News Release

Printer Friendly Version View printer-friendly version
<< Back
MarkWest Energy Partners Reports Record Quarterly Distributable Cash Flow and Increases Common Unit Distribution by 9.4 Percent
Download PDF Download PDF

DENVER, Aug 08, 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 $82.9 million for the three months ended June 30, 2011, and $159.1 million for the six months ended June 30, 2011. Distributable cash flow for the three months and six months ended June 30, 2011, represents distribution coverage of 150 percent. The second quarter distribution of $55.4 million, or $0.70 per common unit, will be paid to unitholders on August 12, 2011. The second quarter 2011 distribution represents an increase of $0.03 per common unit, or 4.5 percent, over the first quarter 2011 distribution and an increase of $0.06 per common unit, or 9.4 percent, over the second 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 $120.0 million for the three months ended June 30, 2011, and $216.2 million for the six months ended June 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 six months ended June 30, 2011, of $103.9 million and $15.1 million, respectively. Income before provision for income tax includes non-cash gain (loss) associated with the change in mark-to-market of derivative instruments of $55.7 million and $(24.2) million for the three and six months ended June 30, 2011, respectively, and costs associated with the redemption of debt of $(43.3) million for the six months ended June 30, 2011. Excluding these items, income before provision for income tax for the three and six months ended June 30, 2011, would have been $48.2 million and $82.6 million, respectively.

"MarkWest had an outstanding second quarter with record distributable cash flow and a significant increase in distributions," said Frank Semple, Chairman, President and Chief Executive Officer. "Since 2008 we have invested $2 billion in high-quality projects to significantly expand our presence in liquids-rich resource plays that provide superior economics for our producer customers and solid results for MarkWest. Our strong growth in DCF and distributions reflects the success of this strategy, and supports our objective to deliver superior and sustainable total returns for our unitholders."

BUSINESS HIGHLIGHTS

Capital Markets

  • On June 15, 2011, the Partnership amended its $705 million senior secured revolving credit facility to increase the borrowing capacity to $745 million.
  • On July 13, 2011, the Partnership completed a common unit equity offering of 4.025 million common units. The net proceeds of approximately $185.1 million were used to repay amounts outstanding under its revolving credit facility and to fund its ongoing capital expenditure program.

Business Development

  • In the second quarter of 2011, MarkWest Liberty commenced operations of its 200 million cubic feet per day (MMcf/d) Houston III cryogenic processing plant and its 135 MMcf/d Majorsville II cryogenic processing plant, increasing MarkWest Liberty's total processing capacity to 625 MMcf/d.

By late 2012, MarkWest Liberty is expected to operate 945 MMcf/d of cryogenic processing capacity in the liquids-rich areas of the Marcellus Shale, which includes current processing capacity of 625 MMcf/d and new processing capacity under construction of 320 MMcf/d. The new processing capacity includes the 120 MMcf/d Mobley, West Virginia processing complex that will primarily serve liquids-rich gas transported in EQT's Equitrans gas pipeline and a 200 MMcf/d processing complex near Sherwood, West Virginia that will serve the core of the Marcellus liquids-rich production in Doddridge and Wetzel counties. The Mobley and Sherwood processing complexes are supported by long-term agreements with high-quality producer customers. In addition, MarkWest Liberty is in discussions with its producer customers regarding additional processing expansions.

  • On July 21, 2011, Sunoco Logistics Partners L.P. announced a binding open season for Mariner West, a pipeline project developed jointly by Sunoco Logistics and MarkWest Liberty to deliver Marcellus Shale ethane from MarkWest Liberty's Houston, Pennsylvania processing and fractionation complex to Sarnia, Ontario, Canada markets. Mariner West is anticipated to have an initial capacity to transport up to 50,000 barrels per day of ethane, and is scheduled to be operational by mid-2013. The open season will end August 22, 2011.

FINANCIAL RESULTS

Balance Sheet

  • At June 30, 2011, the Partnership had $71.6 million of cash and cash equivalents in wholly owned subsidiaries and $471.2 million available for borrowing under its $745 million revolving credit facility after consideration of $27.3 million of outstanding letters of credit.

Operating Results

  • Operating income before items not allocated to segments for the three months ended June 30, 2011, was $147.8 million, an increase of $45.7 million when compared to segment operating income of $102.1 million in the same period in 2010. This increase is primarily attributable to higher 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 $(17.7) million in the second quarter of 2011 compared to realized losses of $(11.4) million in the second quarter of 2010.

