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Regency Energy Partners Reports Full-Year 2014 Results

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Regency Energy Partners LP (NYSE:RGP) , (“Regency” or the “Partnership”), announced today its financial results for the fourth-quarter and full-year ended December 31, 2014.

For full-year 2014, adjusted EBITDA increased 93 percent to $1.2 billion, compared to $608 million in 2013, primarily due to contributions from the midstream assets Regency acquired in 2014 from PVR Partners, L.P. (“PVR”), Hoover Energy Partners, LP (“Hoover”) and Eagle Rock Energy Partners, L.P. (“Eagle Rock”), volume growth in the gathering and processing segment, volume growth at the Lone Star Joint Venture, as well as an increase in revenue generating horsepower in the contract services segment.

For the year-ended December 31, 2014, Regency generated $786 million in distributable cash flow (“DCF”), compared to $411 million for full-year 2013.

For the year ended December 31, 2014, Regency reported a net loss of $157 million, compared to net income of $19 million for the year ended December 31, 2013. Increases in segment margin and investment in unconsolidated affiliates were offset by a goodwill impairment charge related to the Permian region within the gathering and processing segment, as well as increases in depreciation, depletion, and amortization, operation and maintenance expenses, interest expense, and general and administrative expenses as a result of the Hoover, PVR and Eagle Rock midstream acquisitions.

REVIEW OF SEGMENT PERFORMANCE

Adjusted total segment margin increased to $1.4 billion for full-year 2014, compared to $729 million full-year 2013.

Gathering and Processing – Regency provides “wellhead-to-market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs from the raw natural gas, and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems, the gathering of oil (crude and/or condensate, a lighter oil) received from producers, the gathering and disposing of salt water, and natural gas and NGL marketing and trading. This segment also includes our 60% membership interest in ELG, which operates natural gas gathering, oil pipeline, and oil stabilization facilities in south Texas, a 33.33% membership interest in Ranch JV, which processes natural gas delivered from NGL – rich shale formations in west Texas, our 50% partnership interest in Sweeny JV, which operates a natural gas gathering facility in south Texas, our 51% membership interest in Aqua – PVR, which transports and supplies fresh water to natural gas producers in the Marcellus shale in Pennsylvania, our 75% membership interest in ORS, which will operate a natural gas gathering system in the Utica Shale in Ohio, and our 50% interest in Mi Vida JV, which will operate a cryogenic processing plant and related facilities in West Texas.

Adjusted segment margin for the Gathering and Processing segment, which excludes non-cash gains and losses from commodity derivatives, was $1.1 billion for full-year 2014, compared to $521 million for full year 2013. The increase was primarily due to volume growth in south and west Texas, and north Louisiana, and contributions from the PVR, Eagle Rock and Hoover acquisitions.

Total average throughput volumes for the Gathering and Processing segment increased to 4.8 million MMbtu per day of natural gas for full-year 2014, including 2.3 million MMbtu per day related to the PVR, Eagle Rock and Hoover acquisitions, compared to 2.1 million MMbtu per day of natural gas for full-year 2013. Processed NGLs increased to an average of 149,000 barrels per day for full year 2014, compared to 90,000 barrels per day for full-year 2013.

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

Segment margin for the Contract Services segment, including both revenues from external customers as well as intersegment revenues, was $254 million for full-year 2014, compared to $204 million for full-year 2013. The increase in segment margin is primarily due to an increase in revenue generating horsepower, inclusive of intersegment revenue generating horsepower. As of December 31, 2014, the Contract Services segment’s revenue generating horsepower, including intersegment revenue generating horsepower, increased to 1,303,000, compared to 1,049,000 as of December 31, 2013, inclusive of 28,000 and 44,000, respectively, of revenue generating horsepower utilized by the Gathering and Processing segment.

Natural Resources – Regency is involved in the management of coal and natural resource properties and the related collection of royalties. The Partnership also earns revenues from other land management activities, including selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. This segment included the Partnership’s 50% interest in Coal Handling, which owned and operated end-user coal handling facilities. Regency purchased the remaining 50% interest in Coal Handling, effective December 31, 2014.

