MarkWest Energy Partners, L.P. (NYSE: MWE) (the Partnership) today
reported cash available for distribution to common unitholders, or
distributable cash flow (DCF), of $40.3 million for the three months
ended September 30, 2009, and $129.2 million for the nine months ended
September 30, 2009. DCF for the three months and nine months ended
September 30, 2009, represents 95 percent and 110 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) attributable to the Partnership, the most directly comparable
GAAP financial measure, is provided within the financial tables of this
press release.

The Partnership reported Adjusted EBITDA of $60.5 million for the three
months ended September 30, 2009, and $202.3 million for the nine months
ended September 30, 2009. MarkWest believes the presentation of Adjusted
EBITDA is useful to investors because it is commonly used by master
limited partnerships in the midstream natural gas industry to gauge the
performance of ongoing business operations. A reconciliation of Adjusted
EBITDA to net income (loss) attributable to the Partnership, 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, 2009, of $12.5
million and $(115.1) million, respectively. Income (loss) before
provision for income tax includes non-cash costs associated with the
mark-to-market of derivative instruments of $7.7 million and $(147.2)
million for the three and nine months ended September 30, 2009,
respectively.

“Our third quarter financial results keep us firmly on track to achieve
our distributable cash flow objectives for 2009,” said Frank Semple,
Chairman, President and Chief Executive Officer of MarkWest. “I am very
pleased with our ability to strengthen our balance sheet, maintain our
distribution, and continue to deliver on our strategic growth projects
in some of the most exciting resource plays in the U.S.

“During 2009 we have improved our liquidity by approximately $700
million through a combination of capital market transactions, joint
ventures, and the divestiture of the steam methane reformer facility.
This incremental liquidity funds our share of the Partnership’s 2009 and
2010 growth capital projects in the Marcellus, Woodford, Haynesville,
and Granite Wash. These high-quality midstream projects are driving
higher volumes in our core operating areas and will further strengthen
our market presence in and cash flow from these long-term, economic
plays. In 2009 we continued to expand our NGL operations and marketing
presence in Appalachia by adding 140 million cubic feet per day of gas
processing capacity and 9,500 barrels per day of fractionation capacity.
During the second and third quarter we stored approximately 450,000
barrels of propane, which will be sold in the winter months.

“Our decision to raise additional equity capital to pre-fund our growth
capital projects, coupled with our seasonal increase in propane
inventory, impacted our distribution coverage ratio for the third
quarter. However, the midpoint of our revised 2009 full-year
distributable cash flow guidance continues to provide for a coverage
ratio of greater than 1.1 times our current annualized distribution per
unit. Most importantly, we continue to deliver on our key priorities of
providing quality customer service, maintaining a strong balance sheet,
and achieving our long-term distribution growth objectives.”

THIRD QUARTER 2009 HIGHLIGHTS

Business Development

Liberty – In September 2009, MarkWest Liberty announced that it
reached definitive agreements with Chesapeake Appalachia, L.L.C. and
Statoil Natural Gas L.L.C. to process gas at MarkWest Liberty’s new
Majorsville processing plant. The gas produced by Chesapeake and
Statoil will be gathered by Columbia Gas Transmission using its
infrastructure. Columbia will deliver the gas to MarkWest Liberty’s
Majorsville processing plant, which will be located adjacent to
Columbia’s existing Majorsville compressor station. The hydrocarbon
liquids produced at the Majorsville plant will be connected via
pipeline to MarkWest Liberty’s Houston, Pennsylvania processing
complex. MarkWest Liberty plans to install an approximate 37,000
barrel per day fractionation facility at the Houston complex, as well
as transportation, storage, and marketing infrastructure, to sell the
hydrocarbon liquids into high-value markets in the northeastern United
States.

Gulf Coast – In September 2009, MarkWest announced the closing of the
sale of its steam methane reformer (SMR) facility currently being
constructed at its Javelina processing facility in Corpus Christi,
Texas, for proceeds of approximately $73.1 million. Under the terms of
the purchase and sale agreement, Air Products and Chemicals, Inc. will
complete the construction of the SMR, which is expected to be
on-stream in March 2010. In conjunction with the purchase and sale
agreement, the companies executed a long-term supply agreement whereby
Air Products will provide hydrogen and steam to MarkWest. The hydrogen
produced by the SMR facility, together with hydrogen generated by the
Javelina plant, will be sold to MarkWest’s existing refinery customers.

