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MarkWest Energy Partners, L.P. (MWE) (“the Partnership”) today reported quarterly cash available for distribution to common unitholders, or distributable cash flow (DCF), of $195.2 million for the three months ended September 30, 2014, and $505.4 million for the nine months ended September 30, 2014. DCF for the three months ended September 30, 2014 represents distribution coverage of 119 percent. The third quarter distribution of $163.8 million, or $0.89 per common unit, will be paid to unitholders on November 14, 2014. The third quarter 2014 distribution represents an increase of $0.01 per common unit or 1.1 percent over the second quarter 2014 distribution and an increase of $0.04 per common unit or 4.7 percent compared to the third quarter 2013 distribution. As a Master Limited Partnership, cash distributions to common unitholders are largely determined based on DCF. A reconciliation of DCF to net income, the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.

The Partnership reported Adjusted EBITDA for the three and nine months ended September 30, 2014, of $235.5 million and $631.3 million, respectively, compared to $153.9 million and $450.5 million for the respective three and nine months ended September 30, 2013. The Partnership believes the presentation of Adjusted EBITDA provides useful information because it is commonly used by investors in Master Limited Partnerships to assess financial performance and operating results of ongoing business operations. A reconciliation of Adjusted EBITDA to net income, the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.

The Partnership reported income before provision for income tax for the three and nine months ended September 30, 2014 of $97.1 million and $135.6 million, respectively. Income before provision for income tax includes non-cash gains associated with the change in fair value of derivative instruments of $25.2 million and $18.2 million for the respective three and nine months ended September 30, 2014. Excluding these items, income before provision for income tax for the three and nine months ended September 30, 2014 would have been $71.9 million and $117.4 million, respectively.

“Our strong third quarter performance demonstrates the continued success of our producer customers and the ongoing strength of our business model,” commented Frank Semple, Chairman, President and Chief Executive Officer of MarkWest. “Year to date our team has completed 12 major processing and fractionation plants and the utilization of our large scale integrated midstream facilities continues to accelerate. As we move into 2015 and beyond, our operational and commercial execution will drive increasing cash flow, distributions and total returns for our unitholders.”

BUSINESS HIGHLIGHTS

Marcellus:

  • In August, the Partnership announced that it will construct a seventh 200 million cubic feet per day (MMcf/d) processing plant at the Sherwood complex in Doddridge County, West Virginia, at the request of Antero Resources Corporation (AR) (Antero Resources). The new plant is anchored by long-term, fee-based agreements and will expand total capacity at the Sherwood complex to 1.4 billion cubic feet per day (Bcf/d) by the third quarter of 2015. Antero Resources is the anchor producer supporting the Sherwood complex and continues to develop its prolific rich-gas acreage position in northern West Virginia. In August, the Partnership commenced operations of the Sherwood IV plant.
  • In August, the Partnership announced that it will construct a sixth processing complex in the Marcellus Shale. The new Fox complex (formerly known as the Hillman complex) will be located in Washington County, Pennsylvania and will support Range Resources Corporation’s (RRC) rapidly growing rich-gas production. The Fox complex will initially consist of Fox I, a 200 MMcf/d processing plant, and an associated de-ethanization facility. The Fox complex is scheduled to become operational during the first quarter of 2016. Propane and heavier natural gas liquids (NGLs) recovered at the Fox complex will be delivered into the Partnership’s extensive NGL network.
  • In September, the Partnership announced a major expansion project at its Keystone complex in Butler County, West Virginia to support growing rich-gas production from Rex Energy Corporation (REXX) and EdgeMarc Energy. The Partnership is developing Bluestone III, a 200 MMcf/d plant that is scheduled to be operational during the fourth quarter of 2015, and Bluestone IV, an additional 200 MMcf/d plant is scheduled to be operational by the second quarter of 2016. The Partnership is also developing 40,000 barrels per day (Bbl/d) of purity ethane fractionation capacity and 20,000 Bbl/d of propane and heavier NGL fractionation capacity by the third quarter of 2015 and first quarter of 2016, respectively.
  • Today, the Partnership is announcing the completion of Sherwood V, a 200 MMcf/d processing plant at the Sherwood complex in the Marcellus Shale. Sherwood V supports growing rich-gas production from Antero Resources and increases total processing capacity of the Sherwood complex to 1 Bcf/d.
  • Today, the Partnership is announcing the completion of definitive agreements with PennEnergy Resources, LLC (PennEnergy Resources) to provide processing, fractionation and NGL marketing services in the Marcellus Shale. PennEnergy Resources is a growing producer operating in Beaver, Butler, and Armstrong counties of Pennsylvania and will be supported at the Partnership’s Keystone complex.

