Freitag, 25. Mai | 21:43 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 $52.9 million for the
three months ended June 30, 2010, and $117.2 million for the six months
ended June 30, 2010. DCF for the three months and six months ended June
30, 2010, represents 116 percent and 128 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 $72.7 million for the three
months ended June 30, 2010, and $161.1 million for the six months ended
June 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 before provision for income tax for the
three months and six months ended June 30, 2010, of $83.0 million and
$113.4 million, respectively. Income before provision for income tax
includes non-cash gains associated with the change in mark-to-market of
derivative instruments of $65.8 million and $65.4 million for the three
and six months ended June 30, 2010, respectively. Excluding non-cash
gains associated with the change in mark-to-market of derivative
instruments, income before provision for income tax for the three and
six months ended June 30, 2010, would have been $17.2 million and $48.0
million, respectively.

“We are very pleased with our mid-year results which reflect the strong
performance of our core assets and the continued ramp up of our Liberty
operations in the Marcellus,” said Frank Semple, Chairman, President and
Chief Executive Officer of MarkWest. “Our year-over-year gathered
volumes have significantly increased despite the relatively depressed
gas price environment during that period and the continued flattening of
the forward price curve. This growth in volumes was driven by the
strength and diversity of our operations in some of the best resource
plays in the United States. Since the end of the first quarter, we have
also significantly improved our liquidity and capital flexibility with a
$142 million equity offering and a $705 million refinancing of our
secured credit facility. The combination of high-quality core assets,
significant organic growth opportunities, balance sheet strength, and
solid distribution coverage puts MarkWest in a very good position to
provide long-term distribution growth and total returns for our
unitholders.”

SECOND QUARTER 2010 HIGHLIGHTS

Capital Markets

On April 6, 2010, the Partnership completed a public equity offering
of approximately 4.9 million common units. The net proceeds from the
offering of approximately $142.3 million will be used to fund a
portion of the Partnership’s 2010 growth capital program and to repay
borrowings under its revolving credit facility.

Moody’s Investors Service and Standard & Poor’s Ratings Services
upgraded the Partnership’s credit ratings to Ba3 and BB-,
respectively. In addition, Fitch Ratings initiated credit rating
coverage on the Partnership with a BB rating. The primary drivers
behind the ratings actions include the Partnership’s successful track
record in executing its growth strategy, improved liquidity and
strengthened balance sheet, increased fee-based operating margin, and
the Partnership’s commitment to issuing equity.

Subsequent to the end of the quarter, the Partnership executed a $700
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. On July 29, 2010, the Partnership
amended the credit facility to include an additional member in the
bank group and to exercise a portion of the accordion feature, thereby
increasing the borrowing capacity to $705 million. As a result of the
revolver refinancing, the Partnership currently has available
liquidity of more than $670 million to fund its strategic projects.

Business Development

On April 15, 2010, MarkWest Liberty announced the expansion of its
Majorsville processing complex in northern West Virginia to
approximately 270 million cubic feet per day (MMcf/d). The natural gas
liquids (NGL) produced at Majorsville will be connected via pipeline
to MarkWest Liberty’s Houston, Pennsylvania NGL fractionation,
storage, and marketing complex. When combined with the processing
facilities currently operating or under construction at the Houston
complex, MarkWest Liberty’s total processing capacity in the Marcellus
will be approximately 625 MMcf/d by the end of 2011. MarkWest Liberty
also announced the expanded design capacity of its fractionation
facility at the Houston complex to 60,000 barrels per day.

On April 26, 2010, MarkWest Liberty and NiSource Gas Transmission &
Storage (NGT&S) announced their intent to jointly develop natural gas
gathering, processing, and transmission projects to support increased
Marcellus production volumes in the northern West Virginia area of the
Appalachian Basin. The joint project would initially include existing
and new pipelines that deliver gas to NGT&S’ Smithfield, West
Virginia, compressor station where MarkWest Liberty would install a
120 MMcf/d cryogenic processing facility by late 2011. MarkWest
Liberty would complement these processing facilities with
fractionation services provided at its Houston, Pennsylvania NGL
fractionation, storage, and marketing complex to take advantage of the
premium regional markets and to maximize the value of the producers’
gas.

