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Energy Transfer Partners Reports First Quarter Results

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Energy Transfer Partners, L.P. (NYSE:ETP) today reported its financial results for the quarter ended March 31, 2015. Adjusted EBITDA for Energy Transfer Partners, L.P. (“ETP,” “we” or the “Partnership”) for the three months ended March 31, 2015 totaled $1.15 billion, a decrease of $57 million compared to the same period last year. Distributable Cash Flow attributable to the partners of ETP, as adjusted, for the three months ended March 31, 2015 totaled $692 million, a decrease of $52 million compared to the same period last year. Income from continuing operations for the three months ended March 31, 2015 was $308 million, a decrease of $159 million compared to the same period last year.

On a pro forma basis for the Regency Merger, as discussed below, Adjusted EBITDA for ETP and Regency Energy Partners LP (“Regency”) combined was $1.37 billion for the three months ended March 31, 2015. On a pro forma basis, Distributable Cash Flow attributable to the partners of ETP, as adjusted, was $857 million for the three months ended March 31, 2015.

On April 30, 2015, ETP and Regency completed the previously announced merger of an indirect subsidiary of ETP, with and into Regency, with Regency surviving the merger as a wholly-owned subsidiary of ETP (the “Regency Merger”). As part of the merger consideration, each Regency common unit and Class F unit was converted into the right to receive 0.4124 ETP Common Units. Based on the Regency units outstanding, ETP issued approximately 172.2 million ETP Common Units to Regency unitholders, including approximately 15.5 million units issued to ETP subsidiaries. The approximately 1.9 million outstanding Regency series A preferred units were converted into corresponding new ETP Series A Preferred Units. ETP and Regency are both controlled by Energy Transfer Equity, L.P. (“ETE”); therefore, the Regency Merger is a combination of entities under common control. Beginning with the quarter ending June 30, 2015, ETP’s GAAP financial statements will reflect retrospective consolidation of Regency; however, such consolidation is not yet reflected in the actual results presented herein. As such, ETP has included pro forma amounts to reflect the combined results of ETP and Regency.

In April 2015, ETP announced that its Board of Directors approved an increase in its quarterly distribution to $1.015 per ETP Common Unit ($4.06 annualized) for the quarter ended March 31, 2015, representing an increase of $0.32 per ETP Common Unit on an annualized basis, or 8.6%, compared to the first quarter of 2014. On a stand-alone basis (pre-merger) for the quarter ended March 31, 2015, ETP’s distribution coverage ratio was 1.18x. For the quarter ended March 31, 2015, ETP’s distribution coverage ratio would have been 1.04x on a pro forma basis for the Regency Merger (excluding the impact of any synergies).

ETP’s other recent key accomplishments include the following:

  • Material projects that commenced operations in the quarter included: the Mariner South project, a LPG export/import facility with Sunoco Logistics Partners L.P. (“SXL”), which loaded its first propane cargo, and our Rebel processing facility in the Permian Basin, which helped contribute to overall volumes in our midstream segment.
  • ETP, as a member of a consortium, was awarded two pipeline projects for the transportation of natural gas for Mexico’s state power company, CFE, under long-term contracts. The Trans-Pecos pipeline is an approximately 143-mile, 42-inch pipeline to deliver at least 1.356 Bcf/d of natural gas from the Waha Hub to the US/Mexico border near Presidio, Texas. The Comanche Trail pipeline is an approximately 195-mile, 42-inch pipeline to deliver at least 1.135 Bcf/d of natural gas from the Waha Hub to the US/Mexico border near San Elizario, Texas. ETP will be the construction manager and operator of both pipelines. The expected all-in cost for these two pipelines is anticipated to be approximately $1.3 billion and we expect both pipelines to be in-service in the first quarter of 2017.
  • In March 2015, ETE transfered 30.8 million ETP Common Units, ETE’s 45% interest in the Bakken pipeline project, and $879 million in cash to the Partnership in exchange for 30.8 million newly issued Class H Units of ETP that, when combined with the 50.2 million previously issued Class H Units, generally entitle ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of SXL (the “Bakken Pipeline Transaction”). In connection with this transaction, ETP also issued to ETE 100 Class I Units that provide distributions to ETE to offset IDR subsidies previously provided to ETP. The IDR subsidies from ETE to ETP, including the impact from distributions on Class I Units, will be reduced by $55 million in 2015 and $30 million in 2016.
  • In addition, ETP and SXL have agreed to transfer 30% of the Bakken pipeline to SXL.
  • In April 2015, Sunoco LP completed the acquisition of a 31.58% equity interest in Sunoco, LLC from ETP Retail Holdings (“Retail Holdings”). Sunoco LLC distributes approximately 5.3 billion gallons per year of motor fuel to customers in the east, midwest and southwest regions of the United States. The transaction was valued at approximately $816 million. Sunoco LP paid $775 million in cash and issued $41 million of Sunoco LP common units to Retail Holdings.
  • In March 2015, we closed on the acquisition of the King Ranch project from Exxon Mobil Corporation, for a total purchase price of $370 million. This acquisition includes a 750 MMcf/d natural gas processing plant, a 42,000 Bbls/d NGL fractionator, a NGL pipeline that delivers products to Corpus Christi and the ETC King Ranch pipeline, which consists of 165 miles of mainline and gathering pipelines.
  • Earlier this week, we announced that our subsidiary, Lone Star NGL LLC (“Lone Star”), would construct a fourth NGL fractionation facility at Mont Belvieu, Texas. Fractionator IV, estimated to cost approximately $450 million, is scheduled to be operational by December 2016. The 120,000 Bbls/d fractionator is fully subscribed by multiple long-term contracts and will provide off-take for the new 533-mile, 24- and 30-inch Lone Star Express pipeline.
  • Regarding our Lake Charles LNG project, on April 10, 2015, the draft Environmental Impact Statement for Lake Charles LNG and the expansion of the Trunkline interstate pipeline was issued by the Federal Energy Regulatory Commission (“FERC”). ETEETP and BG Group plc (“BG”) were pleased with the findings and recommendations by FERC. It moves the Lake Charles LNG project one step closer to our goal of achieving a final investment decision (“FID”) in 2016.