Natural Resources segment margin was $58 million from March 21, 2014 (the date of the acquisition) to December 31, 2014. Coal royalty tonnage for the same period was 11,265 for an average royalty per ton of $3.91.

Corporate – The Corporate segment comprises our corporate offices. Segment margin in the Corporate segment was $12 million for full-year 2014, compared to $18 million for full-year 2013.

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

RIGS consists solely of the Regency Intrastate Gas System and is operated by Regency. Income from unconsolidated affiliates for RIGS was $27 million for full year 2014, compared to $30 million for full year 2013. Total throughput volumes for RIGS averaged 662,000 MMbtu per day of natural gas for full-year 2014, compared to 648,000 MMbtu per day for full-year 2013.

The MEP Joint Venture consists solely of MEP and is operated by Kinder Morgan Energy Partners L.P. Income from unconsolidated affiliates for the MEP Joint Venture was $45 million for full-year 2014, compared to $40 million for full-year 2013. Total throughput volumes for the MEP Joint Venture averaged 1.2 million MMbtu per day of natural gas for full-year 2014 and 1.3 million MMbtu per day for full-year 2013.

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

Income from unconsolidated affiliates for NGL Services was $116 million for full-year 2014, compared to $64 million for full-year 2013. Transportation volumes averaged 211,000 barrels per day for full-year 2014, compared to 164,000 barrels per day for full-year 2013. Refinery Services throughput averaged 14,000 barrels per day for full-year 2014, compared to 13,000 barrels per day for full-year 2013. NGL Fractionation volumes for the first two fractionators, which came online in December 2012 and November 2013, respectively, averaged 179,000 barrels per day for full-year 2014, compared to 78,000 barrels per day for full-year 2013.

ORGANIC GROWTH

For the year ended December 31, 2014, Regency incurred $1.2 billion of growth capital expenditures: $749 million for the Gathering and Processing segment, $325 million for the Contract Services segment, $99 million for the NGL Services segment and $4 million for the Natural Gas Transportation segment.

For the year ended December 31, 2014, Regency incurred $98 million of maintenance capital expenditures.

In 2015, Regency expects to invest approximately $1.6 billion in growth capital expenditures, of which $1 billion is related to the Gathering and Processing segment, $400 million is related to the NGL Services segment and $200 million is related to the Contract Services segment.

In addition, Regency expects to invest approximately $100 million in maintenance capital expenditures in 2015, including its proportionate share related to joint ventures.

CASH DISTRIBUTIONS

On January 26, 2015, Regency announced a cash distribution of $0.5025 per outstanding common unit for the fourth quarter ended December 31, 2014. This distribution is equivalent to $2.01 per outstanding common unit on an annual basis and was paid on February 13, 2015, to unitholders of record at the close of business on February 6, 2015.

Based on the terms of the partnership agreement, the Series A Preferred Units were paid a quarterly distribution of $0.445 per unit for the fourth quarter-ended December 31, 2014, on the same schedule as set forth above.

For the full-year 2014, Regency generated $786 million in distributable cash flow, representing 0.97 times the amount required to cover its announced distribution to unitholders.

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

TELECONFERENCE

Regency Energy Partners will hold a quarterly conference call to discuss its fourth-quarter and full-year 2014 results on Thursday, February 19, 2015, at 10 a.m. Central Time (11 a.m. Eastern Time).

The dial-in number for the call is 1-866-700-0133 in the United States, or +1-617-213-8831 outside the United States, passcode 74671930. A live webcast of the call may be accessed on the Investor Relations page of Regency’s website at www.regencyenergy.com. The call will be available for replay for seven days by dialing 1-888-286-8010 (from outside the U.S., +1-617-801-6888) passcode 78485780. A replay of the broadcast will also be available on the Partnership’s website for 30 days.

