Freitag, 25. Mai | 21:44 Uhr

MarkWest Energy Partners, L.P. (NYSE: MWE) (the Partnership) today
reported quarterly cash available for distribution to common
unitholders, or distributable cash flow (DCF), of $54.7 million for the
three months ended September 30, 2010, and $171.9 million for the nine
months ended September 30, 2010. DCF for the three months and nine
months ended September 30, 2010, represents 120 percent and 125 percent
coverage, respectively, of the cash distributions declared for those
periods. 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 $83.7 million for the three
months ended September 30, 2010, and $244.9 million for the nine months
ended September 30, 2010. 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 (loss) before provision for income tax
for the three months and nine months ended September 30, 2010, of
$(28.9) million and of $84.5 million, respectively. Income (loss) before
provision for income tax includes non-cash gain (loss) associated with
the change in mark-to-market of derivative instruments of $(50.6)
million and $14.8 million for the three and nine months ended September
30, 2010, respectively. Excluding non-cash gain (loss) associated with
the change in mark-to-market of derivative instruments, income before
provision for income tax for the three and nine months ended September
30, 2010, would have been $21.7 million and $69.7 million, respectively.

“We are very pleased with our third quarter performance and our ability
to increase full-year guidance for both distributable cash flow and DCF
coverage,” said Frank Semple, Chairman, President and Chief Executive
Officer. “We have been able to deliver strong financial results and
further strengthen our balance sheet while executing our strategic
growth objectives in some of the most exciting resource plays in the
U.S. The combination of high-quality assets, significant organic growth
opportunities, and balance sheet strength puts MarkWest in a very good
position to deliver long-term, top-quartile total returns for our
unitholders.”

THIRD QUARTER 2010 HIGHLIGHTS

Capital Markets

In July 2010, the Partnership executed a $705 million senior secured
revolving credit facility that matures in July 2015. The new credit
facility provides additional financial flexibility, lowers the
Partnership’s borrowing costs, and maintains key financial covenants
substantially unchanged from the previous $435.6 million credit
facility.

Subsequent to the end of the third quarter, the Partnership completed
a public offering of $500 million of 6.75% senior unsecured notes due
2020. The Partnership used the net proceeds from the offering to
complete a cash tender offer for approximately 94 percent of the
outstanding $375 million aggregate principal amount of its 6.875%
senior notes due 2014, and to repay borrowings under its revolving
credit facility and provide working capital for general Partnership
purposes.

Business Development

Liberty – In September 2010, MarkWest Liberty and NiSource Midstream
Services announced the commencement of operations of jointly developed
natural gas gathering, processing, and transmission projects in
Majorsville, West Virginia. The gathering and processing facilities
are fully contracted and will serve various producers, including
affiliates of Chesapeake Energy Corporation, Chief Oil & Gas, CONSOL
Energy/CNX Gas, Range Resources, and Statoil.

MarkWest Liberty’s role in the joint development of the Majorsville
complex is to provide natural gas processing and natural gas liquids
(NGL) transportation, fractionation, storage, and marketing. In that
capacity, MarkWest Liberty commenced operations in September 2010 of a
120 million cubic feet per day (MMcf/d) cryogenic natural gas processing
plant at the Majorsville complex and a 35-mile NGL pipeline that
connects the Majorsville complex to MarkWest Liberty’s midstream complex
in Houston, Pennsylvania, where NGLs are fractionated, transported,
stored, and marketed into high-value markets in the northeastern United
States. In 2011, MarkWest Liberty plans to expand its cryogenic
processing capacity at the Majorsville complex to 270 MMcf/d. In
addition, MarkWest Liberty is constructing fractionation capacity of
60,000 barrels per day at its Houston complex to accommodate the
significant increase in NGL production resulting from processing
expansions currently underway at its Houston and Majorsville locations.

Financial Results

Balance Sheet

At September 30, 2010, the Partnership had $62.3 million of cash and
cash equivalents in wholly owned subsidiaries and $581.8 million
available for borrowing under its $705 million revolving credit
facility after consideration of $21.4 million of outstanding letters
of credit.

Operating Results

Operating income before items not allocated to segments for the three
months ended September 30, 2010, was $106.6 million compared to
segment operating income of $83.4 million in the same period in 2009.
This increase is primarily attributable to higher commodity prices
compared to the prior year quarter, an increase in throughput volumes
and NGL sales in certain business units, and a larger contribution
from the Liberty segment.