Utica:

  • In July, MarkWest Utica EMG, a joint venture between the Partnership and The Energy & Minerals Group, completed Seneca III, a 200 MMcf/d processing plant in Noble County, Ohio. The new plant is anchored by Antero Resources under a long-term, fee-based contract and has expanded the total processing capacity of the Seneca complex to 600 MMcf/d. In order to support the continued growth of Antero Resources and other producers, the Partnership expects to complete a fourth 200 MMcf/d processing plant in the second quarter of 2015.
  • In July, MarkWest Utica EMG completed a 40,000 Bbl/d de-ethanization facility at the Cadiz complex in Harrison County, Ohio. This new fractionation facility provides MarkWest Utica EMG’s producer customers with the ability to meet residue gas quality specifications and downstream ethane pipeline commitments. Purity ethane produced at the new Cadiz facility will be delivered to the ATEX pipeline.
  • In August, MarkWest Utica EMG announced the development of Cadiz III, a 200 MMcf/d processing plant at the Cadiz complex in Harrison County, Ohio. The new facility is expected to begin operations during the first quarter of 2015. MarkWest Utica EMG recently began operations of the 200 MMcf/d Cadiz II plant to support rich-gas production from Gulfport Energy Corporation (GPOR) and other producers.
  • In September, MarkWest Utica EMG announced the completion of definitive agreements with American Energy – Utica, LLC (AEU), an affiliate of American Energy Partners, LP, to provide natural gas gathering, processing and fractionation services in the Utica Shale. AEU has dedicated over 60,000 net acres to MarkWest Utica EMG and Ohio Gathering Company, L.L.C. (Ohio Gathering), a joint venture between MarkWest Utica EMG and Summit Midstream Partners, LLC. Ohio Gathering will provide gas gathering and compression services for all of AEU’s gas produced from the dedicated area, while MarkWest Utica EMG will provide processing and fractionation services.
  • Today, MarkWest Utica EMG is announcing the development of Cadiz IV, a 200 MMcf/d processing plant at the Cadiz complex in Harrison County, Ohio. The new facility is scheduled to begin operations in the first quarter of 2016 and will increase MarkWest Utica EMG’s total processing capacity in Ohio to over 1.5 Bcf/d.
  • Today, the Partnership and MarkWest Utica EMG are announcing the development of a third fractionation facility at the Hopedale complex in Ohio. The new 60,000 Bbl/d fractionator is scheduled to begin operations in the first quarter of 2016 and will increase total fractionation capacity for propane and heavier natural gas liquids to 274,000 Bbl/d in the Marcellus and Utica Shales.

Southwest:

  • In August, the Partnership announced that it will construct a fourth processing plant at its Carthage facilities in Panola County, Texas to support growing rich-gas production from the Haynesville Shale and Cotton Valley formation. The new plant will have an initial capacity of 120 MMcf/d and is now scheduled to begin operations in December 2014. Once completed, total processing capacity at the Partnership’s East Texas operations will increase to 520 MMcf/d.

Capital Markets

  • Year-to-date through November 5, 2014, the Partnership has issued 22.1 million new units and received net proceeds of approximately $1.5 billion.

FINANCIAL RESULTS

Balance Sheet

  • As of September 30, 2014, the Partnership had $85.4 million of cash and cash equivalents in wholly owned subsidiaries and $762.8 million of remaining capacity under its $1.3 billion Senior Secured Credit Facility after consideration of $11.3 million of outstanding letters of credit and $525.9 million of outstanding borrowings.