NON-GAAP FINANCIAL INFORMATION

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

  • EBITDA;
  • adjusted EBITDA;
  • distributable cash flow;
  • segment margin;
  • total segment margin;
  • adjusted segment margin; and
  • adjusted total segment margin.

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

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

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

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

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

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

We define distributable cash flow as adjusted EBITDA:

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

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

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

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

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

Operation and maintenance expense is a separate measure used by management to evaluate operating performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operation and maintenance expense. These expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. We do not deduct operation and maintenance expenses from total revenues in calculating total segment margin and adjusted total segment margin because we separately evaluate commodity volume and price changes.

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

FORWARD-LOOKING INFORMATION AND OTHER DISCLAIMERS

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

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

Condensed Consolidated Balance Sheets

Regency Energy Partners LP
Condensed Consolidated Balance Sheets
($ in millions)
December 31, 2014 December 31, 2013
Assets
Current assets $ 703 $ 400
Property, plant and equipment, net 9,217 4,418
Investment in unconsolidated affiliates 2,418 2,097
Other assets, net 103 57
Intangible assets, net 3,439 682
Goodwill 1,223 1,128
Total Assets $ 17,103 $ 8,782
Liabilities and Partners’ Capital and Noncontrolling Interest
Current liabilities $ 756 $ 475
Other long-term liabilities 88 49
Long-term debt 6,641 3,310
Total Liabilities $ 7,485 $ 3,834
Series A Preferred Units 33 32
Partners’ capital 9,465 4,814
Noncontrolling interest 120 102
Total Partners’ Capital and Noncontrolling Interest 9,585 4,916
Total Liabilities and Partners’ Capital and Noncontrolling Interest $ 17,103 $ 8,782

Condensed Consolidated Statements of Operations

Regency Energy Partners LP
Condensed Consolidated Statements of Operations
($ in millions)
Three Months Ended December 31,
2014 2013 2012
REVENUES $ 1,427 $ 677 $ 587
OPERATING COSTS AND EXPENSES
Cost of sales 935 484 428
Operation and maintenance 148 76 69
General and administrative 35 24 22
Loss on asset sales, net 1 1
Depreciation, depletion and amortization 157 80 59
Goodwill impairment 370
Total operating costs and expenses 1,645 665 579
OPERATING (LOSS) INCOME (218 ) 12 8
Income from unconsolidated affiliates 52 32 18
Interest expense, net (84 ) (45 ) (36 )
Loss on debt refinancing, net (27 )
Other income and deductions, net 19 3 3
(LOSS) INCOME BEFORE INCOME TAXES (258 ) 2 (7 )
Income tax (benefit) expense (1 ) 1
NET (LOSS) INCOME $ (257 ) $ 2 $ (8 )
Net income attributable to noncontrolling interest (4 ) (3 )
NET (LOSS) INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP $ (261 ) $ (1 ) $ (8 )
Amount allocated to common units $ (272 ) $ (6 ) $ (14 )
Weighted average number of common units outstanding 404,690,546 210,747,732 170,841,959
Basic loss per common unit $ (0.67 ) $ (0.03 ) $ (0.08 )
Diluted loss per common unit $ (0.67 ) $ (0.03 ) $ (0.08 )

