MarkWest Energy Partners Reports Record Quarterly Distributable Cash Flow, Increases Quarterly Common Unit Distribution By 17.9 Percent

MarkWest Energy Partners, LP (NYSE: MWE) (the Partnership) today reported record quarterly cash available for distribution to common unitholders, or distributable cash flow (DCF), of $109.2 million for the three months ended March 31, 2012, compared to $76.1 million for the three months ended March 31, 2011. DCF for the three months ended March 31, 2012 represents 135 percent coverage of the first quarter distribution of $81.1 million, or $0.79 per common unit, which will be paid to unitholders on May 15, 2012. As a Master Limited Partnership (MLP), 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 record quarterly Adjusted EBITDA of $132.9 million for the three months ended March 31, 2012, compared to $96.2 million for the same period in 2011. The Partnership believes the presentation of Adjusted EBITDA provides useful information because it is commonly used by investors in MLPs 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 ended March 31, 2012 of $20.8 million, compared to a loss of $88.8 million for the same period in 2011. Income (loss) before provision for income tax includes non-cash losses associated with the change in fair value of derivative instruments of $48.2 million and $79.8 million for the three months ended March 31, 2012 and March 31, 2011, respectively, and costs associated with the redemption of debt of $43.3 million for the three months ended March 31, 2011. Excluding these items, income (loss) before provision for income tax for the three months ended March 31, 2012 and 2011 would have been $69.0 million and $34.3 million, respectively.

“Our record distributable cash flow for the first quarter allowed us to deliver year-over-year distribution growth of nearly 18 percent while maintaining a coverage ratio of 1.35 times,” said Frank Semple, Chairman, President and Chief Executive Officer. “Our strategy of developing fully integrated midstream services in the liquids rich areas of the major U.S. shale plays continues to provide significant growth opportunities. We are in the process of constructing 13 cryogenic natural gas processing facilities and a world class fractionation facility to support our producers in the Marcellus, Utica, Huron and the Haynesville/Cotton Valley. Also, the Keystone acquisition and our NGL gathering system expansion will further extend our Marcellus midstream platform into the rich gas corridor of Northwest Pennsylvania. The quality of our existing core assets and our ongoing expansion projects support our objective of providing long term sustainable top quartile returns for our unitholders.”

BUSINESS HIGHLIGHTS

Keystone Midstream Services Acquisition
  • The Partnership announced today that it is acquiring 100% of the ownership interests of Keystone Midstream Services, LLC (Keystone), for consideration of $512 million. Keystone is owned by Stonehenge Energy Resources, LP, and affiliates of Rex Energy Corporation (Rex Energy), and Sumitomo Corporation (Sumitomo). Keystone’s existing assets are located in Butler County, Pennsylvania and include two cryogenic gas processing plants totaling 90 million cubic feet per day (MMcf/d) of capacity, a gas gathering system and associated field compression. Rex Energy and Sumitomo have dedicated an 895 square mile area to the Partnership. To date they have jointly leased 68,400 highly prospective acres in Butler County, an acreage position that continues to grow. The Partnership will gather and process the rich gas and fractionate the natural gas liquids (NGLs) under long-term fee-based agreements.
  • In conjunction with the acquisition of Keystone, MarkWest Utica EMG, LLC (MarkWest Utica) executed a letter agreement to discuss gathering, processing, and NGL fractionation agreements for portions of Rex Energy’s Ohio Utica acreage.

Business Development
  • Southwest – In March 2012, the Partnership announced it has entered into long-term gathering and processing agreements with Anadarko, Chevron, PetroQuest Energy, and Samson Lone Star that support a 120 MMcf/d expansion of the Partnership’s cryogenic processing capacity in East Texas (Carthage East). Carthage East is under construction and is scheduled to come on line in the first quarter of 2013. With the completion of this plant, total processing capacity in East Texas will increase to 400 MMcf/d.
  • Liberty – In January 2012, the Partnership announced significant expansion projects to serve producer customers in the hydrocarbon-rich area of the Marcellus Shale in northern West Virginia and southwest Pennsylvania area including a 400 MMcf/d expansion of its Majorsville processing complex which includes two, 200 MMcf/d processing plants that are expected to be completed in 2013 and are supported by long-term agreements with CONSOL Energy, Noble Energy, and Range Resources.
In May 2012, the Partnership announced additional major expansion projects to serve producer customers in the hydrocarbon-rich area of the Marcellus Shale in northern West Virginia and southwest Pennsylvania area, including another 400 MMcf/d expansion of its Majorsville processing complex which includes two, 200 MMcf/d processing plants that are expected to be completed in late 2013 and mid 2014 and are supported by long-term agreements with Chesapeake Energy. Considering the expansions announced in January and May 2012, the Partnership will have 1.1 billion cubic feet per day of cryogenic processing capacity at its Majorsville processing complex.
 
