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MarkWest Energy Partners Reports Record Quarterly Distributable Cash Flow, Increases Quarterly Common Unit Distribution by 14.1 Percent, Increases 2011 DCF Guidance, and Provides 2012 Guidance
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DENVER, Nov 07, 2011 (BUSINESS WIRE) --

MarkWest Energy Partners, L.P. (NYSE: MWE) (the Partnership) today reported record quarterly cash available for distribution to common unitholders, or distributable cash flow (DCF), of $85.3 million for the three months ended September 30, 2011, and $244.4 million for the nine months ended September 30, 2011. Distributable cash flow for the three and nine months ended September 30, 2011, represents distribution coverage of 138 percent and 146 percent, respectively. The third quarter distribution of $62.0 million, or $0.73 per common unit, will be paid on November 14, 2011, to unitholders of record on November 7, 2011. The third quarter 2011 distribution represents an increase of $0.03 per common unit, or 4.3 percent, over the second quarter 2011 distribution and an increase of $0.09 per common unit, or 14.1 percent, over the third quarter 2010 distribution. As a Master Limited Partnership, cash distributions to common unitholders are largely determined based on DCF. A reconciliation of DCF to net income (loss), the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.

The Partnership reported Adjusted EBITDA of $107.0 million for the three months ended September 30, 2011, and $323.2 million for the nine months ended September 30, 2011. MarkWest 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 (loss), 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 months and nine months ended September 30, 2011, of $179.3 million and $194.4 million, respectively. Income before provision for income tax includes non-cash gains associated with the change in fair value of derivative instruments of $126.8 million and $102.7 million for the three and nine months ended September 30, 2011, respectively, and costs associated with the redemption of debt of $(0.1) million and $(43.5) million for the three and nine months ended September 30, 2011, respectively. Excluding these items, income before provision for income tax for the three and nine months ended September 30, 2011, would have been $52.6 million and $135.2 million, respectively.

"Our record distributable cash flow for the third quarter allowed us to deliver more than 14% year-over-year distribution growth for our unitholders and still maintain a coverage ratio of 1.38 times," said Frank Semple, Chairman, President and Chief Executive Officer. "This strong financial performance is a direct result of providing exceptional service for our producer customers and completing $2 billion of organic growth projects and acquisitions over the past three years. Equally as exciting is the extensive inventory of future growth projects that should continue to deliver strong distribution growth and total returns for our unitholders for years to come."

BUSINESS HIGHLIGHTS

Capital Markets

  • On July 13, 2011, the Partnership completed a common unit equity offering of 4.025 million common units. The net proceeds of approximately $185 million were used to repay amounts outstanding under its revolving credit facility and to fund its ongoing capital expenditure program.
  • On September 7, 2011, the Partnership completed the expansion and extension of its senior secured revolving credit facility. As amended, the credit facility provides up to $750 million of borrowing capacity with improved pricing that will result in significant interest expense savings. The maturity date of the credit facility was extended to September 2016.
  • On October 13, 2011, the Partnership completed a common unit equity offering of 5.750 million common units. The net proceeds of approximately $251 million were used to repay amounts outstanding under its revolving credit facility and to fund its ongoing capital expenditure program.
  • On November 3, 2011, the Partnership completed a public offering of $700 million of 6.25% senior unsecured notes due 2022 resulting in net proceeds of approximately $689 million. The Partnership intends to use the net proceeds from the offering to purchase up to $334.4 million in aggregate principal amount of its outstanding 8.75% senior notes due 2018 pursuant to a tender offer launched October 25, 2011, for any and all of such outstanding senior notes. The tender offer for the senior notes due 2018 expires on November 25, 2011. All remaining net proceeds will be used to fund its ongoing capital expenditure program.