Condensed Consolidated Statements of Operations

Regency Energy Partners LP
Condensed Consolidated Statements of Operations
($ in millions)
Years ended December 31,
2014 2013 2012
REVENUES $ 4,951 $ 2,521 $ 2,000
OPERATING COSTS AND EXPENSES
Cost of sales 3,452 1,793 1,387
Operation and maintenance 448 296 228
General and administrative 158 88 100
(Gain) loss on asset sales, net (1 ) 2 3
Depreciation, depletion and amortization 541 287 252
Goodwill impairment 370
Total operating costs and expenses 4,968 2,466 1,970
OPERATING (LOSS) INCOME (17 ) 55 30
Income from unconsolidated affiliates 195 135 105
Interest expense, net (304 ) (164 ) (122 )
Loss on debt refinancing, net (25 ) (7 ) (8 )
Other income and deductions, net 12 7 29
(LOSS) INCOME BEFORE INCOME TAXES (139 ) 26 34
Income tax expense (benefit) 3 (1 )
NET (LOSS) INCOME $ (142 ) $ 27 $ 34
Net income attributable to noncontrolling interest (15 ) (8 ) (2 )
NET (LOSS) INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP $ (157 ) $ 19 $ 32
Amount allocated to common units $ (199 ) $ 34 $ 27
Weighted average number of common units outstanding 348,070,121 196,227,348 167,492,735
Basic (loss) income per common unit $ (0.57 ) $ 0.17 $ 0.16

Diluted (loss) income per common unit

$ (0.57 ) $ 0.17 $ 0.13

Segment Financial and Operating Data

Three Months Ended December 31, Years Ended December 31,
2014 2013 2012 2014 2013 2012
($ in millions)
Gathering and Processing Segment
Financial data:
Segment margin $ 405 $ 138 $ 109 $ 1,189 $ 520 $ 423
Adjusted segment margin 327 142 109 1,089 521 412
Operating data:
Throughput (MMbtu/d) 5,916,000 2,216,000 2,008,000 4,800,000 2,141,000 1,793,000
NGL gross production (Bbls/d) 180,000 92,000 83,000 149,000 90,000 69,000
Three Months Ended December 31, Years Ended December 31,
2014 2013 2012 2014 2013 2012
($ in millions)
Contract Services
Financial data:
Segment margin $ 69 $ 55 $ 50 $ 254 $ 204 $ 189
Operating data:
Revenue generating horsepower, including intercompany revenue generating horsepower 1,303,000 1,049,000 884,000 1,303,000 1,049,000 884,000
Three Months Ended December 31, Years Ended December 31,
2014 2013 2012 2014 2013 2012
($ in millions)
Natural Resources
Financial data:
Segment margin * $ 18 $ $ $ 58 $ $
Operating data:
Coal royalty tonnage 3,238 11,265
Average coal royalties per ton $ 3.91 $ $ $ 3.91 $ $
* The Natural Resources segment was acquired in the PVR acquisition on March 21, 2014.
Three Months Ended December 31, Years Ended December 31,
2014 2013 2012 2014 2013 2012
($ in millions)
Corporate Segment
Financial data:
Segment margin $ 3 $ 4 $ 6 $ 12 $ 18 $ 20