Operating Results

  • Operating income before items not allocated to segments for the three months ended September 30, 2014, was $256.9 million, an increase of $75.0 million when compared to $181.9 million over the same period in 2013. This increase was primarily attributable to higher processing volumes. Processed volumes continued to increase in the third quarter of 2014, growing approximately 68 percent when compared to the third quarter of 2013, primarily due to the Partnership’s Marcellus and Utica segments.

    A reconciliation of operating income before items not allocated to segments to income before provision for income tax, the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.

  • Operating income before items not allocated to segments does not include losses on commodity derivative instruments. Realized losses on commodity derivative instruments were ($0.9) million in the third quarter of 2014 and ($5.3) million in the third quarter of 2013.

Capital Expenditures

  • For the three months ended September 30, 2014, the Partnership’s portion of capital expenditures was $371.7 million.

2014 ADJUSTED EBITDA, DCF AND CAPITAL EXPENDITURE FORECAST

The Partnership has increased its forecast of 2014 Adjusted EBITDA to a range of $860 million to $880 million and has narrowed its 2014 DCF forecast to a range of $680 million to $700 million. The Partnership has become less sensitive to changes in commodity prices as a result of significant increases in fee-based income.

The Partnership’s portion of growth capital expenditures for 2014 is forecasted in a range of $2.0 billion to $2.3 billion. Maintenance capital for 2014 is forecasted at approximately $25 million.

2015 ADJUSTED EBITDA, DCF AND CAPITAL EXPENDITURE FORECAST

For 2015, the Partnership forecasts Adjusted EBITDA in a range of $1.0 to $1.1 billion and DCF in a range of $800 million to $880 million based on its current forecast of operational volumes and prices for natural gas liquids, crude oil, natural gas, and derivative instruments currently outstanding. A sensitivity analysis for forecasted 2015 DCF based on changes in composite NGL prices and changes in volume assumptions is provided within the tables of this press release.

The Partnership’s portion of growth capital expenditures for 2015 is forecasted in a range of $1.8 billion to $2.3 billion. Maintenance capital for 2015 is forecasted at approximately $30 million.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Thursday, November 6, 2014, at 12:00 p.m. Eastern Time to review its third quarter 2014 financial results. Interested parties can participate in the call by dialing (800) 475-0218 (passcode “MarkWest”) approximately ten minutes prior to the scheduled start time. To access the webcast and associated third quarter 2014 earnings call presentation, please visit the Investor Relations section of the Partnership’s website atwww.markwest.com. A replay of the conference call will be available on the Partnership’s website or by dialing (888) 568-0541 (no passcode required).

MarkWest Energy Partners, L.P. is a master limited partnership engaged in the gathering, processing and transportation of natural gas; the gathering, transportation, fractionation, storage and marketing of natural gas liquids; and the gathering and transportation of crude oil. MarkWest has a leading presence in many unconventional gas plays including the Marcellus Shale, Utica Shale, Huron/Berea Shale, Haynesville Shale, Woodford Shale and Granite Wash formation.

This press release includes “forward-looking statements.” All statements other than statements of historical facts included or incorporated herein may constitute forward-looking statements. Actual results could vary significantly from those expressed or implied in such statements and are subject to a number of risks and uncertainties. Although MarkWest believes that the expectations reflected in the forward-looking statements are reasonable, MarkWest can give no assurance that such expectations will prove to be correct. The forward-looking statements involve risks and uncertainties that affect operations, financial performance, and other factors as discussed in filings with the Securities and Exchange Commission (SEC). Among the factors that could cause results to differ materially are those risks discussed in the periodic reports filed with the SEC, including MarkWest’s Annual Report on Form 10-K for the year ended December 31, 2013. You are urged to carefully review and consider the cautionary statements and other disclosures made in those filings, specifically those under the heading “Risk Factors.” MarkWest does not undertake any duty to update any forward-looking statement except as required by law.

