Regency Energy Partners Reports Second Quarter 2014 Results

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

For second quarter 2014, adjusted EBITDA increased 98 percent to $307 million, compared to $155 million in 2013, primarily due to a full quarter’s contribution from the PVR 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 second quarter 2014, Regency generated $207 million in distributable cash flow (“DCF”), compared to $101 million for second quarter 2013.

For the second quarter of 2014, Regency reported a net loss of $8 million, compared to net income of $10 million for the second 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”) and PVR Partners, L.P. (“PVR”) acquisitions.

“In the second quarter, Regency’s legacy assets delivered another strong performance, driven by volume growth from completed expansion projects in our gathering and processing and NGL logistics businesses, as well as continued strong demand for contract compression,” said Mike Bradley, president and chief executive officer of Regency. “We were also very pleased with the performance of the recently acquired PVR assets, which also saw a substantial increase in volumes compared to the second quarter of 2013.

“Also, we recently completed our acquisition of Eagle Rock Energy’s midstream assets. Once fully integrated, we expect the acquisitions of Hoover, PVR and Eagle Rock to provide significant synergy and expansion opportunities going forward, allowing Regency to continue increasing our footprint and enhancing our services to customers.”

REVIEW OF SEGMENT PERFORMANCE

Adjusted total segment margin increased 92 percent to $348 million for second quarter 2014, compared to $181 million for second quarter 2013.

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, selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems, gathering of oil (crude and/or condensate, a lighter oil) received from producers, and the gathering and disposing of salt water. This segment also includes 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, and the Partnership’s 51% interest in Aqua - PVR, which transports and supplies fresh water to natural gas producers in the Marcellus shale in Pennsylvania.

Adjusted segment margin for the Gathering and Processing segment, which excludes non-cash gains and losses from commodity derivatives, was $267 million for second quarter 2014, compared to $132 million for second quarter 2013. The increase was primarily due to volume growth in south and west Texas, and north Louisiana, including a $101 million contribution from the PVR and Hoover acquisitions.

Total throughput volumes for the Gathering and Processing segment increased to 4.9 million MMbtu per day of natural gas for second quarter 2014, including 2.4 million MMbtu per day related to the PVR and Hoover acquisitions, compared to 2.2 million MMbtu per day of natural gas for second quarter 2013. Processed NGLs increased to 134,000 barrels per day for second quarter 2014, compared to 89,100 barrels per day for second quarter 2013.

Contract Services – We own and operate 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 $63 million for second quarter 2014, compared to $49 million for second 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 June 30, 2014, the Contract Services segment’s revenue generating horsepower, including intersegment revenue generating horsepower, increased to 1,187,000, compared to 938,000 as of June 30, 2013, inclusive of 47,000 and 41,000, respectively, of revenue generating horsepower utilized by the Gathering and Processing segment.

Natural Resources - The Partnership is involved in the management of coal and natural resources 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 $20 million for the three months ended June 30, 2014. Coal royalty tonnage for the same period was 4,011,000, for an average royalty per ton of $3.75.

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

Natural Gas Transportation – We own 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 the 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 $6 million for second quarter 2014, compared to $8 million for second quarter 2013. This decrease was primarily due to a decrease in throughput related to the expiration of certain contracts that were not renewed. Total throughput volumes for HPC averaged 665,000 MMbtu per day of natural gas for second quarter 2014, compared to 658,000 MMbtu per day for second 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 $12 million for second quarter 2014 and $10 million for second quarter 2013. Total throughput volumes for the MEP Joint Venture averaged 1.2 million MMbtu per day of natural gas for second quarter 2014 and 1.3 million MMbtu per day for second quarter 2013.

NGL Services – We own 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 $27 million for second quarter 2014 and $13 million for second quarter 2013. Transportation volumes averaged 215,000 barrels per day for second quarter 2014, compared to 163,000 barrels per day for second quarter 2013. Refinery Services throughput averaged 13,000 barrels per day for second quarter 2014, compared to 15,000 barrels per day for second quarter 2013. NGL Fractionation volumes for the first two fractionators, which came online in December 2012 and November 2013, respectively, averaged 177,000 barrels per day for second quarter 2014, compared to 87,000 barrels per day for second quarter 2013.