Business Development

  • Southwest - in September 2011, MarkWest commenced operations of a 75 million cubic feet per day (MMcf/d) expansion of its cryogenic natural gas processing capacity at its Arapaho complex in Western Oklahoma. With the addition of the incremental capacity, MarkWest has 235 MMcf/d of cryogenic processing capacity available to serve increasing volumes of liquids-rich natural gas production from Granite Wash producers in the Texas panhandle.
  • Liberty - in September 2011, MarkWest Liberty announced three critical milestones in the ongoing development of the hydrocarbon-rich area of the Marcellus Shale. The first milestone was the announcement by Sunoco Logistics, LP of the successful completion of the Mariner West open season and the execution of definitive transportation agreements. Mariner West is a 50,000 barrel per day (Bbl/d) pipeline project jointly developed by Sunoco and MarkWest Liberty that will deliver Marcellus ethane to petrochemical markets in Sarnia, Ontario, Canada. Mariner West will support the long-term development of more than 1.5 billion cubic feet per day (Bcf/d) of liquids-rich Marcellus gas in southwest Pennsylvania and northern West Virginia.

The second milestone was the start-up of MarkWest Liberty's Houston, Pennsylvania fractionation facility with design capacity of 60,000 Bbl/d. The facility is the largest natural gas liquids (NGLs) fractionation and marketing complex in the northeast United States and produces high-purity propane, butane, and natural gasoline for sale into the premium Northeast markets.
The third milestone was MarkWest Liberty's announcement of the development of up to 115,000 Bbl/d of purity ethane production capacity at its Houston and Majorsville processing complexes. The first phase of this expansion will provide capacity to produce approximately 75,000 Bbl/d and will commence operation in mid-2013 to support Mariner West.

  • Liberty - In October 2011, MarkWest Liberty entered into definitive agreements with subsidiaries of Magnum Hunter Resources Corporation to provide long-term midstream processing and related services in the liquids-rich area of the Marcellus Shale in northern West Virginia. MarkWest Liberty will install a 200 MMcf/d cryogenic natural gas processing plant at its Mobley processing complex in West Virginia. When combined with the 120 MMcf/d Mobley I plant currently under construction, MarkWest Liberty expects to operate 320 MMcf/d of cryogenic processing capacity at its Mobley complex by the second half of 2012. The NGLs recovered at the Mobley complex will be transported via a newly constructed liquids pipeline to MarkWest Liberty's fractionation, storage, and marketing complex in Houston, Pennsylvania.
  • Liberty - MarkWest Liberty is in active discussions with existing and new producer customers to develop additional midstream projects in the liquids-rich areas of the Marcellus, including significant processing, NGL transportation, fractionation, storage, and marketing infrastructure that is critical to the full development of the Marcellus.

FINANCIAL RESULTS

Balance Sheet

  • At September 30, 2011, the Partnership had $86.4 million of cash and cash equivalents in wholly owned subsidiaries and $577.6 million available for borrowing under its $750 million revolving credit facility after consideration of $27.3 million of outstanding letters of credit. Pro forma for the equity issuance and senior notes offering in October and November 2011, respectively, and assuming all borrowings under the revolving credit facility at September 30, 2011, are repaid, MarkWest would have $881.3 million of cash and cash equivalents and $722.7 million available for borrowing under its revolving credit facility, resulting in total available liquidity of $1.6 billion.

Operating Results

  • Operating income before items not allocated to segments for the three months ended September 30, 2011, was $147.8 million, an increase of $41.2 million when compared to segment operating income of $106.6 million in the same period in 2010. This increase is primarily attributable to favorable commodity prices compared to the prior year quarter, expanding operations in the Liberty and Northeast segments, and increased processing volumes in the Southwest segment.

A reconciliation of operating income before items not allocated to segments to income (loss) 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 gain (loss) on commodity derivative instruments. Realized losses on commodity derivative instruments were $(15.8) million in the third quarter of 2011 compared to realized losses of $(5.7) million in the third quarter of 2010.

Capital Expenditures

  • For the three and nine months ended September 30, 2011, the Partnership's portion of capital expenditures was $111.3 million and $522.2 million, respectively. Capital expenditures for the nine months ended September 30, 2011, include the $230.7 million acquisition of EQT's Langley processing complex and the partially completed Ranger NGL pipeline.

2011 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

The Partnership increased its 2011 DCF forecast to a range of $325 million to $345 million. The midpoint of this range provides for approximately 135 percent coverage of the Partnership's full-year distribution based on current quarterly distributions and common units outstanding.

The Partnership's portion of the 2011 growth capital expenditure forecast remains unchanged in a range of $675 million to $700 million, which includes the $230 million acquisition of EQT's Langley processing complex and the Ranger NGL pipeline. The Partnership forecasts maintenance capital for 2011 at approximately $15 million.

