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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934



August 8, 2018
Date of Report (Date of earliest event reported)

PANHANDLE EASTERN PIPE LINE COMPANY, LP
(Exact name of Registrant as specified in its charter)

Delaware	1-2921	44-0382470
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

8111 Westchester Drive, Suite 600,
Dallas, Texas 75225

(Address of principal executive offices) (Zip Code)

(214) 981-0700

(Registrant’s telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:


¨	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)


¨	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)


¨	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))


¨	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨



Item 7.01	Regulation FD Disclosure.

On August 8, 2018, Energy Transfer Partners, L.P, the parent of Energy Transfer, LP, the entity which owns 100% of ETP Holdco Corporation, which indirectly owns 100% of the equity interests of Panhandle Eastern Pipe Line Company, LP (the “Company”), issued a press release announcing the financial and operating results of Energy Transfer Partners, L.P. and Energy Transfer, LP, including certain financial results of the Company, for the second quarter ended June 30, 2018. A copy of ETP’s press release is furnished as Exhibit 99.1 to this report and is incorporated herein by reference.

In accordance with General Instruction B.2 of Form 8-K, the information set forth in the attached Exhibit 99.1 is deemed to be “furnished” and shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act.



Item 9.01	Financial Statements and Exhibits.

(d) Exhibits. In accordance with General Instruction B.2 of Form 8-K, the information set forth in the attached Exhibit 99.1 is deemed to be “furnished” and shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act.



Exhibit Number	Description of the Exhibit
99.1	Energy Transfer Partners, L.P. Press Release dated August 8, 2018

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.




	PANHANDLE EASTERN PIPE LINE COMPANY, LP
	(Registrant)
Date: August 8, 2018	By:	/s/ Thomas E. Long
		Thomas E. Long
		Chief Financial Officer (duly authorized to sign on behalf of the registrant)

Exhibit

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ENERGY TRANSFER PARTNERS

REPORTS SECOND QUARTER RESULTS

Dallas – August 8, 2018 – Energy Transfer Partners, L.P. (NYSE: ETP) (“ETP” or the “Partnership”) today reported its financial results for the quarter ended June 30, 2018. For the three months ended June 30, 2018, net income was $602 million and Adjusted EBITDA was $2.05 billion. Adjusted EBITDA increased $506 million compared to the three months ended June 30, 2017, reflecting an increase of $320 million in Adjusted EBITDA from the crude oil transportation and services segment, as well as higher results from several of the other segments, as discussed in the segment results analysis below. Net income increased $306 million compared to the three months ended June 30, 2017, primarily due to increased operating income and equity in earnings of unconsolidated affiliates. Distributable Cash Flow attributable to partners, as adjusted, for the three months ended June 30, 2018 totaled $1.32 billion, an increase of $371 million compared to the three months ended June 30, 2017, primarily due to the increase in Adjusted EBITDA.

ETP’s other recent key accomplishments include the following:

•

In August 2018, ETP and Energy Transfer Equity, L.P. (“ETE”) entered into a merger agreement pursuant to which ETP will merge with a wholly-owned subsidiary of ETE, with ETP unitholders (other than ETE and its subsidiaries) receiving 1.28 ETE common units in exchange for each ETP common unit they own. The transaction is expected to close in the fourth quarter of 2018, subject to the approval by a majority of the unaffiliated unitholders of ETP and other customary closing conditions.


•	In July 2018, ETP announced a quarterly distribution of $0.565 per unit ($2.260 annualized) on ETP common units for the quarter ended June 30, 2018.


•	In July 2018, ETP issued 17.8 million of its 7.625% Series D Preferred Units at a price of $25 per unit, resulting in total gross proceeds of $445 million.


•	In July 2018, ETP placed into service Fractionator V, a 120,000 barrel per day fractionator located in Mont Belvieu, Texas that is fully subscribed under multiple, long-term fixed-fee contacts.


•	In June 2018, ETP issued $3.00 billion aggregate principal amount of senior notes and used the net proceeds to redeem outstanding senior notes, to repay borrowings outstanding under ETP’s revolving credit facility and for general partnership purposes.


•	In May 2018, ETP announced the receipt of approval to place the remaining portion of Phase 2 of the Rover pipeline in service effective June 1, 2018, allowing for use of 100 percent of Rover’s 3.25 Bcf per day mainline capacity.