On June 1, 2010, MarkWest Liberty and Sunoco Logistics Partners L.P.
(NYSE: SXL) announced their intent to develop a combined pipeline and
marine project for ethane produced in the Marcellus Shale Basin. The
Mariner Project would have initial capacity to transport up to 50,000
barrels per day of ethane to Gulf Coast markets as soon as the second
quarter of 2012 and could be scaled to transport higher volumes to
support additional ethane production in the Marcellus region. MarkWest
Liberty has been working with key producers and petrochemical
consumers since late 2009 and the project has the support of key
producers including Range Resources Corporation (NYSE: RRC) and
Chesapeake Energy Corporation (NYSE:CHK).

Financial Results

Balance Sheet

At June 30, 2010, the Partnership had $54.9 million of cash and cash
equivalents in wholly owned subsidiaries and $353.6 million available
for borrowing under its $435.6 million revolving credit facility.

Operating Results

Operating income before items not allocated to segments for the three
months ended June 30, 2010, was $102.1 million compared to segment
operating income of $70.9 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 $(11.4)
million in the second quarter of 2010 compared to realized gains on
commodity derivative instruments of $4.3 million in the second quarter
of 2009.

Growth Capital Expenditures

For the three months and six months ended June 30, 2010, the
Partnership’s portion of growth capital expenditures was $85.7 million
and $145.1 million, respectively.

2010 DCF AND GROWTH CAPITAL FORECAST

The Partnership updated its 2010 DCF forecast to a range of $210 million
to $230 million based on forecasted operational volumes, derivative
instruments currently outstanding, three-year historical price
correlation between crude oil and NGLs for the remainder of 2010, and a
reasonable range of price estimates for crude oil and natural gas. The
midpoint of this range of forecasted DCF provides for approximately 120
percent coverage of the Partnership’s full-year distribution based on
current quarterly distributions and common units outstanding. A
sensitivity analysis for forecasted 2010 DCF is provided within the
tables of this press release.

Forecasted growth capital expenditures for 2010 are unchanged in a range
of $300 million to $350 million and maintenance capital for 2010 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,
August 10, 2010, at 4:00 p.m. Eastern Time to review its second quarter
2010 financial results. Interested parties can participate in the call
by dialing (888) 469-1569, 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) 944-7880 (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 June 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 June 30,
Six months ended June 30,Statement of Operations Data
2010
2009
2010
2009
Revenue:

Revenue

$

276,948

$

185,000

$

592,563

$

368,367

Derivative gain (loss)

46,902

(83,235

)

39,666

(74,931

)

Total revenue

323,850

101,765

632,229

293,436

Operating expenses:

Purchased product costs

128,123

80,652

272,419

182,966

Derivative (gain) loss related to purchased product costs

(8,392

)

2,625

4,997

32,138

Facility expenses

37,427

32,336

75,332

63,780

Derivative loss (gain) related to facility expenses

934

(854

)

128

(1,225

)

Selling, general and administrative expenses

16,419

14,861

37,927

30,788

Depreciation

29,818

23,414

58,005

44,357

Amortization of intangible assets

10,193

10,212

20,386

20,445

Loss on disposal of property, plant and equipment

188

70

179

799

Accretion of asset retirement obligations

69

44

212

91

Impairment of long-lived assets

-

5,855

-

5,855

Total operating expenses

214,779

169,215

469,585

379,994

Income (loss) from operations

109,071

(67,450

)

162,644

(86,558

)

Other income (expense):

Earnings from unconsolidated affiliates

1,585

1,196

1,517

1,091

Interest income

377

60

763

101

Interest expense

(25,755

)

(22,742

)

(49,537

)

(40,524

)

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

(2,280

)

(2,046

)

(4,892

)

(3,437

)

Derivative gain related to interest expense

-

-

1,871

-

Miscellaneous (expense) income, net

(9

)

2,383

1,053

1,721

Income (loss) before provision for income tax

82,989

(88,599

)