ORGANIC GROWTH

For the six-months ended June 30, 2014, Regency incurred $443 million of growth capital expenditures: $232 million for the Gathering and Processing segment, $163 million for the Contract Services segment, $46 million for the NGL Services segment and $2 million for the Transportation segment.

For the six-months ended June 30, 2014, Regency incurred $37 million of maintenance capital expenditures.

In 2014, Regency expects to invest approximately $1.25 billion in growth capital expenditures, of which $850 million is related to the Gathering and Processing segment, inclusive of expenditures related to the recently acquired Hoover midstream business and PVR business, $300 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 $90 million in maintenance capital expenditures in 2014, including its proportionate share related to joint ventures.

CASH DISTRIBUTIONS

On July 28, 2014, Regency announced a cash distribution of $0.49 per outstanding common unit for the second-quarter ended June 30, 2014. This distribution is equivalent to $1.96 per outstanding common unit on an annual basis and will be paid on August 14, 2014, to unitholders of record at the close of business on August 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 second quarter-ended June 30, 2014, on the same schedule as set forth above.

For the second quarter 2014, Regency generated $207 million in distributable cash flow. Excluding the units issued to fund the Eagle Rock midstream acquisition, which closed July 1, 2014, coverage would have been 1.08 times the amount required to cover its announced distribution to unitholders. Including the units issued to fund the Eagle Rock midstream acquisition, coverage was 1.01 times.

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 second-quarter 2014 results Thursday, August 7, 2014, at 10 a.m. Central Time (11 a.m. Eastern Time).

The dial-in number for the call is 1-866-202-0886 in the United States, or +1-617-213-8841 outside the United States, passcode 39462544. 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 18730993. 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 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;
• loss on debt refinancing;
• other non-cash (income) expense, net;
• our interest in ELG adjusted EBITDA less EBITDA attributable to ELG; and
• our interest in adjusted EBITDA from unconsolidated affiliates less income from unconsolidated affiliates.

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 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 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 and Coal Handling) 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 minus direct costs, primarily compressor unit 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 and our 33.33% portion of Ranch JV margin. Our 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)
			June 30, 2014				December 31, 2013
Assets
Current assets			$	592			$	400
Property, plant and equipment, net				7,416				4,418
Investment in unconsolidated affiliates				2,378				2,097
Other assets, net				87				57
Intangible assets, net				3,500				682
Goodwill				1,486				1,128
Total Assets			$	15,459			$	8,782
Liabilities and Partners' Capital and Noncontrolling Interest
Current liabilities			$	730			$	475
Other long-term liabilities				88				49
Long-term debt				5,490				3,310
Total Liabilities			$	6,308			$	3,834
Series A Preferred Units				32				32
Partners' capital				9,012				4,814
Noncontrolling interest				107				102
Total Partners' Capital and Noncontrolling Interest				9,119				4,916
Total Liabilities and Partners' Capital and Noncontrolling Interest			$	15,459			$	8,782

Condensed Consolidated Statements of Operations

Regency Energy Partners LP
Condensed Consolidated Statements of Operations
($ in millions)
			Three Months Ended June 30,
			2014					2013
REVENUES			$	1,178				$	639
OPERATING COSTS AND EXPENSES
Cost of sales				828					445
Operation and maintenance				93					73
General and administrative				54					18
Loss on asset sales, net				-					1
Depreciation, depletion and amortization				168					68
Total operating costs and expenses				1,143					605
OPERATING INCOME				35					34
Income from unconsolidated affiliates				47					31
Interest expense, net				(78	)				(41	)
Loss on debt refinancing, net				-					(7	)
Other income and deductions, net				(7	)				(7	)
(LOSS) INCOME BEFORE INCOME TAXES				(3	)				10
Income tax expense (benefit)				1					(1	)
NET (LOSS) INCOME			$	(4	)			$	11
Net income attributable to noncontrolling interest				(4	)				(1	)
NET (LOSS) INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP			$	(8	)			$	10
Amount allocated to common units			$	(18	)			$	13
Weighted average number of common units outstanding				361,071,005					193,065,183
Basic (loss) income per common unit			$	(0.05	)			$	0.07
Diluted (loss) income per common unit			$	(0.05	)			$	0.07