    On April 7, 2015, BG and Royal Dutch Shell plc (“Shell”) announced a proposed takeover of BG by Shell. We understand that the closing of the BG/Shell merger is expected to occur in early 2016. In the interim, BG and ETEETP remain focused on completing the development milestones for the project as the parties move toward FID.

  • In March 2015, ETP issued $1.0 billion aggregate principal amount of 4.05% senior notes due March 2025, $500 million aggregate principal amount of 4.90% senior notes due March 2035, and $1.0 billion aggregate principal amount of 5.15% senior notes due March 2045. ETP used the $2.48 billion net proceeds to pay outstanding borrowings under the ETP Credit Facility, to fund growth capital expenditures and for general partnership purposes.
  • As of March 31, 2015, the ETP Credit Facility had no outstanding borrowings and its credit ratio, as defined by the credit agreement, was 4.05x. Pro forma for the Regency Merger, borrowings under the ETP Credit Facility increased to $1.5 billion and the pro forma credit ratio, as defined by the credit agreement, was 4.62x.
  • In the first quarter of 2015, ETP issued approximately 1.2 million Common Units through its at-the-market equity program, generating net proceeds of approximately $76 million.

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, May 7, 2015 to discuss the first quarter 2015 results. The conference call will be broadcast live via an internet web cast, which can be accessed through www.energytransfer.com and will also be available for replay on ETP’s web site for a limited time.

Energy Transfer Partners, L.P. (NYSE:ETP) is a master limited partnership owning and operating one of the largest and most diversified portfolios of energy assets in the United States. ETP’s subsidiaries include Panhandle Eastern Pipe Line Company, LP (the successor of Southern Union Company) and Lone Star NGL LLC, which owns and operates natural gas liquids storage, fractionation and transportation assets. In total, ETP currently owns and operates more than 62,000 miles of natural gas and natural gas liquids pipelines. ETP also owns the general partner, 100% of the incentive distribution rights, and approximately 67.1 million common units in Sunoco Logistics Partners L.P. (NYSE:SXL) , which operates a geographically diverse portfolio of crude oil and refined products pipelines, terminalling and crude oil acquisition and marketing assets. ETP owns 100% of Sunoco, Inc. and 100% of Susser Holdings Corporation. Additionally, ETP owns the general partner, 100% of the incentive distribution rights and approximately 44% of the limited partner interests in Sunoco LP (formerly Susser Petroleum Partners LP) (NYSE:SUN) , a wholesale fuel distributor and convenience store operator. ETP’s general partner is owned by ETE. For more information, visit the Energy Transfer Partners, L.P. web site at www.energytransfer.com.

Energy Transfer Equity, L.P. (NYSE: ETE) is a master limited partnership which owns the general partner and 100% of the incentive distribution rights (IDRs) of Energy Transfer Partners, L.P. (NYSE:ETP) and approximately 23.6 million ETP Common Units and 81.0 million ETP Class H Units, which track 90% of the underlying economics of the general partner interest and the IDRs of Sunoco Logistics Partners L.P. (NYSE:SXL) . On a consolidated basis, ETE’s family of companies owns and operates approximately 71,000 miles of natural gas, natural gas liquids, refined products, and crude oil pipelines. For more information, visit the Energy Transfer Equity, L.P. web site at www.energytransfer.com.

Sunoco Logistics Partners L.P. (NYSE: SXL), headquartered in Philadelphia, is a master limited partnership that owns and operates a logistics business consisting of a geographically diverse portfolio of complementary crude oil, refined products, and natural gas liquids pipeline, terminalling and acquisition and marketing assets which are used to facilitate the purchase and sale of crude oil, refined products, and natural gas liquids. Sunoco Logistics’ general partner is owned by Energy Transfer Partners, L.P. (NYSE:ETP) . For more information, visit the Sunoco Logistics Partners, L.P. web site at www.sunocologistics.com.

Sunoco LP (NYSE:SUN) is a growth-oriented master limited partnership that primarily distributes motor fuel to convenience stores, independent dealers, commercial customers and distributors. Sunoco LP also operates more than 150 convenience stores and retail fuel sites. Sunoco LP’s general partner is owned by Energy Transfer Partners, L.P. (NYSE:ETP) . For more information, visit the Sunoco LP web site at www.sunocolp.com.