Reconciliation of Non-GAAP Measures to GAAP Measures

Three Months Ended December 31,
2014 2013 2012
($ in millions)
Net (loss) income $ (257 ) $ 2 $ (8 )
Add (deduct):
Interest expense, net 84 45 36
Depreciation, depletion and amortization 157 80 59
Goodwill impairment 370
Income tax (benefit) expense (1 ) 1
EBITDA (1) $ 353 $ 127 $ 88
Add (deduct):
Partnership’s interest in unconsolidated affiliates’ adjusted EBITDA (2) 85 62 52
Income from unconsolidated affiliates (52 ) (32 ) (18 )
Non-cash (gain) loss from commodity and embedded derivatives (89 ) 3 (2 )
Loss on debt refinancing, net 27
Loss on asset sales, net 1 1
Other income, net (6 ) (1 ) 2
Adjusted EBITDA $ 318 $ 160 $ 123
(1) Earnings before interest, taxes, depreciation and amortization.
(2) The following table presents reconciliations of net income to adjusted EBITDA for our unconsolidated affiliates, on a 100% basis, and our interest in adjusted EBITDA for the three months ended December 31, 2014, 2013, and 2012:
Three months ended December 31, 2014
HPC MEP Lone Star Ranch JV Aqua JV Other Total
Net Income (Loss) $ 17 $ 25 $ 111 $ 9 $ (2 ) $ 1
Add:
Depreciation and amortization 8 18 28 3 1
Interest expense, net 3 7
Other expenses, net 1
Adjusted EBITDA 28 51 139 12 (1 ) 1
Ownership interest 49.99 % 50 % 30 % 33.33 % 51 % 50 %
Partnership’s interest in Adjusted EBITDA $ 15 $ 25 $ 41 $ 4 $ $ $ 85
Operating data
Throughput (MMbtu/d) 674,000 1,179,000 N/A 141,000 N/A N/A
NGL Transportation – Throughput (Bbls/d) N/A N/A 235,000 N/A N/A N/A
Refinery – Throughput (Bbls/d) N/A N/A 16,000 N/A N/A N/A
Fractionation – Throughput (Bbls/d) N/A N/A 193,000 N/A N/A N/A
Coal (tons) N/A N/A N/A N/A` N/A N/A
Three months ended December 31, 2013
HPC MEP Lone Star Ranch JV Other Total
Net Income (Loss) $ 16 $ 17 $ 54 $ 2 $ (1 )
Add:
Depreciation and amortization 9 17 24 1
Interest expense, net 3 13
Adjusted EBITDA 28 47 78 3 (1 )
Ownership interest 49.99 % 50 % 30 % 33.33 % 50.00 %
Partnership’s interest in Adjusted EBITDA $ 14 $ 24 $ 23 $ 1 $ $ 62
Operating data
Throughput (MMbtu/d) 524,000 1,271,000 N/A 96,000 N/A
NGL Transportation – Throughput (Bbls/d) (1) N/A N/A 170,000 N/A N/A
Refinery – Throughput (Bbls/d) N/A N/A 9,000 N/A N/A
Fractionation – Throughput (Bbls/d) (2) N/A N/A 103,000 N/A N/A
Three months ended December 31, 2012
HPC MEP Lone Star Ranch JV Other Total
Net Income (Loss) $ 14 $ 22 $ 37 $ (1 ) $ (18 )
Add:
Depreciation and amortization 9 17 14 1
Interest expense, net 1 13
Impairment of property, plant, and equipment 8 8
Adjusted EBITDA 32 52 51 (10 )
Ownership interest 49.99 % 50 % 30 % 33.33 % 50.00 %
Partnership’s interest in Adjusted EBITDA $ 16 $ 26 $ 15 $ $ (5 ) $ 52
Operating data
Throughput (MMbtu/d) 748,000 1,397,000 N/A 5,200 N/A
NGL Transportation – Throughput (Bbls/d) (1) N/A N/A 137,000 N/A N/A
Refinery – Throughput (Bbls/d) N/A N/A 17,700 N/A N/A
Fractionation – Throughput (Bbls/d) (2) N/A N/A N/A N/A