In May 2012, the Partnership announced a long-term fee-based agreement with Antero Resources Appalachian Corporation to install gathering facilities in support of Antero’s rapidly growing rich natural gas production in Doddridge and Harrison Counties in northern West Virginia. The new gathering system will have the capacity to initially deliver more than 300 MMcf/d of Antero’s rich gas to the Partnership’s Sherwood gas processing complex. The first phase of the gathering system will be completed in the third quarter of 2012 in conjunction with the completion of the 200 MMcf/d Sherwood I processing facility.
 
The Partnership also announced today that it is extending its existing NGL gathering pipeline from its Houston, Pennsylvania fractionation complex into Beaver, Butler and Lawrence Counties to gather NGLs from the Keystone processing facilities and other planned processing projects in northwest Pennsylvania. The NGL pipeline expansion will allow Rex Energy and other producers to access all of the anticipated ethane pipeline projects.
  • Utica – In March 2012, MarkWest Utica announced the execution of a letter of intent with Gulfport Energy Corporation to provide gathering, processing, fractionation, and marketing services in the liquids-rich corridor of the Utica Shale. MarkWest Utica has begun construction of its facilities and the first phase is expected to come online beginning in the second half of 2012. MarkWest Utica will process the gas at its Harrison County processing complex, and will provide NGL fractionation and marketing services at the Harrison County fractionator, where NGL purity products will be marketed by truck, rail, and pipeline.

Capital Markets
  • During the first quarter 2012, the Partnership completed a common unit equity offering of 6.8 million common units, which included the exercise of the underwriters’ over-allotment option. The net proceeds of approximately $388 million were used to partially fund its ongoing capital expenditure program.

FINANCIAL RESULTS

Balance Sheet

  • At March 31, 2012, the Partnership had $347.8 million of cash and cash equivalents in wholly owned subsidiaries and $877.7 million available for borrowing under its $900 million revolving credit facility after consideration of $22.3 million of outstanding letters of credit.

Operating Results
  • Operating income before items not allocated to segments for the three months ended March 31, 2012, was $194.2 million, an increase of $45.8 million when compared to $148.4 million for the same period in 2011. This increase is primarily attributable to the ongoing expansion as well as the acquisition of the noncontrolling interest in the Liberty segment, and increased NGL volumes in the Southwest and Northeast segments. 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 $17.6 million in the first quarter of 2012 compared to realized losses of $22.3 million in the first quarter of 2011.

Capital Expenditures
  • For the three months ended March 31, 2012, the Partnership’s portion of capital expenditures was $254.3 million.

2012 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

For 2012, the Partnership forecasts DCF in a range of $440 million to $500 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, natural gas and natural gas liquids; and the Keystone acquisition, as mentioned above. The midpoint of this range results in approximately 145 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 was increased for the expected additional capital requirements to develop the Keystone assets and is forecasted in a range of $1.1 billion to $1.5 billion. This range excludes the Keystone purchase price of $512 million. Maintenance capital for 2012 is forecasted at approximately $20 million.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Tuesday, May 8, 2012, at 12:00 p.m. Eastern Time to review its first quarter 2012 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 (800) 272-5921 (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 filed with the SEC, including MarkWest's Annual Report on Form 10-K for the year ended December 31, 2011, and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2012. 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 March 31,
Statement of Operations Data   2012     2011  
Revenue:
Revenue $ 399,181 $ 348,900
Derivative loss   (48,715 )   (85,679 )
Total revenue   350,466     263,221  
 