113,419

(127,606

)

Provision for income tax expense (benefit):

Current

923

323

6,721

6,576

Deferred

15,098

(19,726

)

13,726

(35,317

)

Total provision for income tax

16,021

(19,403

)

20,447

(28,741

)

Net income (loss)

66,968

(69,196

)

92,972

(98,865

)

Net (income) loss attributable to non-controlling interest

(6,751

)

1,690

(11,245

)

1,710

Net income (loss) attributable to the Partnership

$

60,217

$

(67,506

)

$

81,727

$

(97,155

)

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

Basic

$

0.84

$

(1.18

)

$

1.18

$

(1.71

)

Diluted

$

0.84

$

(1.18

)

$

1.18

$

(1.71

)

Weighted average number of outstanding common units:

Basic

71,111

57,603

68,795

57,207

Diluted

71,298

57,603

68,889

57,207

 
Cash Flow Data

Net cash flow provided by (used in):

Operating activities

$

16,276

$

23,027

$

130,636

$

114,847

Investing activities

$

(157,813

)

$

(150,746

)

$

(252,843

)

$

(325,797

)

Financing activities

$

171,233

$

152,173

$

159,326

$

264,084

 
Other Financial Data

Distributable cash flow

$

52,905

$

39,938

$

117,248

$

88,853

Adjusted EBITDA

$

72,683

$

61,077

$

161,145

$

141,780

 
Balance Sheet Data
June 30, 2010
December 31, 2009

Working capital

$

95,009

$

13,536

Total assets

3,245,381

3,014,737

Total debt

1,164,045

1,170,072

Total equity

1,649,196

1,379,393

 
MarkWest Energy Partners, L.P.Operating Statistics
 

 
Three months ended June 30,
 
Six months ended June 30,

2010
 
2009
2010
 
2009Southwest

East Texas

Gathering systems throughput (Mcf/d)

438,700

463,900

433,900

457,400

NGL product sales (gallons)

61,887,500

64,692,600

126,083,300

113,062,600

 
Oklahoma

Foss Lake gathering system throughput (Mcf/d)

70,600

93,300

72,400

92,900

Stiles Ranch gathering system throughput (Mcf/d)

106,100

91,000

111,800

92,200

Grimes gathering system throughput (Mcf/d)

8,000

10,000

8,000

10,400

Arapaho NGL product sales (gallons)

30,093,800

31,697,300

59,537,100

59,130,100

Southeast Oklahoma gathering system throughput (Mcf/d)

539,400

403,300

518,100

411,100

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

387,500

N/A

372,700

N/A

 
Other Southwest

Appleby gathering system throughput (Mcf/d)

31,600

49,000

33,100

53,300

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

8,700

10,800

8,800

10,800

 
Northeast

Appalachia (3)

Natural gas processed (Mcf/d)

199,900

197,100

196,400

197,900

Keep-whole sales (gallons)

30,815,000

33,255,100

76,587,400

84,233,000

Percent-of-proceeds sales (gallons)

30,118,700

20,180,700

57,123,600

39,543,800

Total NGL product sales (gallons) (4)

60,933,700

53,435,800

133,711,000

123,776,800

 
Michigan

Crude oil transported for a fee (Bbl/d)

12,100

12,500

12,500

12,600

 
Liberty

Gathering system throughput (Mcf/d)

128,500

43,400

114,800

38,500

NGL product sales (gallons)

23,462,500

7,053,000

44,992,700

8,436,200

 
Gulf Coast

Javelina

Refinery off-gas processed (Mcf/d)

118,800

124,800

116,100

114,600

Liquids fractionated (Bbl/d)

22,800

25,200

22,700

22,600

(1) We began commercial operation of the Arkoma Connector Pipeline
in July 2009.