Capital Expenditures

  • For the three and six months ended June 30, 2011, the Partnership's portion of capital expenditures was $101.6 million and $410.8 million, respectively. Capital expenditures for the six months ended June 30, 2011, include the $230.7 million acquisition of EQT's Langley processing complex and the Ranger natural gas liquids (NGL) pipeline.

2011 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

For 2011, the Partnership increased its DCF forecast from a range of $280 million to $320 million to a range of $300 million to $330 million based on forecasted operational volumes from existing operations, growth capital projects that will be completed and commence operations during 2011, derivative instruments currently outstanding, and a reasonable range of price estimates for crude oil and natural gas. 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 2011 DCF is provided within the tables of this press release.

The Partnership's portion of growth capital expenditures for 2011 is forecasted 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.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Tuesday, August 9, 2011, at 4:00 p.m. Eastern Time to review its second 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) 516-0668 (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 June 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 June 30, Six months ended June 30,
Statement of Operations Data 2011 2010 2011 2010
Revenue:
Revenue $ 359,849 $ 276,948 $ 708,749 $ 592,563
Derivative gain (loss) 40,590 46,902 (45,089 ) 39,666
Total revenue 400,439 323,850 663,660 632,229
Operating expenses:
Purchased product costs 154,580 128,123 308,209 272,419
Derivative (gain) loss related to purchased product costs (254 ) (8,392 ) 19,140 4,997
Facility expenses 40,698 37,427 80,122 75,332
Derivative loss (gain) related to facility expenses 2,927 934 (84 ) 128
Selling, general and administrative expenses 18,580 16,419 40,292 37,927
Depreciation