2012 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

For 2012, the Partnership forecasts DCF in a range of $380 million to $440 million based on forecasted operational volumes from existing operations and growth capital projects; derivative instruments currently outstanding; a reasonable range of price estimates for crude oil and natural gas; and no acquisitions. The midpoint of this range results in approximately 165 percent coverage of the Partnership's full-year distribution based on current quarterly distributions and common units outstanding. A sensitivity analysis for forecasted 2012 DCF is provided within the tables of this press release.

The Partnership's portion of growth capital expenditures for 2012 is forecasted in a range of $600 million to $700 million and maintenance capital for 2012 is forecasted at approximately $20 million.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Tuesday, November 8, 2011, at 4:00 p.m. Eastern Time to review its third quarter 2011 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, please visit the Investor Relations section of the Partnership's website at www.markwest.com. A replay of the conference call will be available on the MarkWest website or by dialing (866) 359-6514 (no passcode required).

###

MarkWest Energy Partners, L.P. is a master limited partnership engaged in the gathering, transportation, and processing of natural gas; the transportation, fractionation, marketing, and storage of natural gas liquids; and the gathering and transportation of crude oil. MarkWest has extensive natural gas gathering, processing, and transmission operations in the southwest, Gulf Coast, and northeast regions of the United States, including the Marcellus Shale, and is the largest natural gas processor and fractionator in the Appalachian region.

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 we believe that the expectations reflected in the forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. The forward-looking statements involve risks and uncertainties that affect our operations, financial performance, and other factors as discussed in our filings with the Securities and Exchange Commission.Among the factors that could cause results to differ materially are those risks discussed in the periodic reports we file with the SEC, including our Annual Report on Form 10-K for the year ended December 31, 2010, and our Quarterly Report on Form 10-Q for the quarter ended September 30, 2011. 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."We do 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 2011 2010 2011 2010
Revenue:
Revenue $ 400,883 $ 292,370 $ 1,109,632 $ 884,933
Derivative gain (loss) 106,943 (36,959 ) 61,854 2,707
Total revenue 507,826 255,411 1,171,486 887,640
Operating expenses:
Purchased product costs 189,284 136,700 497,493 409,119
Derivative (gain) loss related to purchased product costs (1,274 ) 19,996 17,866 24,993
Facility expenses 44,236 37,934 124,358 113,266
Derivative gain related to facility expenses (2,787 ) (564 ) (2,871 ) (436 )
Selling, general and administrative expenses 20,162 17,137 60,454 55,064
Depreciation 38,715 31,362 110,280 89,367
Amortization of intangible assets 10,985 10,193 32,632 30,579
Loss on disposal of property, plant and equipment 147 1,937 4,619 2,116
Accretion of asset retirement obligations 557 70 934 282
Total operating expenses 300,025 254,765 845,765 724,350
Income from operations 207,801 646 325,721 163,290
Other income (expense):
(Loss) earnings from unconsolidated affiliates (507 ) - (1,262 ) 1,517
Interest income 62 422 214 1,185
Interest expense (26,899 ) (26,433 ) (83,036 ) (75,970 )
Amortization of deferred financing costs and discount (a component of interest expense) (1,002 ) (3,625 ) (3,873 ) (8,517 )
Derivative gain related to interest expense - - - 1,871
Loss on redemption of debt (133 ) - (43,461 ) -
Miscellaneous (expense) income, net (4 ) 76 127 1,129
Income (loss) before provision for income tax 179,318 (28,914 ) 194,430 84,505
Provision for income tax expense (benefit):
Current 3,959 3,533 8,104 10,254
Deferred 21,905 (13,771 ) 18,338 (45 )
Total provision for income tax 25,864 (10,238 ) 26,442 10,209
Net income (loss) 153,454 (18,676 ) 167,988 74,296
Net income attributable to non-controlling interest (13,142 ) (8,475 ) (33,208 ) (19,720 )
Net income (loss) attributable to the Partnership $ 140,312 $ (27,151 ) $ 134,780 $ 54,576

Net income (loss) attributable to the Partnership's common unitholders per common unit:

Basic $ 1.77 $ (0.39 ) $ 1.75 $ 0.77
Diluted $ 1.77 $ (0.39 ) $ 1.75 $ 0.77
Weighted average number of outstanding common units:
Basic 78,619 71,438 76,118 69,685
Diluted 78,760 71,438 76,276 69,831
Cash Flow Data

Net cash flow provided by (used in):

Operating activities $ 124,885 $ 66,602 $ 331,249 $ 197,238
Investing activities $ (125,637 ) $ (120,806 ) $ (587,686 ) $ (373,649 )
Financing activities $ 64,894 $ 17,828 $ 348,164 $ 177,154
Other Financial Data
Distributable cash flow $ 85,311 $ 54,694 $ 244,391 $ 171,942
Adjusted EBITDA $ 107,013 $ 83,737 $ 323,204 $ 244,882

Balance Sheet Data

September 30, 2011

December 31, 2010

Working capital $ 56,694 $ (43,296 )
Total assets 3,986,201 3,333,362
Total debt 1,477,963 1,273,434
Total equity 1,909,104 1,536,020
MarkWest Energy Partners, L.P.
Operating Statistics
Three months ended September 30, Nine months ended September 30,
2011 2010 2011 2010
Southwest
East Texas gathering systems throughput (Mcf/d) 417,400 433,000 423,800 433,600
East Texas natural gas processed (Mcf/d) 229,700 221,900 226,000 236,900
East Texas NGL sales (gallons, in thousands) 59,000 60,200 175,200 186,300
Western Oklahoma gathering system throughput (Mcf/d) (1) 241,300 183,600 224,400 189,300
Western Oklahoma natural gas processed (Mcf/d) 153,200 143,300 156,600 129,600
Western Oklahoma NGL sales (gallons, in thousands) 37,000 33,800 111,100 93,400
Southeast Oklahoma gathering system throughput (Mcf/d) 512,600 535,800 507,500 524,100
Southeast Oklahoma natural gas processed (Mcf/d) (2) 105,400 94,500 103,100 79,000
Southeast Oklahoma NGL sales (gallons, in thousands) 30,600 29,900 92,100 72,300
Arkoma Connector Pipeline throughput (Mcf/d) 298,600 396,800 294,300 378,900
Other Southwest gathering system throughput (Mcf/d) (3) 29,900 37,000 31,500 40,200
Northeast (4)
Natural gas processed (Mcf/d) 277,400 190,300 300,700 194,400
NGLs fractionated (Bbl/d) (5) 19,300 21,200 21,400 20,500
Keep-whole sales (gallons, in thousands) 21,700 28,700 82,600 105,300
Percent-of-proceeds sales (gallons, in thousands) 31,600 30,800 95,600 87,900

Total NGL sales (gallons, in thousands) (6)

53,300 59,500 178,200 193,200
Crude oil transported for a fee (Bbl/d) 9,900 12,100 10,500 12,400
Liberty
Gathering system throughput (Mcf/d) 258,300 153,300 228,900 127,700
Natural gas processed (Mcf/d) 366,200 156,300 306,700 122,300
NGLs fractionated (Bbl/d) (7) 12,400 4,200 9,300 3,500

NGL sales (gallons, in thousands) (8)

61,100 32,400 163,500 77,400
Gulf Coast
Refinery off-gas processed (Mcf/d) 122,000 123,000 113,200 118,400
Liquids fractionated (Bbl/d) 23,100 23,100 21,400 22,800

NGL sales (gallons excluding hydrogen, in thousands)

89,200 89,300 245,500 261,700
(1) 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.
(2)

The natural gas processing in Southeast Oklahoma is outsourced to Centrahoma, our equity investment, or a third-party processor.