MarkWest Energy Partners, L.P.
Financial Statistics
(unaudited, in thousands, except per unit data)
Three months ended September 30, Nine months ended September 30,
Statement of Operations Data 2014 2013 2014 2013
Revenue: $ 595,257 $ 450,834 $ 1,636,819 $ 1,219,713
Derivative gain (loss) 11,829 (30,318 ) 1,109 (10,804 )
Total revenue 607,086 420,516 1,637,928 1,208,909
Operating expenses:
Purchased product costs 246,801 191,672 674,189 499,588
Derivative (gain) loss related to purchased product costs (13,564 ) 20,234 (9,398 ) (10,902 )
Facility expenses 83,579 77,542 250,829 199,849
Derivative loss related to facility expenses 1,128 2,332 2,905 2,800
Selling, general and administrative expenses 28,860 26,647 91,851 77,388
Depreciation 105,072 76,323 311,079 215,902
Amortization of intangible assets 16,313 16,003 48,256 47,925
(Gain) loss on disposal of property, plant and equipment (766 ) 1,840 591 (35,758 )
Accretion of asset retirement obligations 168 160 504 669
Total operating expenses 467,591 412,753 1,370,806 997,461
Income from operations 139,495 7,763 267,122 211,448
Other (expense) income:
Equity in (loss) earnings from unconsolidated affiliates (1,555 ) 896 (2,026 ) 1,561
Interest expense (39,448 ) (38,889 ) (123,823 ) (114,180 )
Amortization of deferred financing costs and debt discount (a component of interest expense) (1,469 ) (1,584 ) (5,742 ) (5,198 )
Loss on redemption of debt (38,455 )

Miscellaneous income, net

55 1,531 117 1,748
Income (loss) before provision for income tax 97,078 (30,283 ) 135,648 56,924
Provision for income tax expense (benefit):
Current 39 (2,344 ) 365 (10,503 )
Deferred 10,991 (7,912 ) 20,271 23,087
Total provision for income tax 11,030 (10,256 ) 20,636 12,584
Net income (loss) 86,048 (20,027 ) 115,012 44,340
Net (income) loss attributable to non-controlling interest (8,614 ) (3,577 ) (16,109 ) 297
Net income (loss) attributable to the Partnership’s unitholders $ 77,434 $ (23,604 ) $ 98,903 $ 44,637
Net income (loss) attributable to the Partnership’s common unitholders per common unit:
Basic $ 0.43 $ (0.17 ) $ 0.58 $ 0.32
Diluted $ 0.41 $ (0.17 ) $ 0.54 $ 0.29
Weighted average number of outstanding common units:
Basic 176,757 142,352 166,792 134,115
Diluted 189,440 142,352 182,105 153,455
Cash Flow Data
Net cash flow provided by (used in):
Operating activities $ 139,257 $ 153,063 $ 496,080 $ 330,659
Investing activities $ (609,887 ) $ (751,286 ) $ (1,615,045 ) $ (2,186,307 )
Financing activities $ 269,254 $ 571,822 $ 1,131,696 $ 1,838,045
Other Financial Data
Distributable cash flow $ 195,223 $ 117,897 $ 505,402 $ 356,113
Adjusted EBITDA $ 235,519 $ 153,936 $ 631,316 $ 450,477
Balance Sheet Data September 30, 2014 December 31, 2013
Total assets $ 10,561,565 $ 9,396,423
Total debt $ 3,549,521 $ 3,023,071
Total equity $ 5,673,358 $ 4,798,133
MarkWest Energy Partners, L.P.
Operating Statistics
Three months ended September 30, Nine months ended September 30,