Operating income before items not allocated to segments does not
include realized gain (loss) on commodity derivative instruments.
Realized losses on commodity derivative instruments were $(5.7)
million in the third quarter of 2010 compared to realized losses on
commodity derivative instruments of $(6.0) million in the third
quarter of 2009.

Growth Capital Expenditures

For the three months and nine months ended September 30, 2010, the
Partnership’s portion of growth capital expenditures was $63.3 million
and $209.2 million, respectively.

2010 DCF AND GROWTH CAPITAL FORECAST

The Partnership increased its 2010 DCF forecast to a range of $225
million to $235 million. The midpoint of this range provides for
approximately 125 percent coverage of the Partnership’s full-year
distribution based on current quarterly distributions and common units
outstanding.

The Partnership’s portion of growth capital expenditures for 2010 are
forecasted at approximately $300 million and maintenance capital for
2010 is forecasted at approximately $10 million.

2011 DCF AND GROWTH CAPITAL FORECAST

For 2011, the Partnership forecasts DCF in a range of $240 million to
$280 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 140 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 are
forecasted in a range of $300 million to $350 million and maintenance
capital for 2011 is currently forecasted in a range of $10 million to
$15 million.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Tuesday,
November 9, 2010, at 4:00 p.m. Eastern Time to review its third quarter
2010 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 800-294-5087 (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 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, 2009, and our
Quarterly Report on Form 10-Q for the quarter ended September 30, 2010.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

 
2010
 

 
2009
 

 
2010
 

 
2009
 

Revenue:

Revenue

$

292,370

$

207,933

$

884,933

$

576,300

Derivative (loss) gain

(36,959

)

9,758

2,707

(65,173

)

Total revenue

255,411

217,691

887,640

511,127

Operating expenses:

Purchased product costs

136,700

91,086

409,119

274,052

Derivative loss related to purchased product costs

19,996

7,816

24,993

39,954

Facility expenses

37,934

30,165

113,266

93,945

Derivative (gain) loss related to facility expenses

(564

)

1,347

(436

)

122

Selling, general and administrative expenses

17,137

15,477

55,064

46,265

Depreciation

31,362

25,264

89,367

69,621

Amortization of intangible assets

10,193

10,193

30,579

30,638

Loss on disposal of property, plant and equipment

1,937

633

2,116

1,432

Accretion of asset retirement obligations

70

56

282

147

Impairment of long-lived assets

-

-

-

5,855

Total operating expenses

254,765

182,037

724,350

562,031

Income (loss) from operations

646

35,654

163,290

(50,904

)

Other income (expense):

Earnings from unconsolidated affiliates

-

169

1,517

1,260

Interest income

422

100

1,185

201

Interest expense

(26,433

)

(23,440

)

(75,970

)

(63,964

)

Amortization of deferred financing costs and discount (a component
of interestexpense)

(3,625

)

(3,091

)

(8,517

)

(6,528

)

Derivative gain related to interest expense

-

2,265

1,871

2,265

Miscellaneous income, net

76

825

1,129

2,546

(Loss) income before provision for income tax

(28,914

)

12,482

84,505

(115,124

)

Provision for income tax (benefit) expense:

Current

3,533

(46

)

10,254

6,530

Deferred

(13,771

)

624

(45

)

(34,693

)

Total provision for income tax

(10,238

)

578

10,209

(28,163

)

Net (loss) income

(18,676

)

11,904

74,296

(86,961

)

Net income attributable to non-controlling interest

(8,475

)

(3,624

)

(19,720

)

(1,914

)

Net (loss) income attributable to the Partnership

$

(27,151

)

$

8,280

$

54,576

$

(88,875

)

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

Basic

$

(0.39

)

$

0.13

$

0.77

$

(1.52

)

Diluted

$

(0.39

)

$

0.13

$

0.77

$

(1.52

)

Weighted average number of outstanding common units:

Basic

71,438

63,026

69,685

59,168

Diluted

71,438

63,026

69,831

59,168

 
Cash Flow Data

Net cash flow provided by (used in):

Operating activities

$

66,602

$

33,018

$

197,238

$

147,865

Investing activities

$

(120,806

)