(3) Excludes lateral pipelines where revenue is not based on throughput.
(4) Includes throughput from the Kenova, Cobb, Boldman and Langley processing plants. We acquired the Langley processing plant in February 2011. The volumes reported are the average daily rates for the days of operation.
(5) Amount includes 4,400 barrels per day and 4,300 barrels per day fractionated on behalf of Liberty for the three months ended September 30, 2011 and 2010, respectively, and includes 5,100 barrels per day and 3,500 barrels per day fractionated on behalf of Liberty for the nine months ended September 30, 2011 and 2010, respectively. Beginning in the fourth quarter of 2011, Siloam will no longer fractionate NGLs on behalf of Liberty due to the operation of Liberty's fractionation facility that began in September 2011.
(6)

Represents sales at the Siloam fractionator. The total sales exclude approximately 17,100,000 gallons and 16,700,000 gallons sold by the Northeast on behalf of Liberty for the three months ended September 30, 2011 and 2010, respectively, and approximately 58,600,000 gallons and 40,000,000 gallons sold for the nine months ended September 30, 2011 and 2010, respectively. These volumes are included as part of NGLs sold at Liberty.

(7)

Amount includes all NGLs that were produced at the Liberty processing facilities and fractionated into purity products at our Liberty fractionation facility. Through August 2011, only propane was recovered at our Liberty facilities. In September 2011, Liberty's fractionation facility commenced operations and Liberty now has full fractionation capabilities.

(8) Includes sale of all purity products fractionated at the Liberty facilities and sale of all unfractionated NGLs. Also includes the sale of purity products fractionated and sold at the Siloam facilities on behalf of Liberty.
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, 2011 Southwest Northeast Liberty Gulf Coast Total
Revenue $ 241,998 $ 55,920 $ 78,586 $ 26,868 $ 403,372
Operating expenses:
Purchased product costs 141,067 15,947 32,270 - 189,284
Facility expenses 21,043 6,879 9,108 9,798 46,828
Total operating expenses before items not allocated to segments 162,110 22,826 41,378 9,798 236,112
Portion of operating income attributable to non-controlling interests 1,227 - 18,223 - 19,450
Operating income before items not allocated to segments $ 78,661 $ 33,094 $ 18,985 $ 17,070 $ 147,810
Three months ended September 30, 2010 Southwest Northeast Liberty Gulf Coast Total
Revenue $ 159,044 $ 83,400 $ 28,606 $ 21,320 $ 292,370
Operating expenses:
Purchased product costs 74,835 55,879 5,986 - 136,700
Facility expenses 20,659 5,268 5,668 8,785 40,380
Total operating expenses before items not allocated to segments 95,494 61,147 11,654 8,785 177,080
Portion of operating income attributable to non-controlling interests 1,906 - 6,772 - 8,678
Operating income before items not allocated to segments $ 61,644 $ 22,253 $ 10,180 $ 12,535 $ 106,612
Three months ended September 30,
2011 2010
Operating income before items not allocated to segments $ 147,810 $ 106,612
Portion of operating income attributable to non-controlling interests 19,450 8,678
Derivative gain (loss) not allocated to segments 111,004 (56,391 )
Revenue deferral adjustment (2,489 ) -

Compensation expense included in facility expenses not allocated to
segments

(263 ) (404 )
Facility expenses adjustments 2,855 2,850
Selling, general and administrative expenses (20,162 ) (17,137 )
Depreciation (38,715 ) (31,362 )
Amortization of intangible assets (10,985 ) (10,193 )
Loss on disposal of property, plant and equipment (147 ) (1,937 )
Accretion of asset retirement obligations (557 ) (70 )
Income from operations 207,801 646
Other income (expense):
Loss from unconsolidated affiliate (507 ) -
Interest income 62 422
Interest expense (26,899 ) (26,433 )

Amortization of deferred financing costs and discount (a component of
interest expense)

(1,002 ) (3,625 )

Loss on redemption of debt

(133

)