2014 2013 2014 2013
Marcellus
Gathering systems throughput (Mcf/d) 702,300 563,200 634,800 617,200
Natural gas processed (Mcf/d) 2,223,300 1,137,400 1,897,900 1,000,900
C2 (purity ethane) produced (Bbl/d) (1) 55,200 51,200
C3+ NGLs fractionated (Bbl/d) (2) 102,700 48,200 85,100 44,500
Total NGLs fractionated (Bbl/d) 157,900 48,200 136,300 44,500
Utica
Gathering systems throughput (Mcf/d) 322,300 85,100 231,100 47,100
Natural gas processed (Mcf/d) (3) 459,800 131,100 335,700 62,200
C3+ NGLs fractionated (Bbl/d) (2) 19,500 16,100
Northeast
Natural gas processed (Mcf/d) 296,500 297,800 278,000 298,900
NGLs fractionated (Bbl/d) (4) 20,200 21,500 18,400 18,900
Keep-whole NGL sales (gallons, in thousands) 30,400 28,200 87,400 92,600
Percent-of-proceeds NGL sales (gallons, in thousands) 32,300 34,700 88,300 101,800
Total NGL sales (gallons, in thousands) (5) 62,700 62,900 175,700 194,400
Crude oil transported for a fee (Bbl/d) 9,200 9,400 9,900 9,800
Southwest
East Texas gathering systems throughput (Mcf/d) 591,800 494,300 546,100 505,000
East Texas natural gas processed (Mcf/d) (6) 458,700 345,400 414,900 354,200
East Texas NGL sales (gallons, in thousands) (7) 119,600 77,200 323,100 235,500
Western Oklahoma gathering systems throughput (Mcf/d) (8) 358,800 262,000 334,900 228,400
Western Oklahoma natural gas processed (Mcf/d) (9) 298,600 218,500 279,500 198,400
Western Oklahoma NGL sales (gallons, in thousands) (7) 54,500 64,400 165,800 162,200
Southeast Oklahoma gathering systems throughput (Mcf/d) 396,300 444,200 397,600 459,500
Southeast Oklahoma natural gas processed (Mcf/d) (10) 176,700 156,700 170,300 156,100
Southeast Oklahoma NGL sales (gallons, in thousands) 28,500 44,000 78,700 137,300
Other Southwest gathering systems throughput (Mcf/d) (11) 50,000 33,000 48,600 31,200
Gulf Coast refinery off-gas processed (Mcf/d) 117,200 117,100 113,300 110,100
Gulf Coast liquids fractionated (Bbl/d) (12) 21,700 21,400 20,700 20,300
Gulf Coast NGL sales (gallons, in thousands) (12) 83,800 82,800 237,100 232,500
(1) The Bluestone ethane fractionation facility began operations in June 2014. The volumes reported for 2014 are the average daily rate for the days of operation.
(2) The Marcellus segment includes both the Houston Fractionation Facility and Marcellus’ portion utilized of the jointly owned Hopedale Fractionation Facility. Hopedale is jointly owned by MarkWest Liberty Midstream and MarkWest Utica EMG, respectively. The Utica segment includes only the portion it utilized of the jointly owned Hopedale Fractionation Facility. Operations began in January 2014. The volumes reported for 2014 are the average daily rate for the days of operation.
(3) Utica operations began in August 2012 and have continued to grow. The volumes reported are the average daily rate for the days of operation.
(4) Includes NGLs fractionated for Utica and Marcellus segments.
(5)