$

(78,890

)

$

(373,649

)

$

(404,687

)

Financing activities

$

17,828

$

54,723

$

177,154

$

318,807

 
Other Financial Data

Distributable cash flow

$

54,694

$

40,343

$

171,942

$

129,196

Adjusted EBITDA

$

83,737

$

60,470

$

244,882

$

202,250

 
Balance Sheet Data
September 30, 2010

December 31, 2009

Working capital

$

43,324

$

13,536

Total assets

3,294,318

3,014,737

Total debt

1,216,194

1,170,072

Total equity

1,612,784

1,379,393

 
MarkWest Energy Partners, L.P.Operating Statistics
 

 
Three months ended September 30,
 

 
Nine months ended September 30,

2010
 
2009

2010
 
2009Southwest

East Texas

Gathering systems throughput (Mcf/d)

433,000

455,100

433,600

456,700

NGL product sales (gallons)

60,204,100

66,996,400

186,287,500

180,059,000

 
Oklahoma

Foss Lake gathering system throughput (Mcf/d)

70,200

82,200

71,700

89,300

Stiles Ranch gathering system throughput (Mcf/d)

105,900

87,800

109,800

90,700

Grimes gathering system throughput (Mcf/d)

7,500

9,400

7,800

10,100

Arapaho NGL product sales (gallons)

33,822,300

33,723,900

93,359,400

92,854,000

Southeast Oklahoma gathering system throughput (Mcf/d)

535,800

389,100

524,100

403,700

Arkoma Connector Pipeline throughput (Mcf/d) (1)

396,800

229,000

378,900

229,000

 
Other Southwest

Appleby gathering system throughput (Mcf/d)

29,700

44,200

31,900

50,200

Other gathering systems throughput (Mcf/d) (2)

7,300

10,500

8,300

10,700

 
Northeast

Appalachia (3)

Natural gas processed (Mcf/d)

190,300

197,200

194,400

197,700

Keep-whole sales (gallons)

28,741,100

26,668,300

105,328,500

104,381,200

Percent-of-proceeds sales (gallons)

30,763,000

23,858,400

87,886,700

69,922,200

Total NGL product sales (gallons) (4)

59,504,100

50,526,700

193,215,200

174,303,400

 
Michigan

Crude oil transported for a fee (Bbl/d)

12,100

12,100

12,400

12,400

 
Liberty

Gathering system throughput (Mcf/d)

153,300

56,100

127,700

44,500

NGL product sales (gallons)

32,379,600

10,558,900

77,372,300

18,995,200

 
Gulf Coast

Javelina

Refinery off-gas processed (Mcf/d)

123,000

127,800

118,400

119,000

Liquids fractionated (Bbl/d)

23,100

24,500

22,800

23,200

(1)

We began commercial operation of the Arkoma Connector Pipeline in
mid-July 2009. The volume reported for 2009 is the average daily
rate for thedays of operation.

(2)

Excludes lateral pipelines where revenue is not based on throughput.

(3)

Includes throughput from the Kenova, Cobb, and Boldman processing
plants.

(4)

Represents sales at the Siloam NGL fractionation plant. The total
sales exclude 16,651,700 gallons and 6,602,400 gallons sold by the
Northeast onbehalf of Liberty for the three months ended
September 30, 2010 and 2009, respectively, and 39,957,600 gallons
and 13,122,500 gallons sold for thenine months ended
September 30, 2010 and 2009, respectively.

 
MarkWest Energy Partners, L.P.Operating Income before Items not Allocated to Segments and
Reconciliation to GAAP Financial Measure(unaudited, in thousands)

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, 2009

Southwest

Northeast

Liberty

Gulf Coast

Total
Revenue

$

123,792

$

55,554

$

12,790

$

15,797

$

207,933

Operating expenses:

Purchased product costs

53,425

34,506

3,155

-

91,086

Facility expenses

17,893

4,832

3,435

3,869

30,029

Total operating expenses before items not allocated to segments

71,318

39,338

6,590

3,869

121,115

Portion of operating income attributable to non-controlling interests

980

-

2,470

-

3,450

Operating income before items not allocated to segments

$

51,494

$

16,216

$

3,730

$

11,928

$

83,368

Three months ended September 30,

 
2010
 

 
2009
 

Operating income before items not allocated to segments

$

106,612

$

83,368

Portion of operating income attributable to non-controlling interests

8,678

3,450

Derivative (loss) gain not allocated to segments

(56,391

)