Operating expenses:
Purchased product costs 154,555 153,629
Derivative loss related to purchased product costs 18,800 19,394
Facility expenses 48,840 39,424
Derivative gain related to facility expenses (1,746 ) (3,011 )
Selling, general and administrative expenses 25,224 21,712
Depreciation 41,145 34,364
Amortization of intangible assets 10,985 10,817
Loss on disposal of property, plant and equipment 986 2,099
Accretion of asset retirement obligations   238     87  
Total operating expenses   299,027     278,515  
 
Income (loss) from operations 51,439 (15,294 )
 
Other income (expense):
Loss from unconsolidated affiliates (9 ) (539 )
Interest income 72 89
Interest expense (29,472 ) (28,263 )

Amortization of deferred financing costs and discount (a component of interest expense)
(1,270 ) (1,428 )
Loss on redemption of debt - (43,328 )
Miscellaneous income (loss), net   58     (38 )
Income (loss) before provision for income tax 20,818 (88,801 )
 
Provision for income tax expense (benefit):
Current 15,341 56
Deferred   (10,796 )   (14,186 )
Total provision for income tax   4,545     (14,130 )
 
Net income (loss) 16,273 (74,671 )
 
Net income attributable to non-controlling interest (253 ) (9,358 )
   
Net income (loss) attributable to the Partnership $ 16,020   $ (84,029 )
 
Net income (loss) attributable to the Partnership's common unitholders per common unit:

 
Basic $ 0.16   $ (1.13 )
Diluted $ 0.14   $ (1.13 )
 
Weighted average number of outstanding common units:
Basic   96,840     74,531  
Diluted   117,593     74,531  
 
Cash Flow Data
Net cash flow provided by (used in):
Operating activities $ 207,913 $ 115,319
Investing activities (252,969 ) (341,621 )
Financing activities 278,674 232,004
 
Other Financial Data
Distributable cash flow $ 109,177 $ 76,136
Adjusted EBITDA 132,943 96,187
 
Balance Sheet Data March 31, 2012 December 31, 2011
Working capital $ 113,344 $ 4,234
Total assets 4,445,647 4,070,425
Total debt 1,780,091 1,846,062
Total equity 1,852,301 1,502,067
 
     

MarkWest Energy Partners, L.P.
Operating Statistics
 
Three months ended March 31,
2012 2011
Southwest
East Texas gathering systems throughput (Mcf/d) 410,000 425,800
East Texas natural gas processed (Mcf/d) 242,500 219,200
East Texas NGL sales (gallons, in thousands) 63,400 56,700
 
Western Oklahoma gathering system throughput (Mcf/d) (1) 262,000 207,400
Western Oklahoma natural gas processed (Mcf/d) 203,800 157,100
Western Oklahoma NGL sales (gallons, in thousands) 57,300 39,000
 
Southeast Oklahoma gathering system throughput (Mcf/d) 501,200 498,000
Southeast Oklahoma natural gas processed (Mcf/d) (2) 101,700 93,700
Southeast Oklahoma NGL sales (gallons, in thousands) 33,000 29,400
Arkoma Connector Pipeline throughput (Mcf/d) 328,700 285,900
 
Other Southwest gathering system throughput (Mcf/d) 25,000 33,100
 
Northeast
Natural gas processed (Mcf/d) (3) 321,700 304,800
NGLs fractionated (Bbl/d) (4) 16,700 22,200
 
Keep-whole sales (gallons, in thousands) 49,500 39,800
Percent-of-proceeds sales (gallons, in thousands) 33,000 30,900
Total NGL sales (gallons, in thousands) (5) 82,500 70,700
 
Crude oil transported for a fee (Bbl/d) 10,400 10,200
 
Liberty
Natural gas processed (Mcf/d) 392,100 254,500
Gathering system throughput (Mcf/d) 308,100 195,900
NGLs fractionated (Bbl/d) (6) 20,000 6,900
NGL sales (gallons, in thousands) (7) 97,500 51,800
 
Gulf Coast
Refinery off-gas processed (Mcf/d) 120,300 102,800
Liquids fractionated (Bbl/d) 23,400 19,200
NGL sales (gallons excluding hydrogen, in thousands) 89,300 72,700
 