Represents sales at the Siloam fractionator. The total sales exclude approximately 18,255,000 gallons and 21,049,000 gallons sold by the Northeast on behalf of Marcellus for the three months ended September 30, 2014 and 2013, respectively. The total sales exclude approximately 40,265,000 gallons and 27,867,000 gallons sold by the Northeast on behalf of Marcellus for the nine months ended September 30, 2014 and 2013, respectively.

(6) Includes certain amounts in 2014 in excess of East Texas’ operating capacity that were processed by third-parties.
(7) Excludes gallons processed in conjunction with take in kind contracts for the three and nine months ended September 30, 2014 and September 30, 2013, respectively, as shown below.
Three months ended September 30, Nine months ended September 30,
Gallons processed in conjunction with take in kind contracts 2014 2013 2014 2013
East Texas 1,392,000 318,000 13,743,000
Western Oklahoma 38,983,000 88,001,000
(8) Includes natural gas gathered in Western Oklahoma and from the Granite Wash formation in the Texas Panhandle as management considers this one integrated area of operations.
(9) The Buffalo Creek plant began operations in February 2014.
(10) The natural gas processing in Southeast Oklahoma is outsourced to our joint venture Centrahoma or other third-party processors.
(11) Excludes lateral pipelines where revenue is not based on throughput.
(12) Excludes Hydrogen volumes.
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Operating Income before Items not Allocated to Segments
(unaudited, in thousands)
Three months ended September 30, 2014 Marcellus Utica Northeast Southwest Eliminations (1) Total
Segment revenue $ 230,241 $ 47,520 $ 52,120 $ 276,666 $ (1,298 ) $ 605,249
Operating expenses:
Segment purchased product costs 57,569 11,023 18,350 159,964 246,906
Segment facility expenses 36,171 14,150 9,515 32,267 (1,298 ) 90,805
Total operating expenses before items not allocated to segments 93,740 25,173 27,865 192,231 (1,298 ) 337,711
Segment portion of operating income attributable to non-controlling interests 10,616 5 10,621
Operating income before items not allocated to segments $ 136,501 $ 11,731 $ 24,255 $ 84,430 $ $ 256,917
Three months ended September 30, 2013 Marcellus Utica Northeast Southwest Total
Segment revenue $ 147,290 $ 8,373 $ 48,829 $ 247,885 $ 452,377
Operating expenses:
Segment purchased product costs 36,995 15,330 139,347 191,672
Segment facility expenses 29,621 9,858 7,359 32,559 79,397
Total operating expenses before items not allocated to segments 66,616 9,858 22,689 171,906 271,069
Segment portion of operating (loss) income attributable to non-controlling interests (599 ) 40 (559 )
Operating income (loss) before items not allocated to segments $ 80,674 $ (886 ) $ 26,140 $ 75,939 $ 181,867
(1) Amounts represent revenues and expenses associated with the Northeast segment fractionation completed on behalf of the Marcellus segment.
Three months ended September 30,
2014 2013
Operating income before items not allocated to segments $ 256,917 $ 181,867
Portion of operating income (loss) attributable to non-controlling interests 6,065 (559 )
Derivative gain (loss) not allocated to segments 24,265 (52,884 )
Revenue adjustment for unconsolidated affiliate (15,463 )
Revenue deferral adjustment and other 5,471 (1,543 )
Compensation expense included in facility expenses not allocated to segments (801 ) (833 )
Facility expense and purchase product cost adjustments for unconsolidated affiliate 5,444
Portion of operating loss attributable to non-controlling interests of an unconsolidated affiliate 4,556
Facility expenses adjustments 2,688 2,688
Selling, general and administrative expenses (28,860 ) (26,647 )
Depreciation (105,072 ) (76,323 )
Amortization of intangible assets (16,313 ) (16,003 )
Gain (loss) on disposal of property, plant and equipment 766 (1,840 )
Accretion of asset retirement obligations (168 ) (160 )
Income from operations 139,495 7,763
Other (expense) income:
Equity in (loss) earnings from unconsolidated affiliates (1,555 ) 896
Interest expense (39,448 ) (38,889 )
Amortization of deferred financing costs and debt discount (a component of interest expense) (1,469 ) (1,584 )
Miscellaneous income, net 55 1,531
Income (loss) before provision for income tax $ 97,078 $ (30,283 )
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Operating Income before Items not Allocated to Segments
(unaudited, in thousands)
Nine months ended September 30, 2014 Marcellus Utica Northeast Southwest Eliminations (1) Total
Segment revenue $ 589,134 $ 102,112 $ 157,150 $ 807,136 $ (3,769 ) $ 1,651,763
Operating expenses:
Segment purchased product costs 131,569 22,511 53,974 466,276 674,330
Segment facility expenses 105,399 38,176 25,138 99,143 (3,769 ) 264,087
Total operating expenses before items not allocated to segments 236,968 60,687 79,112 565,419 (3,769 ) 938,417
Segment portion of operating income attributable to non-controlling interests 18,439 10 18,449
Operating income before items not allocated to segments $ 352,166 $ 22,986 $ 78,038 $ 241,707 $ $ 694,897
Nine months ended September 30, 2013 Marcellus Utica Northeast Southwest Total
Segment revenue $ 375,844 $ 12,590 $ 151,530 $ 684,093 $ 1,224,057
Operating expenses:
Segment purchased product costs 72,781 50,118 376,689 499,588
Segment facility expenses 74,529 20,232 20,538 91,027 206,326
Total operating expenses before items not allocated to segments 147,310 20,232 70,656 467,716 705,914
Segment portion of operating (loss) income attributable to non-controlling interests (3,081 ) 157 (2,924 )
Operating income (loss) before items not allocated to segments $ 228,534 $ (4,561 ) $ 80,874 $ 216,220 $ 521,067
(1) Amounts represent revenues and expenses associated with the Northeast segment fractionation completed on behalf of the Marcellus segment.
Nine months ended September 30,
2014 2013
Operating income before items not allocated to segments $ 694,897 $ 521,067
Portion of operating income (loss) attributable to non-controlling interests 13,384 (2,924 )
Derivative gain (loss) not allocated to segments 7,602 (2,702 )
Revenue adjustment for unconsolidated affiliate (19,296 )
Revenue deferral adjustment and other 4,352 (4,344 )
Compensation expense included in facility expenses not allocated to segments (2,707 ) (1,587 )
Facility expense and purchase product cost adjustments for unconsolidated affiliate 8,042
Portion of operating loss attributable to non-controlling interests of an unconsolidated affiliate 5,065
Facility expenses adjustments 8,064 8,064
Selling, general and administrative expenses (91,851 ) (77,388 )
Depreciation (311,079 ) (215,902 )
Amortization of intangible assets (48,256 ) (47,925 )
(Loss) gain on disposal of property, plant and equipment (591 ) 35,758
Accretion of asset retirement obligations (504 ) (669 )
Income from operations 267,122