Reconciliation of Non-GAAP Measures to GAAP Measures

Years ended December 31,
2014 2013 2012
($ in millions)
Net (loss) income $ (142 ) $ 27 $ 34
Add (deduct):
Interest expense, net 304 164 122
Depreciation and amortization 541 287 252
Goodwill impairment 370
Income tax expense (benefit) 3 (1 )
EBITDA (1) $ 1,076 $ 477 $ 408
Add (deduct):
Partnership’s interest in unconsolidated affiliates’ adjusted EBITDA (2) 325 250 222
Income from unconsolidated affiliates (195 ) (135 ) (105 )
Non-cash (gain) loss from commodity and embedded derivatives (92 ) 3 (19 )
Loss on debt refinancing, net 25 7 8
(Gain) loss on asset sales, net (1 ) 2 3
Other expense, net 34 4
Adjusted EBITDA $ 1,172 $ 608 $ 517
(1) Earnings before interest, taxes, depreciation and amortization.
(2) The following table presents reconciliations of net income to adjusted EBITDA for our unconsolidated affiliates, on a 100% basis, and our interest in adjusted EBITDA for the years ended December 31, 2014, 2013, and 2012:
Years ended December 31, 2014
HPC MEP Lone Star Ranch JV Aqua JV Other Total
Net Income (Loss) $ 67 $ 89 $ 387 $ 29 $ (7 ) $ 4
Add:
Depreciation and amortization 36 69 106 6 8 2
Interest expense, net 13 45
Other expenses, net 1 3 1
Adjusted EBITDA 116 204 496 36 1 6
Ownership interest 49.99 % 50 % 30 % 33.33 % 51 % 50 %
Partnership’s interest in Adjusted EBITDA $ 58 $ 102 $ 149 $ 12 $ 1 $ 3 $ 325
Operating data
Throughput (MMbtu/d) 662,000 1,205,000 N/A 136,000 N/A N/A
NGL Transportation – Throughput (Bbls/d) (1) N/A N/A 211,000 N/A N/A N/A
Refinery – Throughput (Bbls/d) N/A N/A 14,000 N/A N/A N/A
Fractionation – Throughput (Bbls/d) (2) N/A N/A 179,000 N/A N/A N/A
Coal (tons) N/A N/A N/A N/A N/A N/A
Years ended December 31, 2013
HPC MEP Lone Star Ranch JV Other Total
Net Income (Loss) $ 72 $ 80 $ 214 $ 4 $ (1 )
Add:
Depreciation and amortization 37 69 84 5
Interest expense, net 5 51
Other expenses, net 2
Adjusted EBITDA 114 200 300 9 (1 )
Ownership interest 49.99 % 50 % 30 % 33.33 % 50 %
Partnership’s interest in Adjusted EBITDA $ 57 $ 100 $ 90 $ 3 $ $ 250
Operating data
Throughput (MMbtu/d) 648,000 1,315,000 N/A 73,000 N/A
NGL Transportation – Throughput (Bbls/d) (1) N/A N/A 164,000 N/A N/A
Refinery – Throughput (Bbls/d) N/A N/A 13,000 N/A N/A
Fractionation – Throughput (Bbls/d) (2) N/A N/A 78,000 N/A N/A
Years ended December 31, 2012
HPC MEP Lone Star Ranch JV Other Total
Net Income (Loss) $ 70 $ 83 $ 147 $ (2 ) $ (18 )
Add:
Depreciation and amortization 36 69 52 1
Interest expense, net 2 52
Impairment of property, plant, and equipment 22 8
Other expenses, net 2
Adjusted EBITDA 132 204 199 (1 ) (10 )
Ownership interest 49.99 % 50 % 30 % 33.33 % 50 %
Partnership’s interest in Adjusted EBITDA $ 65 $ 102 $ 60 $ $ (5 ) $ 222
Operating data
Throughput (MMbtu/d) 854,000 1,409,000 N/A 3,300 N/A
NGL Transportation – Throughput (Bbls/d) (1) N/A N/A 134,000 N/A N/A
Refinery – Throughput (Bbls/d) N/A N/A 17,000 N/A N/A
Fractionation – Throughput (Bbls/d) N/A N/A N/A N/A
(1) Includes Gateway Pipeline throughput which was placed in service in December 2012.
(2) Fractionator began operations in December 2012.