(1)   Includes natural gas gathered in Western Oklahoma and from the Granite Wash formation in the Texas Panhandle as it is one integrated area of operations.
(2) The natural gas processing in Southeast Oklahoma is outsourced to Centrahoma, our equity investment, or other third-party processors.
(3) Includes throughput from the Kenova, Cobb, Boldman and Langley processing plants. We acquired the Langley processing plant in February 2011. The volumes reported for the three months ended March 31, 2011 are the average daily rates for the days of operation.
(4) Amount includes zero barrels per day and 5,500 barrels per day fractionated on behalf of Liberty for the three months ended March 31, 2012 and 2011, respectively. Beginning in the fourth quarter of 2011, Siloam no longer fractionated NGLs on behalf of Liberty due to the operation of Liberty’s fractionation facility that began in September 2011.
(5) Represents sales from the Siloam facilities. The total sales exclude approximately zero gallons and 20,700,000 gallons sold by the Northeast on behalf of Liberty for the three months ended March 31, 2012 and 2011, respectively. These volumes are included as part of NGLs sold at Liberty.
(6) Amount includes all NGLs that were produced at the Liberty processing facilities and fractionated into purity products at our Liberty fractionation facility.
(7) 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 from 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 March 31, 2012 Southwest Northeast Liberty Gulf Coast Total
Revenue $ 214,725 $ 86,918 $ 75,577 $ 24,229 $ 401,449
 
Operating expenses:
Purchased product costs 104,233 25,687 24,635 - 154,555
Facility expenses   22,992   6,378   12,247   9,638   51,255
Total operating expenses before items not allocated to segments 87,500 54,853 38,695 14,591 195,639
 
Portion of operating income attributable to non-controlling interests   1,446   -   -   -   1,446
Operating income before items not allocated to segments $ 86,054 $ 54,853 $ 38,695 $ 14,591 $ 194,193
 
 
Three months ended March 31, 2011 Southwest Northeast Liberty Gulf Coast Total
Revenue $ 201,774 $ 92,091 $ 41,219 $ 21,759 $ 356,843
 
Operating expenses:
Purchased product costs 103,196 40,878 9,555 - 153,629
Facility expenses   20,157   5,594   6,498   8,990   41,239
Total operating expenses before items not allocated to segments 78,421 45,619 25,166 12,769 161,975
 
Portion of operating income attributable to non-controlling interests   1,172   -   12,377   -   13,549
Operating income before items not allocated to segments $ 77,249 $ 45,619 $ 12,789 $ 12,769 $ 148,426
 
     
Three months ended March 31,
  2012     2011  
 
Operating income before items not allocated to segments $ 194,193 $ 148,426
Portion of operating income attributable to non-controlling interests 1,446 13,549
Derivative loss not allocated to segments (65,769 ) (102,062 )
Revenue deferral adjustment (2,268 ) (7,943 )
Compensation expense included in facility expenses not allocated to segments (449 ) (1,040 )
Facility expenses adjustments 2,864 2,855
Selling, general and administrative expenses (25,224 ) (21,712 )
Depreciation (41,145 ) (34,364 )
Amortization of intangible assets (10,985 ) (10,817 )
Loss on disposal of property, plant and equipment (986 ) (2,099 )
Accretion of asset retirement obligations   (238 )   (87 )
Income (loss) from operations 51,439 (15,294 )
Other income (expense):
Loss from unconsolidated affiliates (9 ) (539 )
Interest income 72 89
Interest expense (29,472 ) (28,263 )

Amortization of deferred financing costs and discount (a component of interest expense)
(1,270 ) (1,428 )
Loss on redemption of debt - (43,328 )
Miscellaneous income, net   58     (38 )
Income (loss) before provision for income tax $ 20,818   $ (88,801 )
 
     
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Distributable Cash Flow
(unaudited, in thousands)
 