(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 12,648,600 gallons and 5,136,900 gallons sold
by the Northeast on behalf of Liberty for the three months ended
June 30, 2010 and 2009, respectively, and 23,305,800 gallons and
6,520,000 gallons sold for the six months ended June 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 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, 2009
Southwest
Northeast
Liberty
Gulf Coast
Total
Revenue

$

111,569

$

48,619

$

10,064

$

14,748

$

185,000

Operating expenses:

Purchased product costs

46,497

32,080

2,075

-

80,652

Facility expenses

19,577

4,799

4,583

3,163

32,122

Total operating expenses before items not allocated to segments

66,074

36,879

6,658

3,163

112,774

Portion of operating (loss) income attributable to non-controlling
interests

(1

)

-

1,363

-

1,362

Operating income before items not allocated to segments

$

45,496

$

11,740

$

2,043

$

11,585

$

70,864

Three months ended June 30,

2010
2009

Operating income before items not allocated to segments

$

102,069

$

70,864

Portion of operating income attributable to non-controlling interests

6,764

1,362

Derivative gain (loss) not allocated to segments

54,360

(85,006

)

Compensation expense included in facility expenses not allocated to
segments

(286

)

(214

)

Facility expenses adjustment

2,851

-

Selling, general and administrative expenses

(16,419

)

(14,861

)

Depreciation

(29,818

)

(23,414

)

Amortization of intangible assets

(10,193

)

(10,212

)

Loss on disposal of property, plant and equipment

(188

)

(70

)

Accretion of asset retirement obligations

(69

)

(44

)

Impairment of long-lived assets

-

(5,855

)

Income (loss) from operations

109,071

(67,450

)

Other income (expense):

Earnings from unconsolidated affiliates

1,585

1,196

Interest income

377

60

Interest expense

(25,755

)

(22,742

)

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

(2,280

)

(2,046

)

Miscellaneous (expense) income, net

(9

)

2,383

Income (loss) before provision for income tax

$

82,989

$

(88,599

)

 
MarkWest Energy Partners, L.P.Operating Income before Items not Allocated to Segments and
Reconciliation to GAAP Financial Measure(unaudited, in thousands)
 
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, 2009
Southwest
Northeast
Liberty
Gulf Coast
Total
Revenue

$

216,175

$

110,211

$

16,720

$

25,261

$

368,367

Operating expenses:

Purchased product costs

97,031

83,034

2,901

-

182,966

Facility expenses

37,702

9,964

7,122

8,434

63,222

Total operating expenses before items not allocated to segments

134,733

92,998

10,023

8,434

246,188

Portion of operating income attributable to non-controlling interests

27

-

1,643

-

1,670

Operating income before items not allocated to segments

$

81,415

$

17,213

$

5,054

$

16,827

$

120,509

Six months ended June 30,

2010
2009

Operating income before items not allocated to segments

$

230,529

$

120,509

Portion of operating income attributable to non-controlling interests

11,901

1,670

Derivative gain (loss) not allocated to segments

34,541

(105,844

)

Compensation expense included in facility expenses not allocated to
segments

(1,008

)

(558

)

Facility expenses adjustment

3,390

-

Selling, general and administrative expenses

(37,927

)

(30,788

)

Depreciation

(58,005

)

(44,357

)

Amortization of intangible assets

(20,386

)

(20,445

)

Loss on disposal of property, plant and equipment

(179

)

(799

)

Accretion of asset retirement obligations

(212

)

(91

)

Impairment of long-lived assets

-

(5,855

)

Income (loss) from operations

162,644

(86,558

)

Other income (expense):

Earnings from unconsolidated affiliates

1,517

1,091

Interest income

763

101

Interest expense

(49,537

)

(40,524

)

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

(4,892

)

(3,437

)

Derivative gain related to interest expense

1,871

-

Miscellaneous income, net

1,053

1,721

Income (loss) before provision for income tax

$

113,419

$

(127,606

)

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

 
Three months ended June 30,
 
Six months ended June 30,

2010
 
2009
2010
 
2009

Net income (loss)

$

66,968

$

(69,196

)

$

92,972

$

(98,865

)

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

40,346

39,673

78,938

71,703

Amortization of deferred financing costs

2,280

2,046

4,892

3,437

Non-cash earnings from unconsolidated affiliates

(1,585

)

(1,196

)

(1,517

)

(1,091

)

Distributions from (contributions to) unconsolidated affiliates

1,155

-

1,155

(4,984

)