•	In May 2018, ETP placed into service Red Bluff Express pipeline, a 1.4 Bcf per day natural gas pipeline that runs through the heart of the Delaware basin and connects the ETP Orla Plant and multiple third-party plants to ETP’s Waha Oasis Header.


•	As of June 30, 2018, ETP’s $5.00 billion revolving credit facilities had $3.61 billion of available capacity, and its leverage ratio, as defined by the credit agreement, was 3.87x.

An analysis of ETP’s segment results and other supplementary data is provided after the financial tables shown below. ETP has scheduled a conference call for 8:00 a.m. Central Time, Thursday, August 9, 2018 to discuss the second quarter 2018 results. The conference call will be broadcast live via an internet webcast, which can be accessed through www.energytransfer.com and will also be available for replay on ETP’s website for a limited time.

Energy Transfer Partners, L.P. (NYSE: ETP) is a master limited partnership that owns and operates one of the largest and most diversified portfolios of energy assets in the United States. Strategically positioned in all of the major U.S. production basins, ETP’s operations include complementary natural gas midstream, intrastate and interstate transportation and storage assets; crude oil, natural gas liquids (NGL) and refined product transportation and terminalling assets; NGL fractionation; and various acquisition and marketing assets. ETP’s general partner is owned by Energy Transfer Equity, L.P. (NYSE: ETE). For more information, visit the Energy Transfer Partners, L.P. website at www.energytransfer.com.

Energy Transfer Equity, L.P. (NYSE: ETE) is a master limited partnership that owns the general partner and 100% of the incentive distribution rights (IDRs) of Energy Transfer Partners, L.P. (NYSE: ETP) and Sunoco LP (NYSE: SUN). ETE also owns Lake Charles LNG Company and the general partner of USA Compression Partners, LP (NYSE: USAC). On a consolidated

basis, ETE’s family of companies owns and operates a diverse portfolio of natural gas, natural gas liquids, crude oil and refined products assets, as well as retail and wholesale motor fuel operations and LNG terminalling. For more information, visit the Energy Transfer Equity, L.P. website at www.energytransfer.com.

Forward-Looking Statements

This news release may include certain statements concerning expectations for the future that are forward-looking statements as defined by federal law. Such forward-looking statements are subject to a variety of known and unknown risks, uncertainties, and other factors that are difficult to predict and many of which are beyond management’s control. An extensive list of factors that can affect future results are discussed in the Partnership’s Annual Report on Form 10-K and other documents filed from time to time with the Securities and Exchange Commission. The Partnership undertakes no obligation to update or revise any forward-looking statement to reflect new information or events.

The information contained in this press release is available on our website at www.energytransfer.com.

Contacts

Energy Transfer

Investor Relations:

Lyndsay Hannah, Brent Ratliff, 214-981-0795

Media Relations:

Vicki Granado, 214-840-5820

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(unaudited)



	June 30, 2018		December 31, 2017
ASSETS

Current assets	$	6,547	$	6,528

Property, plant and equipment, net	59,776		58,437

Advances to and investments in unconsolidated affiliates	3,636		3,816
Other non-current assets, net	762		758
Intangible assets, net	4,988		5,311
Goodwill	2,861		3,115
Total assets	$	78,570	$	77,965



LIABILITIES AND EQUITY

Current liabilities	$	6,641	$	6,994

Long-term debt, less current maturities	33,741		32,687
Non-current derivative liabilities	135		145
Deferred income taxes	2,917		2,883
Other non-current liabilities	1,079		1,084

Commitments and contingencies
Redeemable noncontrolling interests	21		21

Equity:
Total partners’ capital	27,865		28,269
Noncontrolling interest	6,171		5,882
Total equity	34,036		34,151
Total liabilities and equity	$	78,570	$	77,965

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per unit data)

(unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017 ^(a)			2018			2017 ^(a)
REVENUES	$	9,410		$	6,576		$	17,690		$	13,471
COSTS AND EXPENSES:
Cost of products sold	7,140			4,624			13,128			9,674
Operating expenses	627			539			1,231			1,031
Depreciation, depletion and amortization	588			557			1,191			1,117
Selling, general and administrative	112			120			224			230
Total costs and expenses	8,467			5,840			15,774			12,052
OPERATING INCOME	943			736			1,916			1,419
OTHER INCOME (EXPENSE):
Interest expense, net	(358		)	(336		)	(704		)	(668		)
Equity in earnings (losses) of unconsolidated affiliates	106			(61		)	34			12
Gain on Sunoco LP common unit repurchase	—			—			172			—
Loss on deconsolidation of CDM	(86		)	—			(86		)	—
Gains (losses) on interest rate derivatives	20			(25		)	72			(20		)
Other, net	46			61			106			80
INCOME BEFORE INCOME TAX EXPENSE	671			375			1,510			823
Income tax expense	69			79			29			134
NET INCOME	602			296			1,481			689
Less: Net income attributable to noncontrolling interest	170			94			334			156
NET INCOME ATTRIBUTABLE TO PARTNERS	432			202			1,147			533
Preferred Unitholders’ interest in net income	30			—			54			—
General Partner’s interest in net income	402			251			804			457
Class H Unitholder’s interest in net income	—			—			—			93
Common Unitholders’ interest in net income (loss)	$	—		$	(49	)	$	289		$	(17	)
NET INCOME (LOSS) PER COMMON UNIT:
Basic	$	(0.01	)	$	(0.04	)	$	0.23		$	(0.02	)
Diluted	$	(0.01	)	$	(0.04	)	$	0.23		$	(0.02	)
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING:
Basic	1,165.4			1,021.7			1,164.6			922.5
Diluted	1,165.4			1,021.7			1,169.4			922.5

(a)

During the fourth quarter of 2017, the Partnership changed its accounting policy related to certain inventories. Certain crude oil, refined product and NGL inventories associated with the legacy Sunoco Logistics business were changed from the LIFO method to the weighted average cost method. These changes have been applied retrospectively to all periods presented, and the prior period amounts reflected below have been adjusted from those amounts previously reported. Certain other prior period amounts have also been reclassified to conform to the current period presentation, including a reclassification between capitalized interest and AFUDC from the three months and six months ended June 30, 2017.

SUPPLEMENTAL INFORMATION

(Dollars and units in millions)

(unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017 ^(a)(b)			2018			2017 ^(a)(b)
Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow (c):
Net income	$	602		$	296		$	1,481		$	689
Interest expense, net	358			336			704			668
Income tax expense	69			79			29			134
Depreciation, depletion and amortization	588			557			1,191			1,117
Non-cash compensation expense	21			15			41			38
(Gains) losses on interest rate derivatives	(20		)	25			(72		)	20
Unrealized (gains) losses on commodity risk management activities	265			(34		)	352			(98		)
Gain on Sunoco LP common unit repurchase	—			—			(172		)	—
Loss on deconsolidation of CDM	86			—			86			—
Equity in (earnings) losses of unconsolidated affiliates	(106		)	61			(34		)	(12		)
Adjusted EBITDA related to unconsolidated affiliates	228			247			413			486
Other, net	(40		)	(37		)	(87		)	(52		)
Adjusted EBITDA (consolidated)	2,051			1,545			3,932			2,990
Adjusted EBITDA related to unconsolidated affiliates	(228		)	(247		)	(413		)	(486		)
Distributable cash flow from unconsolidated affiliates	141			123			266			267
Interest expense, net	(358		)	(336		)	(704		)	(668		)
Preferred unitholders’ distributions	(30		)	—			(54		)	—
Current income tax (expense) benefit	22			(12		)	22			(13		)
Maintenance capital expenditures	(116		)	(107		)	(204		)	(167		)
Other, net	5			12			8			27
Distributable Cash Flow (consolidated)	1,487			978			2,853			1,950
Distributable Cash Flow attributable to PennTex Midstream Partners, LP (“PennTex”) (100%) (d)	—			—			—			(19		)
Distributions from PennTex to ETP (d)	—			—			—			8
Distributable cash flow attributable to noncontrolling interest in other non-wholly-owned consolidated subsidiaries	(180		)	(57		)	(327		)	(80		)
Distributable Cash Flow attributable to the partners of ETP	1,307			921			2,526			1,859
Transaction-related expenses	10			25			14			32
Distributable Cash Flow attributable to the partners of ETP, as adjusted	$	1,317		$	946		$	2,540		$	1,891

