bbls/d)			N/A				N/A				232,000				N/A				N/A				N/A
	Refinery - Throughput (Bbls/d)			N/A				N/A				16,000				N/A				N/A				N/A
	Fractionation - Throughput (Bbls/d)			N/A				N/A				209,000				N/A				N/A				N/A
	Coal (tons)			N/A				N/A				N/A				N/A		`		N/A				696,000
			Three months ended September 30, 2013
			HPC				MEP				Lone Star				Ranch JV				Total
Net Income			$	18			$	21			$	62			$	1
Add:
	Depreciation and amortization			9				17				21				1
	Interest expense, net			1				13				1				-
Adjusted EBITDA				28				51				84				2
Ownership interest				49.99	%			50	%			30	%			33.33	%
Partnership's interest in Adjusted EBITDA			$	14			$	26			$	25			$	1			$	66
Operating data
	Throughput (MMbtu/d)			697,000				1,279,000				N/A				76,000
	NGL Transportation - Throughput (Bbls/d)			N/A				N/A				172,000				N/A
	Refinery - Throughput (Bbls/d)			N/A				N/A				12,000				N/A
	Fractionation - Throughput (Bbls/d)			N/A				N/A				72,000				N/A

Non-GAAP Adjusted Total Segment Margin to GAAP Net Income
		Three Months Ended September 30,
			2014				2013
		($ in millions)
Net Income		$	107			$	42
Add (Deduct):
Operation and maintenance			129				78
General and administrative			36				13
Loss (gain) on asset sales, net			1				(1	)
Depreciation, depletion and amortization			122				74
Income from unconsolidated affiliates			(53	)			(37	)
Interest expense, net			86				41
Gain on debt refinancing, net			(2	)			-
Other income and deductions, net			2				(24	)
Income tax expense			4				2
Total Segment Margin			432				188
Non-cash (gain) loss from commodity derivatives			(17	)			9
Segment margin related to the noncontrolling interest			(7	)			(4	)
Segment margin related to ownership percentage in Ranch JV			4				1
Adjusted Total Segment Margin		$	412			$	194
Gathering & Processing Segment Margin		$	349			$	136
Non-cash (gain) loss from commodity derivatives			(17	)			9
Segment margin related to the noncontrolling interest			(7	)			(4	)
Segment margin related to ownership percentage in Ranch JV			4				1
Adjusted Gathering and Processing Segment Margin			329				142
Natural Gas Transportation Segment Margin			-				-
Contract Services Segment Margin *			66				52
Corporate Segment Margin			2				4
Natural Resources Segment Margin			18				-
Inter-segment Elimination *			(3	)			(4	)
Adjusted Total Segment Margin		$	412			$	194
* Inter-segment elimination is related to Contract Services segment margin.
Operating Data
Gathering and Processing Segment
Throughput (MMbtu/d)			5,680,000				2,178,000
NGL gross production (Bbls/d)			178,000				96,700
Natural Resources Segment
Coal royalty tonnage			3,544,000				-
Contract Services Segment
Revenue generating horsepower			1,251,000				1,014,000

Reconciliation of “distributable cash flow” to net cash flows provided by operating activities and to net income
				Three Months Ended September 30,
					2014				2013
				($ in millions)
	Net Cash Flows Provided by Operating Activities			$	293			$	183
		Add (deduct):
			Depreciation, depletion and amortization, including debt issuance cost amortization and bond premium write-off and amortization		(99	)			(75	)
			Income from unconsolidated affiliates		53				37
			Derivative valuation change		16				14
			(Loss) gain on asset sales, net		(1	)			2
			Unit-based compensation expenses		(3	)			(2	)
		Cash flow changes in current assets and liabilities:
			Trade accounts receivables and related party receivables		28				32
			Other current assets and other current liabilities		(26	)			(25	)
			Trade accounts payable and related party payables		(109	)			(89	)
		Distributions of earnings received from unconsolidated affiliates			(51	)			(37	)
		Cash flow changes in other assets and liabilities			6				2
	Net Income			$	107			$	42
		Add:
			Interest expense, net		86				41
			Depreciation, depletion and amortization		122				74
			Income tax expense		4				2
	EBITDA			$	319			$	159
		Add (deduct):
			Partnership's interest in unconsolidated affiliates' adjusted EBITDA		86				66
			Income from unconsolidated affiliates		(53	)			(37	)
			Non-cash gain from commodity and embedded derivatives		(16	)			(14	)
			Other, net		8				(2	)
	Adjusted EBITDA			$	344			$	172
		Add (deduct):
			Interest expense, excluding capitalized interest		(97	)			(40	)
			Maintenance capital expenditures		(24	)			(9	)
			Proceeds from asset sales		1				-
			Other adjustments		(9	)			(8	)
	Distributable cash flow			$	215			$	115