Forward-Looking Statements

This press 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 Reports 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 web site at www.energytransfer.com.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(unaudited)

Actual Pro Forma for Regency Merger(1)
March 31,
2015
December 31,
2014
March 31,
2015
December 31,
2014

ASSETS

CURRENT ASSETS $ 6,206 $ 5,439 $ 6,776 $ 6,043
PROPERTY, PLANT AND EQUIPMENT, net 31,649 29,743 41,143 38,907
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES 3,723 3,840 3,667 3,760
GOODWILL 6,256 6,419 7,480 7,642
INTANGIBLE ASSETS, net 2,093 2,087 5,499 5,526
OTHER NON-CURRENT ASSETS, net 702 693 802 796
Total assets $ 50,629 $ 48,221 $ 65,367 $ 62,674

LIABILITIES AND EQUITY

CURRENT LIABILITIES $ 4,707 $ 6,040 $ 5,258 $ 6,684
LONG-TERM DEBT, less current maturities 20,430 18,332 27,651 24,973
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES 214 138 228 154
DEFERRED INCOME TAXES 4,036 4,226 4,060 4,226
OTHER NON-CURRENT LIABILITIES 1,256 1,206 1,306 1,278
COMMITMENTS AND CONTINGENCIES
SERIES A PREFERRED UNITS 33 33
REDEEMABLE NONCONTROLLING INTERESTS 15 15 15 15
EQUITY:
Total partners’ capital 12,966 12,070 12,966 12,070
Noncontrolling interest 7,005 6,194 5,943 5,152
Predecessor equity 7,907 8,089
Total equity 19,971 18,264 26,816 25,311
Total liabilities and equity $ 50,629 $ 48,221 $ 65,367 $ 62,674
(1) The Regency Merger is a combination of entities under common control. Beginning with the quarter ending June 30, 2015, ETP’s GAAP financial statements will reflect retrospective consolidation of Regency. The pro forma amounts reflect the retrospective consolidation of Regency.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per unit data)

(unaudited)

Actual Pro Forma for Regency Merger(1)
Three Months Ended
March 31,
Three Months Ended
March 31,
2015 2014 2015 2014
REVENUES $ 9,530 $ 12,232 $ 10,326 $ 13,027
COSTS AND EXPENSES:
Cost of products sold 8,040 10,866 8,487 11,442
Operating expenses 485 336 619 414
Depreciation, depletion and amortization 322 266 479 360
Selling, general and administrative 100 76 133 105
Total costs and expenses 8,947 11,544 9,718 12,321
OPERATING INCOME 583 688 608 706
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized (228 ) (219 ) (310 ) (274 )
Equity in earnings of unconsolidated affiliates 40 79 57 104
Gain on sale of AmeriGas common units 70 70
Losses on interest rate derivatives (77 ) (2 ) (77 ) (2 )
Other, net 3 (3 ) 7
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE 321 613 285 604
Income tax expense from continuing operations 13 146 17 145
INCOME FROM CONTINUING OPERATIONS 308 467 268 459
Income from discontinued operations 24 24
NET INCOME 308 491 268 483
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST 27 76 1 54
LESS: NET INCOME ATTRIBUTABLE TO PREDECESSOR (14 ) 14
NET INCOME ATTRIBUTABLE TO PARTNERS 281 415 281 415
General Partner’s interest in net income 242 113 242 192
Class H Unitholder’s interest in net income 54 49 54 49
Class I Unitholder’s interest in net income 33 33
Common Unitholders’ interest in net income (loss) $ (48 ) $ 253 $ (48 ) $ 174
INCOME (LOSS) FROM CONTINUING OPERATIONS PER COMMON UNIT:
Basic $ (0.17 ) $ 0.69 $ (0.09 ) $ 0.36
Diluted $ (0.17 ) $ 0.69 $ (0.09 ) $ 0.36
NET INCOME (LOSS) PER COMMON UNIT:
Basic $ (0.17 ) $ 0.76 $ (0.09 ) $ 0.41
Diluted $ (0.17 ) $ 0.76 $ (0.09 ) $ 0.41
WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING:
Basic 323.8 324.5 495.8 420.3
Diluted 323.8 325.5 493.5 421.3

(1) See Footnote 1 of the condensed consolidated balance sheets.

SUPPLEMENTAL INFORMATION

(Tabular dollar amounts in millions)

(unaudited)

Actual Pro Forma (a)
Three Months Ended
March 31,
Three Months Ended
March 31,
2015 2014 2015 2014
Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow (b):
Net income $ 308 $ 491 $ 268 $ 483
Interest expense, net of interest capitalized 228 219 310 274
Gain on sale of AmeriGas common units (70 ) (70 )
Income tax expense from continuing operations (c) 13 146 17 145
Depreciation, depletion and amortization 322 266 479 360
Non-cash compensation expense 16 14 20 17
Losses on interest rate derivatives 77 2 77 2
Unrealized losses on commodity risk management activities 66 29 77 32
Inventory valuation adjustments 34 (14 ) 34 (14 )
Equity in earnings of unconsolidated affiliates (40 ) (79 ) (57 ) (104 )
Adjusted EBITDA related to unconsolidated affiliates 127 196 144 210
Other, net (2 ) 6 (4 ) 2
Adjusted EBITDA (consolidated) 1,149 1,206 1,365 1,337
Adjusted EBITDA related to unconsolidated affiliates (127 ) (196 ) (144 ) (210 )
Distributions from unconsolidated affiliates (d) 75 81 111 109
Interest expense, net of interest capitalized (228 ) (219 ) (310 ) (274 )
Amortization included in interest expense (13 ) (16 ) (13 ) (14 )
Current income tax (expense) benefit from continuing operations 9 (253 ) 9 (253 )
Transaction-related income taxes (e) 306 306
Maintenance capital expenditures (62 ) (39 ) (84 ) (64 )
Other, net 4 2 3 2
Distributable Cash Flow (consolidated) 807 872 937 939
Distributable Cash Flow attributable to SXL (100%) (160 ) (157 ) (160 ) (157 )
Distributions from SXL to ETP 90 62 90 62
Distributable Cash Flow attributable to Sunoco LP (100%) (33 ) (33 )
Distributions from Sunoco LP to ETP 12 12
Distributions to Regency in respect of Lone Star (f) (35 ) (33 )
Distributable Cash Flow attributable to the partners of ETP 681 744 846 844
Bakken Pipeline Transaction – pro forma interest expense (g) 6 6
Transaction-related expenses 5 5
Distributable Cash Flow attributable to the partners of ETP, as adjusted $ 692 $ 744 $ 857 $ 844
Distributions to the partners of ETP (h):
Limited Partners (i):
Common Units held by public $ 330 $ 266 $ 465 $ 390
Common Units held by ETE 29 24 29
Class H Units held by ETE and ETE Common Holdings, LLC (“ETE Holdings”) (j) 56 50 56 50
General Partner interests held by ETE 8 5 8 5
Incentive Distribution Rights (“IDRs”) held by ETE 199 168 300 242
IDR relinquishments net of Class I Unit distributions (7 ) (57 ) (27 ) (57 )
Total distributions to be paid to the partners of ETP $ 586 $ 461 $ 826 $ 659
Distribution coverage ratio (k)