37,201

29,818 71,565 58,005
Amortization of intangible assets 10,830 10,193 21,647 20,386
Loss on disposal of property, plant and equipment 2,373 188 4,472 179
Accretion of asset retirement obligations 290 69 377 212
Total operating expenses 267,225 214,779 545,740 469,585
Income from operations 133,214 109,071 117,920 162,644
Other income (expense):
(Loss) earnings from unconsolidated affiliates (216 ) 1,585 (755 ) 1,517
Interest income 63 377 152 763
Interest expense (27,874 ) (25,755 ) (56,137 ) (49,537 )
Amortization of deferred financing costs and discount (a component of interest expense) (1,443 ) (2,280 ) (2,871 ) (4,892 )
Derivative gain related to interest expense - - - 1,871
Loss on redemption of debt - - (43,328 ) -
Miscellaneous income (expense), net 169 (9 ) 131 1,053
Income before provision for income tax 103,913 82,989 15,112 113,419
Provision for income tax expense (benefit):
Current 4,089 923 4,145 6,721
Deferred 10,619 15,098 (3,567 ) 13,726
Total provision for income tax 14,708 16,021 578 20,447
Net income 89,205 66,968 14,534 92,972
Net income attributable to non-controlling interest (10,708 ) (6,751 ) (20,066 ) (11,245 )
Net income (loss) attributable to the Partnership $ 78,497 $ 60,217 $ (5,532 ) $ 81,727
Net income (loss) attributable to the Partnership's common unitholders per common unit:
Basic $ 1.03 $ 0.84 $ (0.09 ) $ 1.18
Diluted $ 1.03 $ 0.84 $ (0.09 ) $ 1.18
Weighted average number of outstanding common units:
Basic 75,160 71,111 74,847 68,795
Diluted 75,266 71,298 74,847 68,889
Cash Flow Data
Net cash flow provided by (used in):
Operating activities $ 91,045 $ 16,276 $ 206,364 $ 130,636
Investing activities $ (120,428 ) $ (157,813 ) $ (462,049 ) $ (252,843 )
Financing activities $ 51,266 $ 171,233 $ 283,270 $ 159,326
Other Financial Data
Distributable cash flow $ 82,944 $ 52,905 $ 159,080 $ 117,248
Adjusted EBITDA $ 120,004 $ 72,683 $ 216,191 $ 161,145
Balance Sheet Data June 30, 2011 December 31, 2010
Working capital $ (25,186 ) $ (43,296 )
Total assets 3,735,025 3,333,362
Total debt 1,582,102 1,273,434
Total equity 1,582,402 1,536,020
MarkWest Energy Partners, L.P.
Operating Statistics
Three months ended June 30, Six months ended June 30,
2011 2010 2011 2010
Southwest
East Texas
Gathering systems throughput (Mcf/d) 428,300 438,700 427,000 433,900
NGL product sales (gallons) 59,488,700 61,887,500 116,170,000 126,083,300
Oklahoma
Foss Lake gathering system throughput (Mcf/d) 72,000 70,600 69,900 72,400
Stiles Ranch gathering system throughput (Mcf/d) 144,400 106,100 138,500 111,800
Grimes gathering system throughput (Mcf/d) 7,500 8,000 7,300 8,000
Arapaho NGL product sales (gallons) 35,088,100 30,093,800 74,108,200 59,537,100
Southeast Oklahoma gathering system throughput (Mcf/d) 511,700 539,400 504,900 518,100
Southeast Oklahoma NGL product sales (gallons) 32,142,900 23,483,000 61,505,500 42,367,800
Arkoma Connector Pipeline throughput (Mcf/d) 298,400 387,500 292,100 372,700
Other Southwest
Appleby gathering system throughput (Mcf/d) 24,800 31,600 25,600 33,100
Other gathering systems throughput (Mcf/d) (1) 6,800 8,700 6,700 8,800
Northeast
Appalachia
Natural gas processed (Mcf/d) (2) 319,600 199,900 312,500 196,400
Keep-whole sales (gallons) 21,078,000 30,815,000 60,913,900 76,587,400
Percent-of-proceeds sales (gallons) 33,092,100 30,118,700 63,987,500 57,123,600
Total NGL product sales (gallons) (3) 54,170,100 60,933,700 124,901,400 133,711,000
Michigan
Crude oil transported for a fee (Bbl/d) 11,500 12,100 10,800 12,500
Liberty
Natural gas processed (Mcf/d) 298,200 116,000 276,500 105,000
Gathering system throughput (Mcf/d) 232,000 128,500 214,000 114,800
NGL product sales (gallons) 50,668,000 23,462,500 102,429,600 44,992,700
Gulf Coast
Javelina
Refinery off-gas processed (Mcf/d) 114,600 118,800 108,700 116,100
Liquids fractionated (Bbl/d) 21,900 22,800 20,600 22,700
(1) Excludes lateral pipelines where revenue is not based on throughput.
(2) Includes throughput from the Kenova, Cobb, Boldman, and recently acquired Langley processing plants.
(3) Represents sales at the Siloam NGL fractionation plant. The total sales exclude 20,897,000 gallons and 12,648,600 gallons sold by the Northeast on behalf of Liberty for the three months ended June 30, 2011 and 2010, respectively, and 41,542,000 gallons and 23,305,800 gallons sold for the six months ended June 30, 2011 and 2010, respectively.
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 June 30, 2011 Southwest Northeast Liberty Gulf Coast Total
Revenue $ 235,575 $ 53,676 $ 48,337 $ 24,683 $ 362,271
Operating expenses:
Purchased product costs 128,988 15,702 9,890 - 154,580
Facility expenses 20,855 6,929 7,269 8,312 43,365
Total operating expenses before items not allocated to segments 149,843 22,631 17,159 8,312 197,945
Portion of operating income attributable to non-controlling interests 1,346 - 15,182 - 16,528
Operating income before items not allocated to segments $ 84,386 $ 31,045 $ 15,996 $ 16,371 $ 147,798
Three months ended June 30, 2010 Southwest Northeast Liberty Gulf Coast Total
Revenue $ 155,043 $ 81,322 $ 18,738 $ 21,845 $ 276,948
Operating expenses:
Purchased product costs 71,389 56,734 - - 128,123
Facility expenses 19,395 5,062 6,140 9,395 39,992
Total operating expenses before items not allocated to segments 90,784 61,796 6,140 9,395 168,115
Portion of operating income attributable to non-controlling interests 1,556 - 5,208 - 6,764
Operating income before items not allocated to segments $ 62,703 $ 19,526 $ 7,390 $ 12,450 $ 102,069