Distributions to partners:
Limited Partners:
Common Units held by public	$	644		$	589		$	1,286		$	1,156
Common Units held by parent	15			15			31			30
General Partner interests and Incentive Distribution Rights (“IDRs”) held by parent	451			400			900			781
IDR relinquishments	(42		)	(162		)	(84		)	(319		)
Total distributions to be paid to partners	$	1,068		$	842		$	2,133		$	1,648
Common Units outstanding – end of period	1,166.4			1,092.6			1,166.4			1,092.6
Distribution coverage ratio (e)	1.23x			1.12x			1.19x			1.15x


(a)	For the three and six months ended June 30, 2017, the calculation of Distributable Cash Flow and the amounts reflected for distributions to partners and common units outstanding reflect the pro forma impacts of the Sunoco Logistics Merger as though the merger had occurred on January 1, 2017. As a result, the prior period amounts reported above reflect the following pro forma impacts:

•

Distributable cash flow attributable to the partners of ETP includes amounts attributable to the partners of both legacy ETP and legacy Sunoco Logistics. Previously, the calculation of distributable cash flow attributable to the partners of ETP (as previously reported by legacy ETP) excluded the distributable cash flow attributable to Sunoco Logistics and only included distributions from legacy Sunoco Logistics to legacy ETP.


•	Distributable cash flow attributable to noncontrolling interest in other consolidated subsidiaries includes amounts attributable to the noncontrolling interests in the other consolidated subsidiaries of both legacy ETP and legacy Sunoco Logistics.


•	The transaction-related expenses adjustment in distributable cash flow attributable to the partners of ETP, as adjusted, includes amounts incurred by both legacy ETP and legacy Sunoco Logistics.

•

Distributions to limited partners include distributions paid on the common units of both legacy ETP and legacy Sunoco Logistics but exclude the following distributions in the prior periods on units that were cancelled in the merger, which comprise the following: (i) distributions paid by legacy Sunoco Logistics on its common units held legacy ETP and (ii) distributions paid by legacy ETP on its Class H units held by ETE.


•	Distributions on General Partner interests and incentive distribution rights are reflected on a pro forma basis, based on the pro forma cash distributions to limited partners and the current distribution waterfall per the limited partnership agreement (i.e., the legacy Sunoco Logistics distribution waterfall).

(b)

(c)

Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures used by industry analysts, investors, lenders, and rating agencies to assess the financial performance and the operating results of ETP’s fundamental business activities and should not be considered in isolation or as a substitute for net income, income from operations, cash flows from operating activities, or other GAAP measures.

There are material limitations to using measures such as Adjusted EBITDA and Distributable Cash Flow, including the difficulty associated with using either as the sole measure to compare the results of one company to another, and the inability to analyze certain significant items that directly affect a company’s net income or loss or cash flows. In addition, our calculations of Adjusted EBITDA and Distributable Cash Flow may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP, such as segment margin, operating income, net income, and cash flow from operating activities.

Definition of Adjusted EBITDA

We define Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments. Adjusted EBITDA reflects amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on our proportionate ownership.

Adjusted EBITDA is used by management to determine our operating performance and, along with other financial and volumetric data, as internal measures for setting annual operating budgets, assessing financial performance of our numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation.

Definition of Distributable Cash Flow

We define Distributable Cash Flow as net income, adjusted for certain non-cash items, less distributions to preferred unitholders and maintenance capital expenditures. Non-cash items include depreciation, depletion and amortization, non-cash compensation expense, amortization included in interest expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and deferred income taxes. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). For unconsolidated affiliates, Distributable Cash Flow reflects the Partnership’s proportionate share of the investee’s distributable cash flow.

Distributable Cash Flow is used by management to evaluate our overall performance. Our partnership agreement requires us to distribute all available cash, and Distributable Cash Flow is calculated to evaluate our ability to fund distributions through cash generated by our operations.