Liberty – Effective November 1, 2009, MarkWest executed an agreement
to amend the MarkWest Liberty Midstream & Resources joint venture.
Under the terms of the amended agreement, M&R will invest an
additional $150 million in 2010. After M&R has contributed the
additional $150 million, MarkWest will contribute the majority of the
future required capital until MarkWest has invested 51 percent of the
joint venture’s total capital. MarkWest and M&R will maintain a 60 /
40 percent respective ownership interest until January 1, 2011, at
which time the ownership percentages will be adjusted to 51 / 49
percent, respectively.

Financial Results

Balance Sheet

At September 30, 2009, the Partnership’s available liquidity was
$417.6 million, comprised of $65.3 million of cash and cash
equivalents and $352.3 million available for borrowing under the
$435.6 million revolving credit facility after consideration of $31.5
million of outstanding letters of credit.

In the third quarter of 2009, the Partnership completed a public
equity offering of approximately 6.0 million common units and used the
net proceeds from the offering of approximately $121.0 million to
repay borrowings under its revolving credit facility and to fund a
portion of its 2009 growth capital program.

In the third quarter of 2009, the Partnership received the second and
final payment of $31.25 million from ArcLight in satisfaction of
ArcLight’s obligation related to the acquisition of a 50 percent
equity interest in the Arkoma Connector Pipeline. In addition, the
Partnership received approximately $73.1 million related to the
divestiture of the SMR described above.

Operating Results

Segment operating income for the three months ended September 30,
2009, was $83.4 million, a decrease of $20.7 million when compared to
segment operating income of $104.1 million in the same period in 2008.
This decrease is primarily attributable to significantly lower
commodity prices compared to the prior year quarter, which was offset,
in part, by higher volumes in the Southwest, Northeast, and Liberty
segments and the benefit of processing capacity expansions and
upgrades in the Southwest and Northeast segments that were completed
in 2008.

Segment operating income does not include realized gains or losses on
derivative instruments. Realized losses on derivative instruments were
$6.0 million in the third quarter of 2009 compared to realized losses
on derivative instruments of $14.8 million in the third quarter of
2008.

Growth Capital Expenditures

For the three months and nine months ended September 30, 2009,
combined growth capital expenditures and equity investments were $66.9
million and $389.6 million, respectively. Growth capital expenditures
for the nine months ended September 30, 2009, were funded, in part,
through net proceeds of approximately $265 million related to capital
contributions from the Partnership’s existing joint venture partners
and proceeds from the divestiture of the SMR facility.

2009 DCF AND GROWTH CAPITAL FORECAST

For 2009, the Partnership forecasts DCF in a range of $170 million to
$180 million. This range provides for approximately 106 percent to 113
percent coverage of the Partnership’s full-year distribution based on
current quarterly distributions and common units outstanding.

The Partnership’s 2009 growth capital expenditures are forecasted at
approximately $465 million, of which MarkWest anticipates approximately
$310 million will be funded through a combination of capital
contributions from the Partnership’s existing joint venture partners and
proceeds from the divestiture of the SMR facility. As a result,
MarkWest’s share of growth capital expenditures for 2009 will be
approximately $155 million. Maintenance capital for 2009 is forecasted
in a range of $5 million to $10 million.

2010 DCF AND GROWTH CAPITAL FORECAST

For 2010, the Partnership forecasts DCF in a range of $170 million to
$210 million based on current forward price estimates for crude oil and
natural gas and a return to historical price relationships between crude
oil and NGLs in the third quarter of 2010.