1.18

x

1.61

x

1.04

x

1.28

x

Distributable Cash Flow per Common Unit (l) $ 1.35 $ 1.78 $ 1.05 $ 1.44

(a) Pro forma amounts reflect the combined results of ETP and Regency assuming the Regency Merger closed January 1, 2014.

(b) 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 gross margin, operating income, net income, and cash flow from operating activities.

Definition of Adjusted EBITDA

ETP defines Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, 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 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 (excluding lower of cost or market 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 ETP’s 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

ETP defines Distributable Cash Flow as net income, adjusted for certain non-cash items, less maintenance capital expenditures. Non-cash items include depreciation and amortization, 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 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). Distributable Cash Flow reflects earnings from unconsolidated affiliates on a cash basis.

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 ETP’s subsidiaries, the Distributable Cash Flow generated by ETP’s subsidiaries may not be available to be distributed to the partners of ETP. In order to reflect the cash flows available for distributions to the partners of ETP, ETP has reported Distributable Cash Flow attributable to the partners of ETP, 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 the partners of ETP 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 the partners of ETP is net of distributions to be paid by the subsidiary to the noncontrolling interests. As of March 31, 2015, Lone Star was such a subsidiary, as it was 30% owned by Regency, which was an unconsolidated affiliate.

The Partnership has presented Distributable Cash Flow in previous communications; however, the Partnership changed its calculation of this non-GAAP measure in recent periods and has revised amounts in prior periods to be consistent with the Partnership’s updated calculation of this measure.

Previously, the Partnership’s calculation of Distributable Cash Flow reflected income tax expense from continuing operations, which included current and deferred income taxes. Current income tax expense represents the estimated taxes that will be payable or refundable for the current period, while deferred income taxes represent the estimated tax effects of tax carryforwards and the reversal of temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The Partnership revised its calculation of Distributable Cash Flow to reflect current income tax expense from continuing operations, rather than total income tax expense from continuing operations. Management believes that this revised calculation is more useful and more accurately reflects the cash flows of the Partnership that are available for payment of distributions. Distributable Cash Flow previously reported for the three months ended March 31, 2014 has been revised to reflect these changes.

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

(c) Income tax expense is based on the earnings of our taxable subsidiaries. For the three months ended March 31, 2015, the Partnership’s income tax expense from continuing operations included favorable state income tax adjustments of $14 million. For the three months ended March 31, 2014, the Partnership’s income tax expense from continuing operations included unfavorable income tax adjustments of $85 million related to the Lake Charles LNG Transaction, which was treated as a sale for tax purposes.

(d) Distributions from unconsolidated affiliates for the pro forma three months ended March 31, 2015 and 2014 include $16 million and $15 million, respectively, of distributions paid to a subsidiary of ETP related to Regency.

(e) Transaction-related income taxes primarily included income tax expense related to the Lake Charles LNG Transaction. For the three months ended March 31, 2014, amounts previously reported for each of the interim periods have been adjusted to reflect income taxes related to other transactions, which amounts had not previously been reflected in the calculation of Distributable Cash Flow for such interim periods.

(f) Cash distributions to Regency in respect of Lone Star consist of cash distributions paid in arrears on a quarterly basis. These amounts are in respect of the periods then ended, including payments made in arrears subsequent to period end.

(g) Pro forma interest expense adjustment for $879 million cash payment received from ETE related to the Bakken Pipeline Transaction.

(h) Distributions on ETP Common Units, as reflected above, exclude cash distributions on ETP Common Units held by subsidiaries of ETP.

(i) For the three months ended March 31, 2015, the distributions to the partners of ETP reflected in the “actual” column exclude distributions related to the ETP Common Units that were issued in the Regency Merger.

(j) Distributions on the Class H Units for the three months ended March 31, 2015 and 2014 were calculated as follows:

Three Months Ended
March 31,
2015 2014
General partner distributions and incentive distributions from SXL $ 62 $ 39
90.05 % 50.05 %
Share of SXL general partner and incentive distributions payable to Class H Unitholder 56 20
Incremental distributions payable to Class H Unitholder (IDR subsidy offset)* 30
Total Class H Unit distributions $ 56 $ 50

* Incremental distributions previously paid to the Class H Unitholder were eliminated in Amendment No. 9 to ETP’s Amended and Restated Agreement of Limited Partnership effective in the first quarter of 2015.