Three months ended March 31,
  2012     2011  
 
Net income (loss) $ 16,273 $ (74,671 )
Depreciation, amortization, impairment, and other non-cash operating expenses 53,432 47,445
Loss on redemption of debt, net of tax benefit - 39,499
Amortization of deferred financing costs and discount 1,270 1,428
Non-cash loss from unconsolidated affiliate 9 539
Distributions from unconsolidated affiliate 900 -
Non-cash compensation expense 2,710 1,578
Non-cash derivative activity 48,217 79,784
Provision for income tax - deferred (10,796 ) (14,186 )
Cash adjustment for non-controlling interest of consolidated subsidiaries (1,017 ) (12,522 )
Revenue deferral adjustment 2,268 7,943
Other 2,208 1,707
Maintenance capital expenditures, net of joint venture partner contributions   (6,297 )   (2,408 )
Distributable cash flow $ 109,177   $ 76,136  
 
Maintenance capital expenditures $ 6,297 $ 2,506
Growth capital expenditures   247,966     111,146  
Total capital expenditures 254,263 113,652
Acquisition   -     230,728  
Total capital expenditures and acquisition 254,263 344,380
Joint venture partner contributions   -     (35,176 )
Total capital expenditures and acquisition, net $ 254,263   $ 309,204  
 
Distributable cash flow $ 109,177 $ 76,136
Maintenance capital expenditures, net 6,297 2,408
Changes in receivables and other assets 57,655 19,869
Changes in accounts payable, accrued liabilities and other long-term liabilities 35,244 5,102
Derivative instrument premium payments, net of amortization - 1,045
Cash adjustment for non-controlling interest of consolidated subsidiaries 1,017 12,522
Other   (1,477 )   (1,763 )
Net cash provided by operating activities $ 207,913   $ 115,319  
 
     
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Adjusted EBITDA
(unaudited, in thousands)
 
Three months ended March 31,
  2012     2011  
 
Net income (loss) $ 16,273 $ (74,671 )
Non-cash compensation expense 2,710 1,578
Non-cash derivative activity 48,217 79,784
Interest expense (1) 28,552 27,456
Depreciation, amortization, impairment, and other non-cash operating expenses 53,432 47,445
Loss on redemption of debt - 43,328
Provision for income tax 4,545 (14,130 )
Adjustment for cash flow from unconsolidated affiliate 909 539
Adjustment related to non-guarantor, consolidated subsidiaries (2) (21,198 ) (14,690 )
Other   (497 )   (452 )
Adjusted EBITDA $ 132,943   $ 96,187  
 

(1)
 

Includes amortization of deferred financing costs and discount, and excludes interest expense related to the Steam Methane Reformer.

(2)

The non-guarantor subsidiaries, in accordance with Credit Facility covenants, are MarkWest Liberty Midstream & Resources, L.L.C. (Liberty), MarkWest Utica EMG L.L.C., MarkWest Pioneer, L.L.C., Wirth Gathering Partnership, and Bright Star Partnership. As of January 1, 2012, Liberty is a wholly owned subsidiary but remains a non-guarantor in accordance with the Credit Facility.
 

MarkWest Energy Partners, L.P. Distributable Cash Flow Sensitivity Analysis

(unaudited, in millions except commodity prices)

The Partnership 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 The Partnership’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 for all NGLs (C2+), 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 April 30, 2012, and production volumes estimated through December 31, 2012. The range of stated hypothetical changes in commodity prices considers current and historic market performance.

Estimated Range of 2012 DCF
                                 
          Natural Gas Price
Crude Oil Price   Three-year NGL Correlation to Crude     $2.00     $2.50     $3.00     $3.50     $4.00
One standard deviation above     561     557     553     549     546
$120 Three-year NGL correlation to crude     501     497     494     490     486
    One standard deviation below     443     439     435     432     428
One standard deviation above     543     540     536     532     529
$110 Three-year NGL correlation to crude     489     485     481     478     474
    One standard deviation below     437     433     429     426     422
One standard deviation above     522     519     515     511     507
$100 Three-year NGL correlation to crude     473     469     466     462     458
    One standard deviation below     426     422     419     415     411
One standard deviation above     499     495     491     487     484
$90 Three-year NGL correlation to crude     455     452     448     444     441
    One standard deviation below     413     409     405     402     398
One standard deviation above     477     473     470     466     462
$80 Three-year NGL correlation to crude     440     436     433     429     425
    One standard deviation below     402     398     394     391     388
               

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. 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, particularly those under the heading “Risk Factors.”

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