Non-GAAP Adjusted Total Segment Margin to GAAP Net Income

Three Months Ended December 31,
2014 2013 2012
($ in millions)
Net (Loss) Income $ (257 ) $ 2 $ (8 )
Add (Deduct):
Operation and maintenance 148 76 69
General and administrative 35 24 22
Loss on asset sales, net 1 1
Depreciation, depletion and amortization 157 80 59
Goodwill impairment 370
Income from unconsolidated affiliates (52 ) (32 ) (18 )
Interest expense, net 84 45 36
Loss on debt refinancing, net 27
Other income and deductions, net (19 ) (3 ) (3 )
Income tax (benefit) expense (1 ) 1
Total Segment Margin 492 193 159
Non-cash (gain) loss from commodity derivatives (76 ) 7 2
Segment margin related to the noncontrolling interest (6 ) (5 ) (2 )
Segment margin related to ownership percentage in Ranch JV 4 2
Adjusted Total Segment Margin $ 414 $ 197 $ 159
Gathering & Processing Segment Margin $ 405 $ 138 $ 109
Non-cash (gain) loss from commodity derivatives (76 ) 7 2
Segment margin related to the noncontrolling interest (6 ) (5 ) (2 )
Segment margin related to ownership percentage in Ranch JV 4 2
Adjusted Gathering and Processing Segment Margin 327 142 109
Natural Gas Transportation Segment Margin
Contract Services Segment Margin * 69 55 50
Corporate Segment Margin 3 4 6
Natural Resources Segment Margin 18
Inter-segment Elimination * (3 ) (4 ) (6 )
Adjusted Total Segment Margin $ 414 $ 197 $ 159
* Inter-segment elimination is related to Contract Services segment margin.
Operating Data
Gathering and Processing Segment
Throughput (MMbtu/d) 5,916,000 2,216,000 4,800,000
NGL gross production (Bbls/d) 180,000 92,000 149,000
Natural Resources Segment
Coal royalty tonnage 3,238
Contract Services Segment
Revenue generating horsepower 1,303,000 1,049,000 884,000

Non-GAAP Adjusted Total Segment Margin to GAAP Net Income

Years ended December 31,
2014 2013 2012
($ in millions)
Net (Loss) Income $ (142 ) $ 27 $ 34
Add (Deduct):
Operation and maintenance 448 296 228
General and administrative 158 88 100
(Gain) loss on asset sales, net (1 ) 2 3
Depreciation, depletion and amortization 541 287 252
Goodwill impairment 370
Income from unconsolidated affiliates (195 ) (135 ) (105 )
Interest expense, net 304 164 122
Loss on debt refinancing, net 25 7 8
Other income and deductions, net (12 ) (7 ) (29 )
Income tax expense (benefit) 3 (1 )
Total Segment Margin 1,499 728 613
Non-cash (gain) loss from commodity derivatives (89 ) 9 (5 )
Segment margin related to the noncontrolling interest (25 ) (13 ) (6 )
Segment margin related to ownership percentage in Ranch JV 14 5
Adjusted Total Segment Margin $ 1,399 $ 729 $ 602
Gathering & Processing Segment Margin $ 1,189 $ 520 $ 423
Non-cash (gain) loss from commodity derivatives (89 ) 9 (5 )
Segment margin related to the noncontrolling interest (25 ) (13 ) (6 )
Segment margin related to ownership percentage in Ranch JV 14 5
Adjusted Gathering and Processing Segment Margin 1,089 521 412
Natural Gas Transportation Segment Margin 1 2
Contract Services Segment Margin 254 204 189
Corporate Segment Margin * 12 18 20
Natural Resources Segment Margin 58
Inter-segment Elimination (14 ) (15 ) (21 )
Adjusted Total Segment Margin $ 1,399 $ 729 $ 602
* Inter-segment elimination is related to Contract Services segment margin.
Operating Data
Gathering and Processing Segment
Throughput (MMbtu/d) 4,800,000 2,141,000 1,793,000
NGL gross production (Bbls/d) 149,000 90,000 69,000
Natural Resources Segment
Coal royalty tonnage ** 11,265
Contract Services Segment
Revenue generating horsepower 1,303,000 1,049,000 884,000
** Represents coal royalty tonnage for the period from March 21, 2014 (the acquisition date) to December 31, 2014.