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

(l) The Partnership defines Distributable Cash Flow per Common Unit for a period as the quotient of Distributable Cash Flow attributable to the partners of ETP, as adjusted, net of distributions related to the Class H Units, Class I Units and the General Partner and IDR interests, divided by the weighted average number of Common Units outstanding.

Similar to Distributable Cash Flow as described above, Distributable Cash Flow per Common Unit is a significant liquidity measure used by the Partnership’s senior management to compare net cash flows generated by the Partnership to the distributions the Partnership expects to pay to its unitholders. Using this measure, the Partnership’s management can compare Distributable Cash Flow attributable to the partners of ETP, as adjusted, among different periods on a per-unit basis.

Distributable Cash Flow per Common Unit is calculated as follows:

Actual Pro Forma
Three Months Ended
March 31,
Three Months Ended
March 31,
2015 2014 2015 2014
Distributable Cash Flow attributable to the partners of ETP, as adjusted $ 692 $ 744 $ 857 $ 844
Less:
Class H Units held by ETE and ETE Holdings (56 ) (50 ) (56 ) (50 )
General Partner interests held by ETE (8 ) (5 ) (8 ) (5 )
IDRs held by ETE (199 ) (168 ) (300 ) (242 )
IDR relinquishments net of Class I Unit distributions 7 57 27 57
$ 436 $ 578 $ 520 $ 604
Weighted average Common Units outstanding – basic 323.8 324.5 495.8 420.3
Distributable Cash Flow per Common Unit $ 1.35 $ 1.78 $ 1.05 $ 1.44

SUMMARY ANALYSIS OF QUARTERLY RESULTS BY SEGMENT

(Tabular dollar amounts in millions)
(unaudited)

Our segment results were presented based on the measure of Segment Adjusted EBITDA. The tables below identify the components of Segment Adjusted EBITDA, which was calculated as follows:

  • Gross margin, operating expenses, and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.
  • Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate gross margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.
  • Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.
  • Adjusted EBITDA related to unconsolidated affiliates. These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates. Amounts reflected are calculated consistently with our definition of Adjusted EBITDA.

Pro forma amounts reflect the combined results of ETP and Regency assuming the Regency Merger closed January 1, 2014.

Actual Pro Forma for Regency Merger
Three Months Ended
March 31,
Three Months Ended
March 31,
2015 2014 2015 2014
Segment Adjusted EBITDA:
Midstream $ 153 $ 126 $ 318 $ 236
Liquids transportation and services 166 128 166 128
Interstate transportation and storage 277 300 302 324
Intrastate transportation and storage 162 177 176 191
Investment in Sunoco Logistics 221 208 221 208
Retail marketing 129 109 129 109
All other 41 158 53 141
$ 1,149 $ 1,206 $ 1,365 $ 1,337

Midstream

Actual Pro Forma for Regency Merger
Three Months Ended
March 31,
Three Months Ended
March 31,
2015 2014 2015 2014
Gathered volumes (MMBtu/d) 3,657,371 2,558,851 9,413,358 5,221,201
NGLs produced (Bbls/d) 202,370 136,818 369,941 238,146
Equity NGLs (Bbls/d) 14,320 12,106 26,368 20,878
Revenues $ 531 $ 653 $ 1,406 $ 1,459
Cost of products sold 346 493 959 1,133
Gross margin 185 160 447 326

Unrealized losses on commodity risk management activities

11 3
Operating expenses, excluding non-cash compensation expense (30 ) (28 ) (138 ) (88 )
Selling, general and administrative expenses, excluding non-cash compensation expense (2 ) (6 ) (3 ) (7 )
Adjusted EBITDA related to unconsolidated affiliates 1 2
Segment Adjusted EBITDA $ 153 $ 126 $ 318 $ 236

Gathered volumes, NGLs produced and equity NGLs produced increased primarily due to increased production by our customers in the Eagle Ford Shale and the recent startup of the Rebel plant in the Permian Basin.

Segment Adjusted EBITDA for the midstream segment reflected an increase in gross margin as follows:

Actual Pro Forma for Regency Merger
Three Months Ended
March 31,
Three Months Ended
March 31,
2015 2014 2015 2014
Gathering and processing fee-based revenues $ 161 $ 123 $ 363 $ 219
Non fee-based contracts and processing 24 37 84 107
Total gross margin $ 185 $ 160 $ 447 $ 326

Midstream gross margin reflected an increase in fee-based revenues of $38 million primarily due to increased capacity from assets recently placed in service in the Eagle Ford Shale and Permian Basin and a change in contract terms on our Southeast Texas system where certain contracts were converted from non fee-based terms to fee-based. Lower commodity prices resulted in a decrease in non fee-based revenues of $24 million, which was partially offset by a $9 million increase in equity volumes due to production in the Eagle Ford Shale and Permian Basin.

Segment Adjusted EBITDA for the midstream segment also reflected lower selling, general and administrative expenses primarily due to a reduction in employee-related costs.

For the pro forma results, the increase in actual Segment Adjusted EBITDA, as discussed above, was incrementally increased due to Regency’s gathering and processing operations.