595

Compensation expense included in facility expenses not allocated tosegments

(404

)

(243

)

Facility expenses adjustments

2,850

107

Selling, general and administrative expenses

(17,137

)

(15,477

)

Depreciation

(31,362

)

(25,264

)

Amortization of intangible assets

(10,193

)

(10,193

)

Loss on disposal of property, plant and equipment

(1,937

)

(633

)

Accretion of asset retirement obligations

(70

)

(56

)

Income from operations

646

35,654

Other income (expense):

Earnings from unconsolidated affiliates

-

169

Interest income

422

100

Interest expense

(26,433

)

(23,440

)

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

(3,625

)

(3,091

)

Derivative gain related to interest expense

-

2,265

Miscellaneous income, net

76

825

(Loss) income before provision for income tax

$

(28,914

)

$

12,482

MarkWest Energy Partners, L.P.Operating Income before Items not Allocated to Segments and
Reconciliation to GAAP Financial Measure(unaudited, in thousands)

 
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, 2009

Southwest

Northeast

Liberty

Gulf Coast

Total
Revenue

$ 339,967

$ 165,765

$ 29,510

$ 41,058

$ 576,300

Operating expenses:

Purchased product costs

150,456

117,540

6,056

-

274,052

Facility expenses

55,703

14,796

10,557

12,303

93,359

Total operating expenses before items not allocated to segments

206,159

132,336

16,613

12,303

367,411

Portion of operating income attributable to non-controlling interests

1,007

-

4,113

-

5,120

Operating income before items not allocated to segments

$ 132,801

$ 33,429

$ 8,784

$ 28,755

$ 203,769

 
Nine months ended September 30,
 

2010
 
2009

Operating income before items not allocated to segments

$

337,141

$

203,769

Portion of operating income attributable to non-controlling interests

20,579

5,120

Derivative loss not allocated to segments

(21,850

)

(105,249

)

Compensation expense included in facility expenses not allocated tosegments

(1,412

)

(801

)

Facility expenses adjustments

6,240

215

Selling, general and administrative expenses

(55,064

)

(46,265

)

Depreciation

(89,367

)

(69,621

)

Amortization of intangible assets

(30,579

)

(30,638

)

Loss on disposal of property, plant and equipment

(2,116

)

(1,432

)

Accretion of asset retirement obligations

(282

)

(147

)

Impairment of long-lived assets

-

(5,855

)

Income (loss) from operations

163,290

(50,904

)

Other income (expense):

Earnings from unconsolidated affiliates

1,517

1,260

Interest income

1,185

201

Interest expense

(75,970

)

(63,964

)

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

(8,517

)

(6,528

)

Derivative gain related to interest expense

1,871

2,265

Miscellaneous income, net

1,129

2,546

Income (loss) before provision for income tax

$

84,505

$

(115,124

)

MarkWest Energy Partners, L.P.Reconciliation of GAAP Financial Measures to Non-GAAP Financial
MeasuresDistributable Cash Flow(unaudited, in thousands)
 

Three months ended September 30,
 

Nine months ended September 30,

 
2010
 

 
2009
 

 
2010
 

 
2009
 

Net (loss) income

$

(18,676

)

$

11,904

$

74,296

$

(86,961

)

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

43,640

36,224

122,578

107,927

Amortization of deferred financing costs

3,625

3,091

8,517

6,528

Non-cash earnings from unconsolidated affiliates

-

(169

)

(1,517

)

(1,260

)

Distributions from (contributions to) unconsolidated affiliates

1,353

(1,451

)

2,508

(6,435

)

Starfish partial insurance settlement

-

3,293

-

3,293

Non-cash compensation expense

1,447

723

6,456

3,342

Non-cash derivative activity

50,610

(7,667

)

(14,782

)

147,240

Provision for income tax – deferred

(13,771

)

624

(45

)

(34,693

)

Cash adjustment for non-controlling interest of consolidated
subsidiaries

(8,274

)

(3,230

)

(19,317

)

(4,466

)

Other

(1,259

)

(695

)

561

(24

)