211,448
Other (expense) income:

Equity in (loss) earnings from unconsolidated affiliates (2,026 ) 1,561
Interest expense (123,823 ) (114,180 )
Amortization of deferred financing costs and debt discount (a component of interest expense) (5,742 ) (5,198 )
Loss on redemption of debt (38,455 )
Miscellaneous income, net 117 1,748
Income before provision for income tax $ 135,648 $ 56,924
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Distributable Cash Flow
(unaudited, in thousands)

Three months ended September 30,

Nine months ended September 30,

2014 2013 2014 2013
Net income (loss) $ 86,048 $ (20,027 ) $ 115,012 $ 44,340
Depreciation, amortization and other non-cash operating expenses 121,631 92,564 360,942 264,730
(Gain) loss on sale or disposal of property, plant and equipment (766 ) 1,840 591 (32,711 )
Loss on redemption of debt, net of tax benefit 36,178
Amortization of deferred financing costs and debt discount 1,469 1,584 5,742 5,198
Equity in loss (earnings) from unconsolidated affiliates 1,555 (896 ) 2,026 (1,561 )
Distributions from unconsolidated affiliates 3,276 2,224 7,186 4,952
Non-cash compensation expense 1,646 1,924 7,448 5,464
Unrealized (gain) loss on derivative instruments (25,186 ) 47,542 (18,162 ) 1,222
Deferred income tax expense (benefit) 10,991 (7,912 ) 20,271 23,087
Cash adjustment for non-controlling interest of consolidated subsidiaries (5,330 ) 1,183 (10,626 ) 4,672
Revenue deferral adjustment 1,720 1,754 5,533 5,164
Other (1) 3,481 3,197 24,503 8,553
Maintenance capital expenditures (2) (5,312 ) (7,080 ) (15,064 ) (13,175 )
Distributable cash flow $ 195,223 $ 117,897 $ 505,402 $ 356,113

Maintenance capital expenditures (2) $ 5,312 $ 7,080 $ 15,064 $ 13,175
Growth capital expenditures of consolidated subsidiaries 491,264 734,555 1,756,836 2,163,544
Growth capital expenditures of unconsolidated subsidiary (3) 148,165 188,178
Total capital expenditures 644,741 741,635 1,960,078 2,176,719
Acquisitions, net of cash acquired 225,210
Total capital expenditures and acquisitions 644,741 741,635 1,960,078 2,401,929
Joint venture partner contributions (273,003 ) (91,163 ) (393,109 ) (716,982 )
Total capital expenditures and acquisitions, net $ 371,738 $ 650,472 $ 1,566,969 $ 1,684,947
Distributable cash flow $ 195,223 $ 117,897 $ 505,402 $ 356,113
Maintenance capital expenditures (2) 5,312 7,080 15,064 13,175
Changes in receivables, inventories and other assets (22,250 ) (6,969 ) (65,013 ) (74,470 )
Changes in accounts payable, accrued liabilities and other long-term liabilities (41,545 ) 38,504 53,496 48,557
Cash adjustment for non-controlling interest of consolidated subsidiaries 5,330 (1,183 ) 10,626 (4,672 )
Other (2,813 ) (2,266 ) (23,495 ) (8,044 )
Net cash provided by operating activities $ 139,257 $ 153,063 $ 496,080 $ 330,659
(1) Other includes amounts related to capitalized interest associated with joint venture capital expenditures and fees earned related to development of joint venture capital projects.
(2) Net of joint venture partner contributions.
(3) Growth capital expenditures for Ohio Gathering, L.L.C.
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Adjusted EBITDA
(unaudited, in thousands)
Three months ended September 30, Nine months ended September 30,
2014 2013 2014 2013