-

Miscellaneous (expense) income, net (4 ) 76
Income (loss) before provision for income tax $ 179,318 $ (28,914 )
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, 2011 Southwest Northeast Liberty Gulf Coast Total
Revenue $ 679,347 $ 201,687 $ 168,142 $ 73,310 $ 1,122,486
Operating expenses:
Purchased product costs 373,251 72,527 51,715 - 497,493
Facility expenses 62,055 19,402 22,875 27,100 131,432
Total operating expenses before items not allocated to segments 435,306 91,929 74,590 27,100 628,925
Portion of operating income attributable to non-controlling interests 3,745 - 45,782 - 49,527
Operating income before items not allocated to segments $ 240,296 $ 109,758 $ 47,770 $ 46,210 $ 444,034
Nine months ended September 30, 2010 Southwest Northeast Liberty Gulf Coast Total
Revenue $ 479,051 $ 276,570 $ 66,354 $ 62,958 $ 884,933
Operating expenses:
Purchased product costs 220,849 179,700 8,570 - 409,119
Facility expenses 60,543 14,555 19,121 23,875 118,094
Total operating expenses before items not allocated to segments 281,392 194,255 27,691 23,875 527,213
Portion of operating income attributable to non-controlling interests 4,962 - 15,617 - 20,579
Operating income before items not allocated to segments $ 192,697 $ 82,315 $ 23,046 $ 39,083 $ 337,141
Nine months ended September 30,
2011 2010
Operating income before items not allocated to segments $ 444,034 $ 337,141
Portion of operating income attributable to non-controlling interests 49,527 20,579
Derivative gain (loss) not allocated to segments 46,859 (21,850 )
Revenue deferral adjustment (12,854 ) -

Compensation expense included in facility expenses not allocated to
segments

(1,491 ) (1,412 )
Facility expenses adjustments 8,565 6,240
Selling, general and administrative expenses (60,454 ) (55,064 )
Depreciation (110,280 ) (89,367 )
Amortization of intangible assets (32,632 ) (30,579 )
Loss on disposal of property, plant and equipment (4,619 ) (2,116 )
Accretion of asset retirement obligations (934 ) (282 )
Income from operations 325,721 163,290
Other income (expense):
(Loss) earnings from unconsolidated affiliate (1,262 ) 1,517
Interest income 214 1,185
Interest expense (83,036 ) (75,970 )

Amortization of deferred financing costs and discount (a component of
interest expense)

(3,873 ) (8,517 )
Derivative gain related to interest expense - 1,871
Loss on redemption of debt (43,461 ) -
Miscellaneous income, net 127 1,129
Income before provision for income tax $ 194,430 $ 84,505
MarkWest Energy Partners, L.P.
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,
2011 2010 2011 2010
Net income (loss) $ 153,454 $ (18,676 ) $ 167,988 $ 74,296

Depreciation, amortization, impairment, and other non-cash operating expenses

50,482 43,640 148,699 122,578
Loss on redemption of debt, net of tax benefit 119 - 39,618

-
Amortization of deferred financing costs and discount 1,002 3,625 3,873 8,517
Non-cash loss (earnings) from unconsolidated affiliate 507 - 1,262 (1,517 )
Distributions from unconsolidated affiliate - 1,353 300

2,508
Non-cash compensation expense 995 1,447 3,707 6,456
Non-cash derivative activity (126,802 ) 50,610 (102,681 ) (14,782 )
Provision for income tax - deferred 21,905 (13,771 ) 18,338 (45 )
Cash adjustment for non-controlling interest of consolidated subsidiaries (18,227 ) (8,274 ) (46,285 ) (19,317 )
Revenue deferral adjustment 2,489 - 12,854 -
Other 1,334 (1,259 ) 4,537 561
Maintenance capital expenditures, net of joint venture partner contributions (1,947 ) (4,001 ) (7,819 ) (7,313 )
Distributable cash flow $ 85,311

$ 54,694 $ 244,391 $ 171,942
Maintenance capital expenditures $ 2,179 $ 4,001 $ 8,577 $ 7,313
Growth capital expenditures 123,631 116,912 351,349 366,860
Total capital expenditures 125,810 120,913 359,926

374,173
Acquisition - - 230,728 -
Total capital expenditures and acquisition 125,810 120,913 590,654 374,173
Joint venture partner contributions (14,474 ) (53,975 ) (68,501 ) (158,017 )
Total capital expenditures and acquisition, net $ 111,336 $ 66,938 $ 522,153 $ 216,156
Distributable cash flow $ 85,311 $ 54,694 $ 244,391 $ 171,942
Maintenance capital expenditures, net 1,947 4,001 7,819 7,313
Changes in receivables and other assets (17,856 ) (19,966 ) (33,255 ) (32,979 )
Changes in accounts payable, accrued liabilities and other long-term liabilities 38,405 16,118 69,372