Three months ended June 30,

2011 2010
Operating income before items not allocated to segments $ 147,798 $ 102,069
Portion of operating income attributable to non-controlling interests 16,528 6,764
Derivative gain not allocated to segments 37,917 54,360
Revenue deferral adjustment (2,422 ) -
Compensation expense included in facility expenses not allocated to segments (188 ) (286 )
Facility expenses adjustments 2,855 2,851
Selling, general and administrative expenses (18,580 ) (16,419 )
Depreciation (37,201 ) (29,818 )
Amortization of intangible assets (10,830 ) (10,193 )
Loss on disposal of property, plant and equipment (2,373 ) (188 )
Accretion of asset retirement obligations (290 ) (69 )
Income from operations 133,214 109,071
Other income (expense):
(Loss) earnings from unconsolidated affiliate (216 ) 1,585
Interest income 63 377
Interest expense (27,874 ) (25,755 )
Amortization of deferred financing costs and discount (a component of interest expense) (1,443 ) (2,280 )
Miscellaneous income (expense), net 169 (9 )
Income before provision for income tax $ 103,913 $ 82,989
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)
Six months ended June 30, 2011 Southwest Northeast Liberty Gulf Coast Total
Revenue $ 437,349 $ 145,767 $ 89,556 $ 46,442 $ 719,114
Operating expenses:
Purchased product costs 232,184 56,580 19,445 - 308,209
Facility expenses 41,012 12,523 13,767 17,302 84,604
Total operating expenses before items not allocated to segments 273,196 69,103 33,212 17,302 392,813
Portion of operating income attributable to non-controlling interests 2,518 - 27,559 - 30,077
Operating income before items not allocated to segments $ 161,635 $ 76,664 $ 28,785 $ 29,140 $ 296,224
Six months ended June 30, 2010 Southwest Northeast Liberty Gulf Coast Total
Revenue $ 320,007 $ 193,170 $ 37,748 $ 41,638 $ 592,563
Operating expenses:
Purchased product costs 146,014 123,821 2,584 - 272,419
Facility expenses 39,884 9,287 13,453 15,090 77,714
Total operating expenses before items not allocated to segments 185,898 133,108 16,037 15,090 350,133
Portion of operating income attributable to non-controlling interests 3,056 - 8,845 - 11,901
Operating income before items not allocated to segments $ 131,053 $ 60,062 $ 12,866 $ 26,548 $ 230,529