On a consolidated basis, Distributable Cash Flow includes 100% of the Distributable Cash Flow of ETP’s consolidated subsidiaries. However, to the extent that noncontrolling interests exist among our subsidiaries, the Distributable Cash Flow generated by our subsidiaries may not be available to be distributed to our partners. In order to reflect the cash flows available for distributions to our partners, we have reported Distributable Cash Flow attributable to partners, which is calculated by adjusting Distributable Cash Flow (consolidated), as follows:


•	For subsidiaries with publicly traded equity interests, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiary, and Distributable Cash Flow attributable to our partners includes distributions to be received by the parent company with respect to the periods presented.


•	For consolidated joint ventures or similar entities, where the noncontrolling interest is not publicly traded, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiary, but Distributable Cash Flow attributable to partners is net of distributions to be paid by the subsidiary to the noncontrolling interests.

For Distributable Cash Flow attributable to partners, as adjusted, certain transaction-related and non-recurring expenses that are included in net income are excluded.


(d)	Beginning with the second quarter of 2017, PennTex became a wholly-owned subsidiary of ETP. The amounts reflected above for PennTex relate only to the first quarter of 2017, and no distributable cash flow has been attributed to noncontrolling interests in PennTex subsequent to March 31, 2017.


(e)	Distribution coverage ratio for a period is calculated as Distributable Cash Flow attributable to partners, as adjusted, divided by net distributions expected to be paid to the partners of ETP in respect of such period.

SUMMARY ANALYSIS OF QUARTERLY RESULTS BY SEGMENT

(Tabular dollar amounts in millions)

(unaudited)



	Three Months Ended June 30,
	2018		2017
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	208	$	148
Interstate transportation and storage	330		262
Midstream	414		412
NGL and refined products transportation and services	461		388
Crude oil transportation and services	548		228
All other	90		107
	$	2,051	$	1,545

In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment margin is similar to the GAAP measure of gross margin, except that segment margin excludes charges for depreciation, depletion and amortization.

In addition, for certain segments, the sections below include information on the components of segment margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of segment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin, and other margin. These components of segment margin are calculated consistent with the calculation of segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.

For prior periods reported herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliates. These reclassifications had no impact on net income or total equity.

Following is a reconciliation of segment margin to operating income, as reported in the Partnership’s consolidated statements of operations:



	Three Months Ended June 30,
	2018			2017
Intrastate transportation and storage	$	267		$	202
Interstate transportation and storage	328			207
Midstream	593			571
NGL and refined products transportation and services	587			516
Crude oil transportation and services	442			374
All other	57			76
Intersegment eliminations	(4		)	6
Total segment margin	2,270			1,952

Less:
Operating expenses	627			539
Depreciation, depletion and amortization	588			557
Selling, general and administrative	112			120
Operating income	$	943		$	736

Intrastate Transportation and Storage



	Three Months Ended June 30,
	2018			2017
Natural gas transported (BBtu/d)	10,327			9,261
Revenues	$	813		$	753
Cost of products sold	546			551
Segment margin	267			202
Unrealized gains on commodity risk management activities	(8		)	(21		)
Operating expenses, excluding non-cash compensation expense	(51		)	(46		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(7		)	(5		)
Adjusted EBITDA related to unconsolidated affiliates	7			18
Segment Adjusted EBITDA	$	208		$	148

Transported volumes increased primarily due to favorable market pricing. In addition, beginning in April 2018, transported volumes also reflected Regency Intrastate Gas LP (“RIGS”) as a consolidated subsidiary. RIGS was previously reflected as an unconsolidated affiliate until ETP acquired the remaining interest in April 2018.

Segment Adjusted EBITDA. For the three months ended June 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impacts of the following:


•	an increase of $47 million in realized natural gas sales and other margin due to higher realized gains from pipeline optimization activity;


•	a net increase of $5 million due to the consolidation of RIGS beginning in April 2018, as discussed above, resulting in increases in transportation fees, operating expenses, and selling, general and administrative expenses of $26 million, $6 million and $2 million, respectively, and a decrease of $13 million in Adjusted EBITDA related to unconsolidated affiliates;


•	an increase of $4 million in transportation fees, excluding the incremental transportation fees related to the RIGS consolidation discussed above, primarily due to higher demand on existing pipelines; and


•	an increase of $3 million in realized storage margin primarily due to higher realized derivative gains; partially offset by


•	a decrease of $2 million in retained fuel revenues as a result of lower natural gas pricing.