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

Three Months Ended December 31,
2014 2013 2012
($ in millions)
Net Cash Flows Provided by Operating Activities $ 149 $ 59 $ 68
Add (deduct):
Depreciation, depletion and amortization, including debt issuance cost amortization and bond premium write-off and amortization (162 ) (82 ) (62 )
Income from unconsolidated affiliates 52 32 18
Derivative valuation change 90 (3 ) 2
Loss on asset sales, net (1 ) (1 )
Unit-based compensation expenses (2 ) (2 ) (2 )
Revaluation of unconsolidated affiliate upon acquisition 6

Goodwill impairment (370 )

Cash flow changes in current assets and liabilities:
Trade accounts receivables and related party receivables (73 ) 23 9
Other current assets and other current liabilities 18 28 43
Trade accounts payable and related party payables 89 (20 ) (51 )
Distributions of earnings received from unconsolidated affiliates (57 ) (33 ) (29 )
Cash flow changes in other assets and liabilities 3 1 (3 )
Net (Loss) Income $ (257 ) $ 2 $ (8 )
Add:
Interest expense, net 84 45 36
Depreciation, depletion and amortization 157 80 59
Goodwill impairment 370
Income tax (benefit) expense (1 ) 1
EBITDA $ 353 $ 127 $ 88
Add (deduct):
Partnership’s interest in unconsolidated affiliates’ adjusted EBITDA 85 62 52
Income from unconsolidated affiliates (52 ) (32 ) (18 )
Non-cash (gain) loss from commodity and embedded derivatives (89 ) 3 (2 )
Loss on debt refinancing, net 27
Loss on asset sales, net 1 1
Other, net (6 ) 4
Adjusted EBITDA $ 318 $ 165 $ 121
Add (deduct):
Interest expense, excluding capitalized interest (94 ) (51 ) (41 )
Maintenance capital expenditures (37 ) (18 ) (8 )
Proceeds from asset sales 4 2 4
Other adjustments (7 ) (4 ) (4 )
Distributable Cash Flow $ 184 $ 94 $ 68

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

Years Ended December 31,
2014 2013 2012
($ in millions)
Net Cash Flows Provided by Operating Activities $ 719 $ 436 $ 324
Add (deduct):
Depreciation, depletion and amortization, including debt issuance cost amortization and bond premium write-off and amortization (525 ) (293 ) (259 )
Income from unconsolidated affiliates 195 135 105
Derivative valuation change 93 (6 ) 12
Gain (loss) on asset sales, net 1 (2 ) (3 )
Unit-based compensation expenses (10 ) (7 ) (5 )
Revaluation of unconsolidated affiliate upon acquisition 6
Goodwill impairment (370 )
Cash flow changes in current assets and liabilities:
Trade accounts receivables and related party receivables (28 ) 96
Other current assets and other current liabilities (34 ) 54 (10 )
Trade accounts payable, related party payables and deferred revenues 16 (119 ) (18 )
Distributions of earnings received from unconsolidated affiliates (204 ) (142 ) (121 )
Other assets and liabilities (1 ) (125 ) 9
Net (Loss) Income $ (142 ) $ 27 $ 34
Add:
Interest expense, net 304 164 122
Depreciation, depletion and amortization 541 287 252
Goodwill impairment 370
Income tax expense (benefit) 3 (1 )
EBITDA $ 1,076 $ 477 $ 408
Add (deduct):
Partnership’s interest in unconsolidated affiliates’ adjusted EBITDA 325 250 222
Income from unconsolidated affiliates (195 ) (135 ) (105 )
Non-cash (gain) loss from commodity and embedded derivatives (92 ) 3 (19 )
Loss on debt refinancing, net 25 7 8
(Gain) loss on asset sales, net (1 ) 2 3
Other, net 34 4
Adjusted EBITDA $ 1,172 $ 608 $ 517
Add (deduct):
Interest expense, excluding capitalized interest (364 ) (192 ) (151 )
Maintenance capital expenditures (101 ) (48 ) (34 )
SUGS Contribution Agreement adjustment * 34 (37 )
PVR DCF Contribution ** 83
Proceeds from asset sales 12 18 27
Other adjustments (16 ) (9 ) (12 )
Distributable Cash Flow $ 786 $ 411 $ 310
* Includes an adjustment to DCF related to the historical SUGS operations for the time period prior to the Partnership’s acquisition.
** Represents the distributable cash flow from PVR’s operations from January 1, 2014 to March 21, 2014 (the date of acquisition).

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