Liquids Transportation and Services

Three Months Ended
March 31,
2015 2014
Liquids transportation volumes (Bbls/d) 438,646 307,511
NGL fractionation volumes (Bbls/d) 226,041 156,898
Revenues $ 831 $ 830
Cost of products sold 637 671
Gross margin 194 159
Unrealized losses on commodity risk management activities 9 1
Operating expenses, excluding non-cash compensation expense (35 ) (28 )
Selling, general and administrative expenses, excluding non-cash compensation expense (4 ) (5 )
Adjusted EBITDA related to unconsolidated affiliates 2 1
Segment Adjusted EBITDA $ 166 $ 128

NGL transportation volumes increased approximately 98,000 Bbls/d on our wholly-owned and joint venture pipelines due to an increase in NGL production from our Jackson processing plants and volumes transported to our Mont Belvieu, Texas facilities via our Justice pipeline. The remainder of the increase was from volumes transported out of west Texas on our Lone Star pipeline system as producers ramped up volumes. Average daily fractionated volumes increased for the three months ended March 31, 2015 compared to the same period last year due to the ramp-up of our second 100,000 Bbls/d fractionator at Mont Belvieu, Texas, which was commissioned in October 2013. These volumes include all physical and contractual volumes where we collected a fractionation fee.

Segment Adjusted EBITDA for the liquids transportation and services segment reflected an increase in gross margin as follows:

Three Months Ended
March 31,
2015 2014
Transportation margin $ 81 $ 59
Processing and fractionation margin 65 49
Storage margin 44 40
Other margin 4 11
Total gross margin $ 194 $ 159

Transportation margin increased $11 million due to higher volumes transported out of west Texas and the Eagle Ford Shale on our Lone Star pipeline system, $9 million due to increases in NGL production from our processing plants that connect to various fractionators via our wholly-owned pipelines, and $2 million due to the recent commissioning of our wholly-owned crude pipeline.

Processing and fractionation margin increased primarily due to the ramp-up of Lone Star’s second fractionator at Mont Belvieu, Texas, which was commissioned in October 2013.

Storage margin reflected increases of approximately $6 million due to increased demand for leased storage capacity as a result of market conditions and higher ancillary fees associated with throughput volumes of $2 million. These increases in fee-based storage margin were offset by a decrease of $4 million from lower non fee-based storage activities, including blending activities.

Other margin decreased primarily due to the impact of the cold winter season in early 2014.

Segment Adjusted EBITDA for the liquids transportation and services segment also reflected an increase in operating expenses for the three months ended March 31, 2015 compared to the same period last year primarily due to the ramp-up of Lone Star’s second fractionator in Mont Belvieu, Texas, which was commissioned in October 2013.

Interstate Transportation and Storage

Actual Pro Forma for Regency Merger
Three Months Ended
March 31,
Three Months Ended
March 31,
2015 2014 2015 2014
Natural gas transported (MMBtu/d) 6,763,691 6,956,089 6,763,691 6,956,089
Natural gas sold (MMBtu/d) 16,656 15,783 16,656 15,783
Revenues $ 276 $ 298 $ 276 $ 298
Operating expenses, excluding non-cash compensation, amortization and accretion expenses (72 ) (71 ) (72 ) (71 )
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses (15 ) (14 ) (15 ) (14 )
Adjusted EBITDA related to unconsolidated affiliates 88 87 113 111
Segment Adjusted EBITDA $ 277 $ 300 $ 302 $ 324
Distributions from unconsolidated affiliates $ 49 $ 50 $ 69 $ 68

Transported volumes decreased primarily due to warmer weather in 2015 along the Panhandle pipeline, resulting in a decrease of 137,508 MMBtu/d, and declines in supply into the Sea Robin pipeline as a result of a customer maintenance related outage, resulting in a decrease of 78,260 MMBtu/d.

Segment Adjusted EBITDA for the interstate transportation and storage segment decreased primarily due to lower transportation loan-related revenues of approximately $23 million as a result of higher basis differentials in 2014 driven by the colder weather.

The pro forma results for adjusted EBITDA related to unconsolidated affiliates and distributions from unconsolidated affiliates reflect the impact of Regency’s investment in Midcontinent Express Pipeline LLC (“MEP”).

Intrastate Transportation and Storage

Actual Pro Forma for Regency Merger
Three Months Ended
March 31,
Three Months Ended
March 31,
2015 2014 2015 2014
Natural gas transported (MMBtu/d) 8,809,018 9,399,267 8,809,018 9,399,267
Revenues $ 586 $ 934 $ 586 $ 934
Cost of products sold 416 734 416 734
Gross margin 170 200 170 200
Unrealized losses on commodity risk management activities 35 27 35 27
Operating expenses, excluding non-cash compensation expense (36 ) (42 ) (36 ) (42 )
Selling, general and administrative expenses, excluding non-cash compensation expense (7 ) (7 ) (7 ) (7 )
Adjusted EBITDA related to unconsolidated affiliates (1 ) 14 13
Segment Adjusted EBITDA $ 162 $ 177 $ 176 $ 191
Distributions from unconsolidated affiliates $ 1 $ 1 $ 14 $ 11

Transported volumes declined compared to the same period last year primarily due to lower production from certain key shippers in the Barnett Shale region.

Intrastate transportation and storage gross margin decreased $17 million in margin from natural gas sales and other primarily due to a decrease in gains from derivatives. Additionally, retained fuel revenues decreased $15 million primarily due to the impact of the cold weather season in early 2014 and storage margin decreased $9 million principally driven by a decline in the spreads between the spot and forward prices on natural gas inventory held in the Bammel storage facility. These decreases were partially offset by an increase of $11 million in transportation fees primarily due to increased revenue from long-term fixed capacity fee contracts on our Houston pipeline system resulting from the renegotiation of existing contracts, as well as the initiation of new contracts.