Interstate Transportation and Storage



	Three Months Ended June 30,
	2018			2017
Natural gas transported (BBtu/d)	8,707			5,299
Natural gas sold (BBtu/d)	17			17
Revenues	$	328		$	207
Operating expenses, excluding non-cash compensation, amortization and accretion expenses	(105		)	(67		)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses	(17		)	(7		)
Adjusted EBITDA related to unconsolidated affiliates	123			128
Other	1			1
Segment Adjusted EBITDA	$	330		$	262

Transported volumes reflected an increase of 1,748 BBtu/d as a result of the partial in service of the Rover pipeline; increases of 654 BBtu/d and 425 BBtu/d on the Panhandle and Trunkline pipelines, respectively, due to increased utilization of higher contracted capacity; an increase of 350 BBtu/d on the Tiger pipeline as a result of production increases in the Haynesville Shale and deliveries into intrastate markets; and an increase of 200 BBtu/d on the Transwestern pipeline resulting from favorable opportunities in the midcontinent and Waha areas from the Permian supply basin.

Segment Adjusted EBITDA. For the three months ended June 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impacts of the following:


•	an increase of $68 million from the partial in service of the Rover pipeline with increases of $105 million in revenues, $30 million in operating expenses and $7 million in selling, general and administrative expenses; and


•	an aggregate increase of $19 million in revenues, excluding the incremental revenue related to the Rover pipeline in service discussed above, primarily due to capacity sold at higher rates on the Transwestern and Panhandle pipelines, partially offset by $3 million of lower revenues on the Tiger pipeline due to a customer contract restructuring; partially offset by


•	an increase of $8 million in operating expenses, excluding the incremental expenses related to the Rover pipeline in service discussed above, primarily due to higher maintenance project costs;


•	an increase of $3 million in selling, general and administrative expenses, excluding the incremental expenses related to the Rover pipeline in service discussed above, primarily due to a reimbursement of legal fees and a franchise tax settlement received in 2017; and


•	a decrease of $5 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower sales of short-term firm capacity on Citrus.

Midstream



	Three Months Ended June 30,
	2018			2017
Gathered volumes (BBtu/d)	11,576			10,961
NGLs produced (MBbls/d)	513			474
Equity NGLs (MBbls/d)	31			28
Revenues	$	1,874		$	1,615
Cost of products sold	1,281			1,044
Segment margin	593			571
Unrealized gains on commodity risk management activities	—			(3		)
Operating expenses, excluding non-cash compensation expense	(169		)	(152		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(20		)	(11		)
Adjusted EBITDA related to unconsolidated affiliates	9			7
Other	1			—
Segment Adjusted EBITDA	$	414		$	412

Gathered volumes and NGL production increased primarily due to increases in the Permian and Northeast regions, partially offset by smaller declines in other regions.

Segment Adjusted EBITDA. For the three months ended June 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net effects of the following:


•	an increase of $17 million in fee-based margin due to growth in the Permian and Northeast regions, offset by declines in the South Texas, North Texas and midcontinent/Panhandle regions;


•	an increase of $6 million in non-fee-based margin primarily due to higher crude oil and NGL prices;


•	an increase of $2 million in non-fee-based margin due to increased throughput volume in the Permian region; and


•	an increase of $2 million in Adjusted EBITDA related to unconsolidated affiliates due to higher earnings from our Aqua, Mi Vida and Ranch joint ventures; partially offset by


•	an increase of $17 million in operating expenses primarily due to increases of $6 million in outside services, $5 million in materials, $2 million in employee costs and $2 million in ad valorem taxes; and


•	an increase of $9 million in selling, general and administrative expenses primarily due to a favorable impact recorded in the prior period from the adjustment of certain reserves in connection with contingent matters.

NGL and Refined Products Transportation and Services



	Three Months Ended June 30,
	2018			2017
NGL transportation volumes (MBbls/d)	967			835
Refined products transportation volumes (MBbls/d)	637			643
NGL and refined products terminal volumes (MBbls/d)	789			767
NGL fractionation volumes (MBbls/d)	473			431
Revenues	$	2,568		$	1,779
Cost of products sold	1,981			1,263
Segment margin	587			516
Unrealized (gains) losses on commodity risk management activities	13			(4		)
Operating expenses, excluding non-cash compensation expense	(141		)	(125		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(17		)	(17		)
Adjusted EBITDA related to unconsolidated affiliates	19			18
Segment Adjusted EBITDA	$	461		$	388

NGL transportation volumes increased primarily from the Permian region resulting from a ramp up in production from existing customers. Refined products transportation volumes decreased slightly primarily due to lower throughput volumes from the Midwest region due to end user operational issues, partially offset by increased throughput volumes from the Southwest region due to increased demand.