Non-cash compensation expense

1,113

745

5,009

2,619

Non-cash derivative activity

(65,786

)

89,205

(65,392

)

154,907

Provision for income tax – deferred

15,098

(19,726

)

13,726

(35,317

)

Cash adjustment for non-controlling interest of consolidated
subsidiaries

(6,442

)

(1,031

)

(11,043

)

(1,236

)

Other

2,234

410

1,820

671

Maintenance capital expenditures

(2,476

)

(992

)

(3,312

)

(2,991

)

Distributable cash flow

$

52,905

$

39,938

$

117,248

$

88,853

Maintenance capital expenditures

$

2,476

$

992

$

3,312

$

2,991

Growth capital expenditures and equity investments

155,462

150,854

249,948

322,781

Total capital expenditures and equity investments

$

157,938

$

151,846

$

253,260

$

325,772

Distributable cash flow

$

52,905

$

39,938

$

117,248

$

88,853

Maintenance capital expenditures

2,476

992

3,312

2,991

Changes in receivables and other assets

(22,326

)

(34,691

)

(13,013

)

5,021

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

(22,372

)

14,025

8,217

7,734

Derivative instrument premium payments, net of amortization

530

1,418

1,094

2,634

Contributions to unconsolidated affiliates

-

-

-

4,984

Cash adjustment for non-controlling interest of consolidated
subsidiaries

6,442

1,031

11,043

1,236

Other

(1,379

)

314

2,735

1,394

Net cash provided by operating activities

$

16,276

$

23,027

$

130,636

$

114,847

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

 
Three months ended June 30,
 
Six months ended June 30,

2010
 
2009
2010
 
2009

Net income (loss)

$

66,968

$

(69,196

)

$

92,972

$

(98,865

)

Non-cash compensation expense

1,113

745

5,009

2,619

Non-cash derivative activity

(65,786

)

89,205

(64,590

)

154,907

Interest expense (1)

25,769

24,788

49,975

43,961

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

40,346

39,673

78,938

71,703

Provision for income tax

16,021

(19,403

)

20,447

(28,741

)

Adjustment for cash flow from unconsolidated affiliates

(429

)

(1,196

)

(361

)

(113

)

Adjustment related to non-wholly owned subsidiaries

(10,897

)

(3,539

)

(20,765

)

(3,691

)

Other

(422

)

-

(480

)

-

Adjusted EBITDA

$

72,683

$

61,077

$

161,145

$

141,780

(1) includes derivative activity related to interest expense and
reclassification of 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 natural gas liquids (NGL) prices to crude oil. The table
below reflects MarkWest’s estimate of the range of DCF for 2010 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
August 2, 2010, and production volumes estimated through December 31,
2010.

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.
Estimated Range of 2010 DCF
 

 
Crude Oil to Gas RatioCrude Oil Price
 
NGL Correlation
 

22:1

20:1

18:1

16:1

14:1

One standard deviation above historical average

$

284

$

283

$

281

$

279

$

276

$100

Historical average

$

257

$

255

$

254

$

252

$

249

One standard deviation below historical average

$

229

$

228

$

226

$

224

$

222

One standard deviation above historical average

$

271

$

270

$

269

$

267

$

264

$90

Historical average

$

247

$

245

$

244

$

242

$

240

One standard deviation below historical average

$

222

$

221

$

219

$

217

$

216

One standard deviation above historical average

$

258

$

257

$

256

$

254

$

252

$80

Historical average

$

236

$

235

$

234

$

232

$

230

One standard deviation below historical average

$

214

$

213

$

212

$

210

$

209

One standard deviation above historical average

$

248

$

247

$

245

$

244

$

242

$70

Historical average

$

228

$

227

$

226

$

225

$

223

One standard deviation below historical average

$

209

$

208

$

207

$

205

$

204

One standard deviation above historical average

$

237

$

236

$

235

$

234

$

232

$60

Historical average

$

220

$

219

$

218

$

217

$

216

One standard deviation below historical average

$

204

$

203

$

202

$

201

$

199

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.”