The pro forma results for adjusted EBITDA related to unconsolidated affiliates and distributions from unconsolidated affiliates reflect the impact of Regency’s investment in RIGS Haynesville Partnership Co. (“HPC”).

Investment in Sunoco Logistics

Three Months Ended
March 31,
2015 2014
Revenues $ 2,572 $ 4,477
Cost of products sold 2,350 4,210
Gross margin 222 267
Unrealized (gains) losses on commodity risk management activities 15 (1 )
Operating expenses, excluding non-cash compensation expense (48 ) (39 )
Selling, general and administrative expenses, excluding non-cash compensation expense (22 ) (27 )
Inventory valuation adjustments 41
Adjusted EBITDA related to unconsolidated affiliates 13 8
Segment Adjusted EBITDA $ 221 $ 208
Distributions from unconsolidated affiliates $ 5 $ 2

Segment Adjusted EBITDA related to Sunoco Logistics increased due to the net impacts of the following:

  • an increase of $19 million from crude oil acquisition and marketing activities, primarily due to an increase of $17 million from higher realized crude margins and an increase of $1 million from increased crude oil volumes resulting from recent acquisitions and the expansion of the crude oil trucking fleet;
  • an increase of $26 million from products pipelines, primarily due to an increase of $12 million from higher throughput volumes and higher average pipeline revenue per barrel of $10 million, which were largely driven by contributions from Sunoco Logistics’ Mariner NGL pipeline projects, and increased contributions from Sunoco Logistics’ joint venture interests of $5 million; and
  • an increase of $2 million from crude oil pipelines, primarily due to higher throughput volumes of $10 million largely driven by expansion projects placed into service in Texas and Oklahoma during 2014, largely offset by lower average pipeline revenue per barrel of $7 million, which was impacted by reduced volumes on higher-priced tariff movements; partially offset by
  • a decrease of $34 million from terminal facilities, primarily due to lower results from products acquisition and marketing activities of $45 million. Sunoco Logistics utilized its storage capabilities to increase its level of certain refined products inventories in order to capture the contango market structure. These inventory positions, combined with the timing of butane blending sales, were negatively impacted by inventory valuation adjustments. This decrease in operating results was partially offset by higher contributions from Sunoco Logistics’ bulk marine and refined products terminals of $10 million.

Retail Marketing

Three Months Ended
March 31,
2015 2014
Retail gasoline outlets, end of period:
Total 6,683 5,122
Company-operated 1,258 529
Motor fuel sales:
Total gallons (in millions) 1,881 1,392
Company-operated (gallons/month per site) 156,456 178,448
Motor fuel gross profit (cents per gallon):
Total 12.9 8.4
Company-operated 26.0 22.1
Merchandise sales $ 481 $ 140
Revenues $ 4,805 $ 5,011
Cost of products sold 4,367 4,756
Gross margin 438 255
Unrealized losses on commodity risk management activities 2 3
Operating expenses, excluding non-cash compensation expense (271 ) (126 )
Selling, general and administrative expenses, excluding non-cash compensation expense (34 ) (10 )
Inventory valuation adjustments (7 ) (14 )
Adjusted EBITDA related to unconsolidated affiliates 1 1
Segment Adjusted EBITDA $ 129 $ 109

Retail marketing gross margin increased due to the net impacts of the following:

  • an increase of $184 million from the acquisition of Susser in August 2014;
  • favorable impact of $34 million from other recent acquisitions;
  • an increase of $33 million from stronger retail and wholesale motor fuel margins;
  • an increase of $4 million from other retail margins; partially offset by
  • a decrease of $45 million due to exceptionally strong results in 2014 from ethanol manufacturing and blending, largely related to weather related impacts and regional market dynamics;
  • unfavorable impact of $20 million in non-retail fuel activities; and
  • unfavorable impact of $7 million related to non-cash inventory valuation adjustments.

Segment Adjusted EBITDA for the retail marketing segment also reflected an increase in operating expenses and in selling, general and administrative expenses primarily due to recent acquisitions.

All Other

Actual Pro Forma for Regency Merger
Three Months Ended
March 31,
Three Months Ended
March 31,
2015 2014 2015 2014
Revenues $ 383 $ 591 $ 493 $ 660
Cost of products sold 374 564 389 574
Gross margin 9 27 104 86
Unrealized (gains) losses on commodity risk management activities 5 (1 ) 5 (1 )
Operating expenses, excluding non-cash compensation expense 5 (5 ) (21 ) (27 )
Selling, general and administrative expenses, excluding non-cash compensation expense (18 ) (11 ) (46 ) (36 )
Adjusted EBITDA related to discontinued operations 27 27
Adjusted EBITDA related to unconsolidated affiliates 25 102 3 75
Other 19 19 19 19
Elimination (4 ) (11 ) (2 )
Segment Adjusted EBITDA $ 41 $ 158 $ 53 $ 141
Distributions from unconsolidated affiliates $ 18 $ 26 $ 18 $ 26

Amounts reflected in our all other segment primarily include:

  • our natural gas marketing and compression operations;
  • an approximate 33% non-operating interest in PES, a refining joint venture;
  • our investment in Regency common and Class F units; and
  • our investment in AmeriGas until August 2014.