Maintenance capital expenditures

(4,001

)

(2,304

)

(7,313

)

(5,295

)

Distributable cash flow

$

54,694

$

40,343

$

171,942

$

129,196

Maintenance capital expenditures

$

4,001

$

2,304

$

7,313

$

5,295

Growth capital expenditures and equity investments

116,912

66,861

366,860

389,642

Total capital expenditures and equity investments

$

120,913

$

69,165

$

374,173

$

394,937

Distributable cash flow

$

54,694

$

40,343

$

171,942

$

129,196

Maintenance capital expenditures

4,001

2,304

7,313

5,295

Changes in receivables and other assets

(19,966

)

(20,108

)

(32,979

)

(15,087

)

Changes in accounts payable, accrued liabilities and other long-term
liabilities

16,118

10,159

24,335

17,893

Derivative instrument premium payments, net of amortization

492

1,517

1,586

4,151

Contributions to unconsolidated affiliates

-

1,451

-

6,435

Cash adjustment for non-controlling interest of consolidated
subsidiaries

8,274

3,230

19,317

4,466

Starfish partial insurance settlement

-

(3,293

)

-

(3,293

)

Other

2,989

(2,585

)

5,724

(1,191

)

Net cash provided by operating activities

$

66,602

$

33,018

$

197,238

$

147,865

 
MarkWest Energy Partners, L.P.Reconciliation of GAAP Financial Measures to Non-GAAP Financial
MeasuresAdjusted EBITDA(unaudited, in thousands)
 

 
Three months ended September 30,
 
Nine months ended September 30,

2010
 
2009
2010
 
2009

Net (loss) income

$

(18,676

)

$

11,904

$

74,296

$

(86,961

)

Non-cash compensation expense

1,447

723

6,456

3,342

Non-cash derivative activity

50,610

(7,667

)

(13,980

)

147,240

Interest expense (1)

27,802

26,531

77,777

70,492

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

43,640

36,224

122,578

107,927

Provision for income tax

(10,238

)

578

10,209

(28,163

)

Adjustment for cash flow from unconsolidated affiliates

1,450

(169

)

1,089

(282

)

Adjustment related to non-wholly owned subsidiaries

(11,866

)

(7,654

)

(32,631

)

(11,345

)

Other

(432

)

-

(912

)

-

Adjusted EBITDA

$

83,737

$

60,470

$

244,882

$

202,250

(1) 2010 includes derivative activity related to interest expense
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
hedge 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 at the noted crude oil
prices. 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 historical average NGL correlation to crude over the past three
years.

b. One standard deviation above the historical average NGL correlation
to crude over the past three years.

c. One standard deviation below the historical average NGL correlation
to crude over the past three years.

The analysis further assumes derivative instruments outstanding as of
November 2, 2010, and production volumes estimated through December 31,
2011.

The range of stated hypothetical changes in commodity prices considers
current and historic market performance. During the past 10 years, the
annual average NGL correlation has ranged between one standard deviation
below the historical average and one standard deviation above the
historical average.

 
Crude Oil to Gas Ratio
Crude Oil Price
 
NGL Correlation
 

24:1

22:1

20:1

18:1

16:1

One standard deviation above historical average

$

362

$

359

$

356

$

352

$

347

$100

Historical average

$

303

$

300

$

297

$

293

$

288

One standard deviation below historical average

$

243

$

240

$

237

$

233

$

229

One standard deviation above historical average

$

339

$

336

$

333

$

330

$

326

$90

Historical average

$

285

$

283

$

280

$

277

$

272

One standard deviation below historical average

$

231

$

229

$

226

$

222

$

219

One standard deviation above historical average

$

313

$

311

$

308

$

305

$

302

$80

Historical average

$

265

$

263

$

261

$

257

$

254

One standard deviation below historical average

$

217

$

214

$

212

$

209

$

206

One standard deviation above historical average

$

292

$

290

$

288

$

286

$

282

$70

Historical average

$

250

$

248

$

246

$

243

$

240

One standard deviation below historical average

$

207

$

205

$

203

$

200

$

198

One standard deviation above historical average

$

273

$

271

$

269

$

267

$

264

$60

Historical average

$

236

$

234

$

232

$

230

$

227

One standard deviation below historical average

$

198

$

196

$

195

$

192

$

190

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.”