Segment Financial and Operating Data

			Three Months Ended June 30,
			2014				2013
			($ in millions)
Gathering and Processing Segment
Financial data:
Segment margin			$	269			$	145
Adjusted segment margin				267				132
Operating data:
Throughput (MMbtu/d)				4,895,000				2,178,000
NGL gross production (Bbls/d)				134,000				89,100

			Three Months Ended June 30,
			2014				2013
			($ in millions)
Contract Services
Financial data:
Segment margin			$	63			$	49
Operating data:
Revenue generating horsepower, including intercompany revenue generating horsepower				1,187,000				938,000

			Three Months Ended June 30,
			2014				2013
			($ in millions)
Natural Resources
Financial data:
Segment margin *			$	20			$	-
Operating data:
Coal royalty tonnage				4,011,000				-
Average coal royalties per ton			$	3.75			$	-

*

The Natural Resources segment was acquired in the PVR acquisition on March 21, 2014.

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

Reconciliation of Non-GAAP Measures to GAAP Measures

			Three Months Ended June 30,
			2014					2013
			($ in millions)
Net (loss) income			$	(4	)			$	11
Add (deduct):
Interest expense, net				78					41
Depreciation, depletion and amortization				168					68
Income tax expense				1					-
EBITDA (1)			$	243				$	120
Add (deduct):
Partnership's interest in unconsolidated affiliates' adjusted EBITDA (2)				79					60
Income from unconsolidated affiliates				(47	)				(31	)
Non-cash loss (gain) from commodity and embedded derivatives				9					(4	)
Other income, net				23					10
Adjusted EBITDA			$	307				$	155

(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 June 30, 2014 and 2013:

			Three months ended June 30, 2014
			HPC					MEP					Lone Star					Ranch JV					Aqua JV					Coal Handling					Total
Net Income (Loss)			$	16				$	22				$	89				$	7				$	(3	)			$	1
Add:
Depreciation and amortization				10					17					26					1					3					1
Interest expense, net				3					13					-					-					-					-
Adjusted EBITDA				29					52					115					8					-					2
Ownership interest				49.99	%				50	%				30	%				33.33	%				51	%				50	%
Partnership's interest in Adjusted EBITDA			$	14				$	26				$	35				$	3				$	-				$	1				$	79
Operating data
Throughput (MMbtu/d)				665,000					1,197,000					N/A					140,000					N/A					N/A
NGL Transportation - Throughput (Bbls/d) (1)				N/A					N/A					215,000					N/A					N/A					N/A
Refinery - Throughput (Bbls/d)				N/A					N/A					13,000					N/A					N/A					N/A
Fractionation - Throughput (Bbls/d) (2)				N/A					N/A					177,000					N/A					N/A					N/A
Coal (tons)				N/A					N/A					N/A				N/A						N/A					662,000
			Three months ended June 30, 2013
			HPC					MEP					Lone Star					Ranch JV					Total
Net Income			$	18				$	21				$	46				$	1
Add:
Depreciation and amortization				9					17					20					1
Interest expense, net				-					13					1					-
Adjusted EBITDA				27					51					67					2
Ownership interest				49.99	%				50	%				30	%				33.33	%
Partnership's interest in Adjusted EBITDA			$	13				$	26				$	20				$	1				$	60
Operating data
Throughput (MMbtu/d)				658,000					1,264,000					N/A					69,000
NGL Transportation - Throughput (Bbls/d) (1)				N/A					N/A					163,000					N/A
Refinery - Throughput (Bbls/d)				N/A					N/A					15,000					N/A
Fractionation - Throughput (Bbls/d) (2)				N/A					N/A					87,000					N/A