Segment Adjusted EBITDA decreased due to the net impact of the following:

  • a decrease of $77 million in Adjusted EBITDA related to unconsolidated affiliates, primarily due to a decrease of $51 million related to our investment in AmeriGas driven by a reduction in our investment due to the sale of AmeriGas common units in 2014 and lower earnings from our investment in PES of $21 million; and
  • Adjusted EBITDA related to discontinued operations of $27 million in the prior period related to a marketing business that was sold effective April 1, 2014.

For the pro forma results, the decrease in actual Segment Adjusted EBITDA, as discussed above, was partially offset by increases in Regency’s natural resources and contract services operations.

In connection with the Lake Charles LNG Transaction, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Lake Charles LNG’s regasification facility and the development of a liquefaction project at Lake Charles LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015. These fees were reflected in “Other” in the “All other” segment and for the three months ended March 31, 2015 were reflected as an offset to operating expenses of $6 million and selling, general and administrative expenses of $13 million in the consolidated statements of operations.

The decrease in cash distributions from unconsolidated affiliates was primarily due to a decrease of $11 million in cash distribution from our ownership in AmeriGas as a result of selling our interests in AmeriGas in 2014, partially offset by an increase of $2 million in cash distribution from our ownership in PES.

SUPPLEMENTAL INFORMATION ON CAPITAL EXPENDITURES

(Tabular amounts in millions)
(unaudited)

The following is a summary of capital expenditures (net of contributions in aid of construction costs) for the three months ended March 31, 2015, excluding Regency’s capital expenditures:

Growth Maintenance Total
Direct(1):
Midstream $ 248 $ 4 $ 252
Liquids transportation and services(2) 559 4 563
Interstate transportation and storage(2) 271 19 290
Intrastate transportation and storage 15 3 18
Retail marketing(3) 73 14 87
All other (including eliminations) 10 10
Total direct capital expenditures 1,176 44 1,220
Indirect(1):
Investment in Sunoco Logistics 416 15 431
Investment in Sunoco LP(3) 36 3 39
Total indirect capital expenditures 452 18 470
Total capital expenditures – actual 1,628 62 1,690
Regency capital expenditures (excluding contributions to Lone Star) 438 22 460
Total capital expenditures – pro forma for Regency Merger $ 2,066 $ 84 $ 2,150
(1) Indirect capital expenditures comprise those funded by our publicly traded subsidiaries; all other capital expenditures are reflected as direct capital expenditures.
(2) Includes 100% of Lone Star, Bakken and Rover’s capital expenditures.
(3) The retail marketing segment includes the investment in Sunoco LP, as well as ETP’s wholly-owned retail marketing operations. Capital expenditures by Sunoco LP are reflected as indirect because Sunoco LP is a publicly traded subsidiary.

We currently expect capital expenditures (net of contributions in aid of construction costs) for the full year 2015 to be within the following ranges, including Regency’s expected capital expenditures:

Growth Maintenance
Low High Low High
Direct(1):
Midstream $ 1,900 $ 2,000 $ 90 $ 110
Liquids transportation and services:
NGL(2) 1,700 1,750 25 30
Crude(3) 700 750
Interstate transportation and storage(3) 750 850 100 115
Intrastate transportation and storage 150 200 30 35
Retail marketing(4) 200 250 80 100
All other (including eliminations) 200 250 35 45
Total direct capital expenditures 5,600 6,050 360 435
Indirect(1):
Investment in Sunoco Logistics 2,400 2,600 65 75
Investment in Sunoco LP(4) 180 230 15 25
Total indirect capital expenditures 2,580 2,830 80 100
Total projected capital expenditures $ 8,180 $ 8,880 $ 440 $ 535
(1) Indirect capital expenditures comprise those funded by our publicly traded subsidiaries; all other capital expenditures are reflected as direct capital expenditures.
(2) Includes 100% of Lone Star’s capital expenditures.
(3) Includes capital expenditures related to our proportionate ownership of the Bakken and Rover pipeline projects.
(4) The retail marketing segment includes the investment in Sunoco LP, as well as ETP’s wholly-owned retail marketing operations. Capital expenditures by Sunoco LP are reflected as indirect because Sunoco LP is a publicly traded subsidiary.

SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES

(In millions)

(unaudited)

Three Months Ended
March 31,
2015 2014
Equity in earnings (losses) of unconsolidated affiliates:
Citrus $ 19 $ 18
FEP 14 14
Regency 4 (7 )
PES (9 ) 17
AmeriGas 6 34
Other 6 3
Total equity in earnings of unconsolidated affiliates – actual $ 40 $ 79
MEP 12 11
HPC 9 7
Other and eliminations (4 ) 7
Total equity in earnings of unconsolidated affiliates – pro forma for Regency Merger $ 57 $ 104
Adjusted EBITDA related to unconsolidated affiliates:
Citrus $ 69 $ 68
FEP 19 19
Regency 23 27
PES 2 23
AmeriGas 51
Other 14 8
Total Adjusted EBITDA related to unconsolidated affiliates – actual $ 127 $ 196
MEP 24 26
HPC 15 14
Other and eliminations (22 ) (26 )
Total Adjusted EBITDA related to unconsolidated affiliates – pro forma for Regency Merger $ 144 $ 210
Distributions received from unconsolidated affiliates:
Citrus $ 33 $ 34
FEP 16 16
Regency 16 15
PES 2
AmeriGas 11
Other 8 5
Total distributions received from unconsolidated affiliates – actual $ 75 $ 81
MEP 20 18
HPC 13 10
Other and eliminations 3
Total distributions received from unconsolidated affiliates – pro forma for Regency Merger $ 111 $ 109

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