24,335
Derivative instrument premium payments, net of amortization 1,137 492 3,281 1,586
Cash adjustment for non-controlling interest of consolidated subsidiaries 18,227 8,274 46,285 19,317
Other (2,286 ) 2,989 (6,644 ) 5,724
Net cash provided by operating activities $ 124,885 $ 66,602 $ 331,249 $ 197,238
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,
2011 2010 2011 2010
Net income (loss) $ 153,454 $ (18,676 ) $ 167,988 $ 74,296
Non-cash compensation expense 995 1,447 3,707 6,456
Non-cash derivative activity (126,802 ) 50,610 (102,681 ) (13,980 )
Interest expense (1) 25,687 27,802 80,235 77,777
Depreciation, amortization, impairment, and other non-cash operating expenses 50,482 43,640 148,699 122,578
Loss on redemption of debt 133 - 43,461 -
Provision for income tax 25,864 (10,238 ) 26,442 10,209
Adjustment for cash flow from unconsolidated affiliate 507 1,450 1,562

1,089
Adjustment related to non-wholly owned, consolidated subsidiaries (22,713 ) (11,866 ) (44,819 )

(32,631 )
Other (594 ) (432 ) (1,390 ) (912 )
Adjusted EBITDA $ 107,013 $ 83,737 $ 323,204 $ 244,882

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

MarkWest periodically estimates the effect on DCF resulting from its commodity risk management program, changes in crude oil and natural gas prices, and the correlation of NGL prices to crude oil. The table below reflects MarkWest's estimate of the range of DCF for 2012 and forecasted crude oil and natural gas prices for 2012. The analysis assumes various combinations of crude oil and natural gas prices as well as three NGL to crude correlation scenarios, including:

a. The three-year NGL correlation to crude for 2012.

b. One standard deviation above the three-year NGL correlation to crude for 2012.

c. One standard deviation below the three-year NGL correlation to crude for 2012.

The analysis further assumes derivative instruments outstanding as of October 28, 2011, and production volumes estimated through December 31, 2012. The range of stated hypothetical changes in commodity prices considers current and historic market performance.

Natural Gas Price
Crude Oil Price Three-year NGL Correlation to Crude $ 3.00 $ 3.50 $ 4.00 $ 4.50 $ 5.00
One standard deviation above $ 586 $ 578 $ 569 $ 561 $ 552
$110 Three-year NGL correlation to crude $ 508 $ 500 $ 491 $ 483 $ 474
One standard deviation below $ 434 $ 426 $ 417 $ 409 $ 400
One standard deviation above $ 545 $ 536 $ 528 $ 519 $ 511
$100 Three-year NGL correlation to crude $ 475 $ 466 $ 458 $ 449 $ 441
One standard deviation below $ 408 $ 399 $ 391 $ 382 $ 373
One standard deviation above $ 499 $ 491 $ 482 $ 474 $ 465
$90 Three-year NGL correlation to crude $ 438 $ 430 $ 421 $ 413 $ 404
One standard deviation below $ 377 $ 369 $ 360 $ 352 $ 341
One standard deviation above $ 453 $ 445 $ 436 $ 428 $ 419
$80 Three-year NGL correlation to crude $ 400 $ 392 $ 383 $ 375 $ 366
One standard deviation below $ 346 $ 337 $ 329 $ 317 $ 307
One standard deviation above $ 413 $ 404 $ 396 $ 387 $ 379
$70 Three-year NGL correlation to crude $ 365 $ 357 $ 348 $ 340 $ 331
One standard deviation below $ 318 $ 309 $ 298 $ 288 $ 280

The table is based on current information, expectations, and beliefs concerning future developments and their potential effects, and does not consider actions MarkWest management may take to mitigate exposure to changes. Nor does the table consider the effects that such hypothetical adverse changes may have on overall economic activity. Historical prices and correlations do not guarantee future results.

Although MarkWest believes the expectations reflected in this analysis are reasonable, MarkWest 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, and the correlation between crude oil and NGL 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 MarkWest's periodic reports filed with the SEC, specifically those under the heading "Risk Factors."

SOURCE: MarkWest Energy Partners

MarkWest Energy Partners, L.P.
Frank Semple, 866-858-0482
Chairman, President & CEO
or
Nancy Buese, 866-858-0482
Senior VP and CFO
or
Dan Campbell, 866-858-0482
VP of Finance & Treasurer
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E-mail: investorrelations@markwest.com