Non-GAAP Adjusted Total Segment Margin to GAAP Net Income

			Three Months Ended June 30,
			2014					2013
			($ in millions)
Net (Loss) Income			$	(4	)			$	11
Add (Deduct):
Operation and maintenance				93					73
General and administrative				54					18
Loss on asset sales, net				-					1
Depreciation, depletion and amortization				168					68
Income from unconsolidated affiliates				(47	)				(31	)
Interest expense, net				78					41
Loss on debt refinancing, net				-					7
Other income and deductions, net				7					7
Income tax expense (benefit)				1					(1	)
Total Segment Margin				350					194
Non-cash loss (gain) from commodity derivatives				1					(12	)
Segment margin related to the noncontrolling interest				(6	)				(2	)
Segment margin related to ownership percentage in Ranch JV				3					1
Adjusted Total Segment Margin			$	348				$	181
Gathering & Processing Segment Margin			$	269				$	145
Non-cash loss (gain) from commodity derivatives				1					(12	)
Segment margin related to the noncontrolling interest				(6	)				(2	)
Segment margin related to ownership percentage in Ranch JV				3					1
Adjusted Gathering and Processing Segment Margin				267					132
Natural Gas Transportation Segment Margin				-					-
Contract Services Segment Margin *				63					49
Corporate Segment Margin				2					4
Natural Resources Segment Margin				20					-
Inter-segment Elimination *				(4	)				(4	)
Adjusted Total Segment Margin			$	348				$	181
* Inter-segment elimination is related to Contract Services segment margin.
Operating Data
Gathering and Processing Segment
Throughput (MMbtu/d)				4,895,000					2,178,000
NGL gross production (Bbls/d)				134,000					89,100
Natural Resources Segment
Coal royalty tonnage				4,011,000					-
Contract Services Segment
Revenue generating horsepower				1,187,000					938,000

Reconciliation of “distributable cash flow” to net cash flows provided by operating activities and to net income

			Three Months Ended June 30,
			2014					2013
			($ in millions)
Net Cash Flows Provided by Operating Activities			$	90				$	112
Add (deduct):
Depreciation, depletion and amortization, including debt issuance cost amortization and bond premium write-off and amortization				(167	)				(68	)
Income from unconsolidated affiliates				47					31
Derivative valuation change				4					1
Loss on asset sales, net				-					(1	)
Unit-based compensation expenses				(3	)				(1	)
Cash flow changes in current assets and liabilities:
Trade accounts receivables and related party receivables				(4	)				27
Other current assets and other current liabilities				9					137
Trade accounts payable and related party payables				84					(57	)
Distributions of earnings received from unconsolidated affiliates				(53	)				(35	)
Cash flow changes in other assets and liabilities				(11	)				(135	)
Net (Loss) Income			$	(4	)			$	11
Add:
Interest expense, net				78					41
Depreciation, depletion and amortization				168					68
Income tax expense				1					-
EBITDA			$	243				$	120
Add (deduct):
Partnership's interest in unconsolidated affiliates' adjusted EBITDA				79					60
Income from unconsolidated affiliates				(47	)				(31	)
Non-cash loss (gain) from commodity and embedded derivatives				9					(4	)
Other, net				23					10
Adjusted EBITDA			$	307				$	155
Add (deduct):
Interest expense, excluding capitalized interest				(87	)				(46	)
Maintenance capital expenditures				(15	)				(13	)
SUGS Contribution Agreement adjustment *				-					9
Proceeds from asset sales				2					5
Other adjustments				-					(9	)
Distributable cash flow			$	207				$	101
* Includes an adjustment to DCF related to the historical SUGS operations for the time period prior to the Partnership's acquisition.