NGL and refined products terminal volumes increased primarily due to more volumes loaded at our Nederland terminal as propane export demand increased, as well as higher refined products throughput volumes at our Eagle Point terminal, partially offset by lower throughput volumes at our Marcus Hook Industrial Complex primarily due to Mariner East 1 system downtime during the second quarter of 2018.

Average fractionated volumes at our Mont Belvieu, Texas fractionation facility increased primarily due to increased volumes from Permian producers.

Segment Adjusted EBITDA. For the three months ended June 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to net impacts of the following:

•

an increase of $49 million in transportation margin due to a $43 million increase resulting from increased producer volumes from the Permian region on our Texas NGL pipelines, an $11 million increase resulting from a reclassification between our transportation and fractionation margins, a $4 million increase due to higher throughput on Mariner West and a $2 million increase on Mariner South primarily due to system downtime in the prior period. These increases were partially offset by an $11 million decrease resulting from lower throughput on Mariner East 1 due to system downtime in the second quarter of 2018;


•	an increase of $23 million in marketing margin (excluding a net change of $17 million in unrealized gains and losses) due to gains of $10 million from our butane blending operations, a $9 million increase from sales of domestic propane and other products at our Marcus Hook Industrial Complex and a $4 million increase from optimizing sales of purity product from our Mont Belvieu fractionators;

•

an increase of $11 million in fractionation and refinery services margin due to a $14 million increase resulting from higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility, a $6 million increase from blending gains as a result of improved market pricing and a $2 million increase from Mariner South as more cargoes were loaded at Mariner South. These increases were partially offset by an $11 million decrease resulting from a reclassification between our transportation and fractionation margins; and

•

an increase of $10 million in terminal services margin due to a $7 million increase resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018 and a $5 million increase at our Nederland terminal due to increased demand for propane exports. These increases were partially offset by a $2 million decrease due to the effect of Mariner East pipeline system downtime on our Marcus Hook Industrial Complex; partially offset by

•

an increase of $16 million in operating expenses primarily due to a $7 million increase resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018, a $4 million increase in utilities and ad valorem taxes on the fractionators, and a $3 million increase in overhead costs; and


•	a decrease of $5 million in storage margin primarily due to the expiration and amendments to various NGL and refined products storage contracts.

Crude Oil Transportation and Services



	Three Months Ended June 30,
	2018			2017
Crude transportation volumes (MBbls/d)	4,242			3,452
Crude terminals volumes (MBbls/d)	2,103			1,950
Revenues	$	4,803		$	2,465
Cost of products sold	4,361			2,091
Segment margin	442			374
Unrealized (gains) losses on commodity risk management activities	262			(2		)
Operating expenses, excluding non-cash compensation expense	(144		)	(114		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(20		)	(32		)
Adjusted EBITDA related to unconsolidated affiliates	8			2
Segment Adjusted EBITDA	$	548		$	228

Crude transportation volumes increased due to placing the Bakken pipeline in service in June 2017 as well as increased volumes on existing pipelines due to increased production in West Texas. Crude terminal volumes increased due to increased volumes delivered to our Nederland crude terminal from the Bakken pipeline and from increased West Texas production.

Segment Adjusted EBITDA. For the three months ended June 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following:

•

an increase of $332 million in segment margin (excluding unrealized losses on commodity risk management activities) due to a $193 million increase resulting primarily from placing our Bakken pipeline in service in the second quarter of 2017 as well as a $27 million increase resulting from increased throughput, primarily from Permian producers, on existing pipeline assets; a $100 million increase (excluding a net change of $264 million in unrealized gains and losses) from our crude oil acquisition and marketing business primarily resulting from more favorable market price differentials between the West Texas and Gulf Coast markets; and a $9 million increase in terminal fees primarily from ship loading fees at our Nederland facility as a result of increased exports;