Six months ended June 30,

2011 2010
Operating income before items not allocated to segments $ 296,224 $ 230,529
Portion of operating income attributable to non-controlling interests 30,077 11,901
Derivative (loss) gain not allocated to segments (64,145 ) 34,541
Revenue deferral adjustment (10,365 ) -
Compensation expense included in facility expenses not allocated to segments (1,228 ) (1,008 )
Facility expenses adjustments 5,710 3,390
Selling, general and administrative expenses (40,292 ) (37,927 )
Depreciation (71,565 ) (58,005 )
Amortization of intangible assets (21,647 ) (20,386 )
Loss on disposal of property, plant and equipment (4,472 ) (179 )
Accretion of asset retirement obligations (377 ) (212 )
Income from operations 117,920 162,644
Other income (expense):
(Loss) earnings from unconsolidated affiliate (755 ) 1,517
Interest income 152 763
Interest expense (56,137 ) (49,537 )
Amortization of deferred financing costs and discount (a component of interest expense) (2,871 ) (4,892 )
Derivative gain related to interest expense - 1,871
Loss on redemption of debt (43,328 ) -
Miscellaneous income, net 131 1,053
Income before provision for income tax $ 15,112 $ 113,419
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Distributable Cash Flow
(unaudited, in thousands)
Three months ended June 30, Six months ended June 30,
2011 2010 2011 2010
Net income $ 89,205 $ 66,968 $ 14,534 $ 92,972
Depreciation, amortization, impairment, and other non-cash operating expenses 50,772 40,346 98,217 78,938
Loss on redemption of debt, net of tax benefit - - 39,499 -
Amortization of deferred financing costs 1,443 2,280 2,871 4,892
Non-cash loss (earnings) from unconsolidated affiliate 216 (1,585 ) 755 (1,517 )
Distributions from unconsolidated affiliate 300 1,155 300 1,155
Non-cash compensation expense 1,134 1,113 2,712 5,009
Non-cash derivative activity (55,663 ) (65,786 ) 24,121 (65,392 )
Provision for income tax - deferred 10,619 15,098 (3,567 ) 13,726
Cash adjustment for non-controlling interest of consolidated subsidiaries (15,536 ) (6,442 ) (28,058 ) (11,043 )
Revenue deferral adjustment 2,422 - 10,365 -
Other 1,496 2,234 3,203 1,820
Maintenance capital expenditures, net of joint venture partner contributions (3,464 ) (2,476 ) (5,872 ) (3,312 )
Distributable cash flow $ 82,944 $ 52,905 $ 159,080 $ 117,248
Maintenance capital expenditures $ 3,892 $ 2,476 $ 6,398 $ 3,312
Growth capital expenditures 116,572 155,462 227,718 249,948
Total capital expenditures 120,464 157,938 234,116 253,260
Acquisition - - 230,728 -
Total capital expenditures and acquisition 120,464 157,938 464,844 253,260
Joint venture partner contributions (18,850 ) (70,357 ) (54,027 ) (104,042 )
Total capital expenditures and acquisition, net $ 101,614 $ 87,581 $ 410,817 $ 149,218
Distributable cash flow $ 82,944 $ 52,905 $ 159,080 $ 117,248
Maintenance capital expenditures, net 3,464 2,476 5,872 3,312
Changes in receivables and other assets (35,268 ) (22,326 ) (15,399 ) (13,013 )
Changes in accounts payable, accrued liabilities and other long-term liabilities 25,865 (22,372 ) 30,967 8,217
Derivative instrument premium payments, net of amortization 1,099 530 2,144 1,094
Cash adjustment for non-controlling interest of consolidated subsidiaries 15,536 6,442 28,058 11,043
Other (2,595 ) (1,379 ) (4,358 ) 2,735
Net cash provided by operating activities $ 91,045 $ 16,276 $ 206,364 $ 130,636
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Adjusted EBITDA
(unaudited, in thousands)
Three months ended June 30, Six months ended June 30,
2011 2010 2011 2010
Net income $ 89,205 $ 66,968 $ 14,534 $ 92,972
Non-cash compensation expense 1,134 1,113 2,712 5,009
Non-cash derivative activity (55,663 ) (65,786 ) 24,121 (64,590 )
Interest expense (1) 27,092 25,769 54,548 49,975
Depreciation, amortization, impairment, and other non-cash operating expenses 50,772 40,346 98,217 78,938
Loss on redemption of debt - - 43,328 -
Provision for income tax 14,708 16,021 578 20,447
Adjustment for cash flow from unconsolidated affiliate 516 (429 ) 1,055 (361 )
Adjustment related to non-wholly owned, consolidated subsidiaries (7,416 ) (10,897 ) (22,106 ) (20,765 )
Other (344 ) (422 ) (796 ) (480 )
Adjusted EBITDA $ 120,004 $ 72,683 $ 216,191 $ 161,145
(1) Includes derivative activity related to interest expense, amortization of deferred financing costs and discount, and excludes interest expense related to the Steam Methane Reformer.

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 2011 given actual results through June 30, 2011, and forecasted crude oil and natural gas prices for the remainder of 2011. The analysis assumes various combinations of crude oil prices and the ratio of crude oil to gas based on three NGL correlation scenarios, including:

a. The three-year NGL correlation to crude for the remainder of 2011.
b. One standard deviation above the three-year NGL correlation to crude for the remainder of 2011.
c. One standard deviation below the three-year NGL correlation to crude for the remainder of 2011.

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

Estimated Range of 2011 DCF

Natural Gas Price
Crude Oil Price Three-year NGL Correlation to Crude $ 3.50 $ 4.00 $ 4.50
One standard deviation above $ 368 $ 367 $ 366
$110 Three-year NGL correlation to crude $ 349 $ 348 $ 347
One standard deviation below $ 333 $ 331 $ 330
One standard deviation above $ 355 $ 354 $ 352
$100 Three-year NGL correlation to crude $ 339 $ 337 $ 336
One standard deviation below $ 323 $ 322 $ 320
One standard deviation above $ 342 $ 340 $ 339
$90 Three-year NGL correlation to crude $ 328 $ 327 $ 325
One standard deviation below $ 314 $ 312 $ 311
One standard deviation above $ 328 $ 327 $ 326
$80 Three-year NGL correlation to crude $ 316 $ 315 $ 313
One standard deviation below $ 303 $ 302 $ 301

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, L.P.

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
investorrelations@markwest.com