Net income (loss) 86,048 (20,027 ) 115,012 44,340
Non-cash compensation expense 1,646 1,924 7,448 5,464
Unrealized (gain) loss on derivative instruments (25,186 ) 47,542 (18,162 ) 1,222
Interest expense (1) 38,856 38,356 123,339 112,988
Depreciation, amortization and other non-cash operating expenses 121,631 92,564 360,942 264,730
(Gain) loss on disposal of property, plant and equipment (766 ) 1,840 591 (35,758 )
Loss on redemption of debt 38,455
Provision for income tax expense (benefit) 11,030 (10,256 ) 20,636 12,584
Adjustment for cash flow from unconsolidated affiliates 4,831 1,328 9,212 3,391
Other (2) (2,571 ) 665 12,298 3,061
Adjusted EBITDA $ 235,519 $ 153,936 $ 631,316 $ 450,477
(1) Includes amortization of deferred financing costs and debt discount, and excludes interest expense related to the Steam Methane Reformer.
(2) For the three and nine months ended September 30, 2014, Other includes amounts related to capitalized interest associated with joint venture capital expenditures and fees earned related to development of joint venture capital projects.

MarkWest Energy Partners, L.P.
Distributable Cash Flow Sensitivity Analysis
(unaudited, in millions)

The Partnership periodically estimates the effect on DCF resulting from changes in its volume forecast and NGL prices. The Partnership has become less sensitive to changes in commodity prices as a result of significant increases in fee-based income. For the full year 2015, the Partnership estimates that net operating margin will be approximately 80 percent fee-based.

The analysis further assumes derivative instruments outstanding as of November 4, 2014, and production volumes estimated through December 31, 2015.

Estimated Range of 2015 DCF

Volume Forecast (1)
Low Case Base Case High Case

NGL $/Gal
(2) (3)

$1.00 $

832

$ 872 $

910

$0.95 $

814

$

854 $

892

$0.90 $

796

$ 836 $

873

$0.85 $

779

$ 818 $

855

$0.80 $

761

$ 800 $

836

(1) Volume Forecast is increased/decreased by 5% in the Marcellus and Utica segments for the High and Low Cases.
(2)

The composition is based on the Partnership’s projected NGL barrel of approximately: Ethane: 35%, Propane: 35%, Iso-Butane: 6%, Normal Butane: 12%, Natural Gasoline: 12%.

(3) Composite NGL prices are based on the Partnership’s average forecasted price.

The table is based on current information, expectations, and beliefs concerning future developments and their potential effects, and does not consider actions the Partnership’s management may take to mitigate exposure to changes. Further, the table does not consider the effects that such hypothetical adverse changes may have on overall economic activity. Historical volumes, prices and correlations do not guarantee future results.

Although the Partnership believes the expectations reflected in this analysis are reasonable, the Partnership can give no assurance that such expectations will prove to be correct and readers are cautioned that projected performance, results, or distributions may not be achieved. Actual changes in market prices, market conditions and constraints, production, NGL composition, infrastructure availability, market participants, and ratios between product prices may differ from the assumptions utilized in the analysis. Actual results, performance, distributions, volumes, events, or transactions could vary significantly from those expressed, considered or implied in this analysis. All results, performance, distributions, volumes, events or transactions are subject to a number of uncertainties and risks. Those uncertainties and risks may not be factored into or accounted for in this analysis. Readers are urged to carefully review and consider the cautionary statements and disclosures made in the Partnership’s periodic reports filed with the SEC, specifically those under the heading “Risk Factors.”