•	a decrease of $12 million in selling, general and administrative expenses primarily due to higher professional fees recorded in the prior period; and


•	an increase of $6 million in Adjusted EBITDA related to unconsolidated affiliates due to a new contract at one of our joint ventures; partially offset by

•

an increase of $30 million in operating expenses due to a $13 million increase primarily resulting from placing our Bakken pipeline in service in the second quarter of 2017; a $3 million increase resulting from the addition of certain joint venture transportation assets in the second quarter of 2017; and a $14 million increase from existing transportation assets due to increases of $7 million in utilities, $5 million in expense projects, $5 million in ad valorem taxes and $5 million in management fees, partially offset by decreases in environmental fees of $5 million and capacity leases of $3 million.

All Other



	Three Months Ended June 30,
	2018			2017
Revenues	$	502		$	870
Cost of products sold	445			794
Segment margin	57			76
Unrealized gains on commodity risk management activities	(2		)	(4		)
Operating expenses, excluding non-cash compensation expense	(10		)	(31		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(19		)	(27		)
Adjusted EBITDA related to unconsolidated affiliates	62			76
Other and eliminations	2			17
Segment Adjusted EBITDA	$	90		$	107

Amounts reflected in our all other segment primarily include:


•	our equity method investment in limited partnership units of Sunoco LP consisting of 26.2 million and 43.5 million Sunoco LP common units, representing 31.8% and 43.7% of Sunoco LP’s total outstanding common units as of June 30, 2018 and June 30, 2017, respectively;


•	our natural gas marketing and compression operations. Subsequent to our contribution of CDM to USAC in April 2018, our all other segment includes our equity method investment in USAC consisting of 19.2 million USAC common units and 6.4 million USAC Class B Units, together representing 26.6% of the limited partner interests;


•	a non-controlling interest in PES, comprising 33% of PES’ outstanding common units; and


•	our investment in coal handling facilities.

Segment Adjusted EBITDA. For the three months ended June 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased due to the net impacts of the following:


•	a decrease of $44 million in Adjusted EBITDA related to unconsolidated affiliates from our investment in Sunoco LP resulting from the Partnership’s lower ownership in Sunoco LP and lower operating results of Sunoco LP due to the sale of the majority of its retail assets in January 2018; and


•	a decrease of $12 million due to the contribution of CDM to USAC in April 2018, which decrease reflects the impact of deconsolidating CDM, partially offset by an increase in Adjusted EBITDA related to unconsolidated affiliates due to the equity method investment in USAC held by ETP subsequent to the CDM Contribution; partially offset by


•	a decrease of $14 million in merger and acquisition expenses related to the Sunoco Logistics merger in 2017, partially offset by the CDM Contribution in 2018;


•	an increase of $12 million in Adjusted EBITDA related to unconsolidated affiliates from our investment in PES;


•	an increase of $6 million from gains in power trading activities; and


•	an increase of $2 million in margin due to the expiration of a capacity contract commitment.

SUPPLEMENTAL INFORMATION ON LIQUIDITY

(In millions)

(unaudited)



	Facility Size		Funds Available at June 30, 2018		Maturity Date
ETP Five-Year Revolving Credit Facility	$	4,000	$	2,605	December 1, 2022
ETP 364-Day Revolving Credit Facility	1,000		1,000		November 30, 2018
	$	5,000	$	3,605

SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES

(In millions)

(unaudited)



	Three Months Ended June 30,
	2018			2017
Equity in earnings (losses) of unconsolidated affiliates:
Citrus	$	33		$	30
FEP	13			13
MEP	8			10
Sunoco LP	16			(110		)
USAC	(2		)	—
Other	38			(4		)
Total equity in earnings (losses) of unconsolidated affiliates	$	106		$	(61	)

Adjusted EBITDA related to unconsolidated affiliates:
Citrus	$	85		$	88
FEP	18			19
MEP	20			21
Sunoco LP	39			83
USAC	21			—
Other	45			36
Total Adjusted EBITDA related to unconsolidated affiliates	$	228		$	247

Distributions received from unconsolidated affiliates:
Citrus	$	27		$	22
FEP	15			10
MEP	18			20
Sunoco LP	22			37
USAC	10			—
Other	21			30
Total distributions received from unconsolidated affiliates	$	113		$	119