Growth capital expenditures for 2010 are forecasted at $480 million, of
which MarkWest anticipates approximately $180 million will be funded
through capital contributions from the Partnership’s existing joint
venture partners. As a result, MarkWest’s share of growth capital
expenditures for 2010 is estimated at approximately $300 million.
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,
November 10, 2009, at 4:00 p.m. Eastern time to review its third quarter
2009 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 888-566-0569 (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, 2008, and our
Quarterly Report on Form 10-Q for the quarter ended September 30, 2009.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
2009
2008
2009
2008
Revenue:

Revenue

$

207,933

$

303,560

$

576,300

$

866,760

Derivative gain (loss)

 

9,758

 

 

262,811

 

 

(65,173

)

 

(96,030

)

Total revenue

 

217,691

 

 

566,371

 

 

511,127

 

 

770,730

 

 

Operating expenses:

Purchased product costs

91,086

171,539

274,052

479,747

Derivative loss (gain) related to purchased product costs

7,816

67,574

39,954

(11,520

)

Facility expenses

30,165

28,213

93,945

75,641

Derivative loss related to facility expenses

1,347

1,748

122

1,395

Selling, general and administrative expenses

15,477

15,331

46,265

54,406

Depreciation

25,264

17,510

69,621

48,533

Amortization of intangible assets

10,193

10,732

30,638

28,050

Other operating expenses

689

38

1,579

106

Impairment of long-lived assets

 

-

 

 

-

 

 

5,855

 

 

5,009

 

Total operating expenses

 

182,037

 

 

312,685

 

 

562,031

 

 

681,367

 

 

Income (loss) from operations

35,654

253,686

(50,904

)

89,363

 

Other income (expense):

Earnings (loss) from unconsolidated affiliates

169

(196

)

1,260

1,932

Interest expense

(23,440

)

(18,928

)

(63,964

)

(47,527

)

Amortization of deferred financing costs and discount (acomponent
of interest expense)

(3,091

)

(1,080

)

(6,528

)

(7,287

)

Derivative gain related to interest expense (1)

2,265

-

2,265

-

Other income, net

 

925

 

 

1,322

 

 

2,747

 

 

4,640

 

Income (loss) before provision for income tax

12,482

234,804

(115,124

)

41,121

 

Provision for income tax (benefit) expense:

Current

(46

)

7,544

6,530

22,876

Deferred

 

624

 

 

40,592

 

 

(34,693

)

 

(6,414

)

Total provision for income tax

 

578

 

 

48,136

 

 

(28,163

)

 

16,462

 

 

Net income (loss)

11,904

186,668

(86,961

)

24,659

 

Net (income) loss attributable to non-controlling interest

(3,624

)

(122

)

(1,914

)

3,271

 

 

 

 

Net income (loss) attributable to the Partnership

$

8,280

 

$

186,546

 

$

(88,875

)

$

27,930

 

 

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

Basic

$

0.13

 

$

3.24

 

$

(1.52

)

$

0.55

 

Diluted

$

0.13

 

 

$

3.24

 

$

(1.52

)

 

$

0.55

 

 

Weighted average number of outstanding common units:

Basic

 

63,026

 

 

56,635

 

 

59,168

 

 

49,123

 

Diluted

 

63,026

 

 

56,635

 

 

59,168

 

 

49,127

 

 
Cash Flow Data

Net cash flow provided by (used in):

Operating activities

$

33,018

$

52,174

$

147,865

$

216,132

Investing activities

(78,890

)

(189,341

)

(404,687

)

(648,794

)

Financing activities

54,723

(36,233

)

318,807

499,880

 
Other Financial Data

Distributable cash flow

$

40,343

$

45,353

$

129,196

$

156,737

Adjusted EBITDA

$

60,470

$

80,089

$

202,250

$

230,291

 
Balance Sheet Data
September 30, 2009
December 31, 2008

Working capital

$

35,649

$

51,237

Total assets

2,896,263

2,673,054

Total debt

1,160,498

1,172,965

Total partners’ capital

1,397,445

1,207,759

 

(1) In July 2009, the Partnership entered into interest rate swap
contracts. The fair value of these contracts is included as an asset
or liability in Fair value of derivative instruments in the
Condensed Consolidated Balance Sheets. Changes in the fair value of
interest rate swaps are recorded in Derivative gain related to
interest expense in the Condensed Consolidated Statements of
Operations.

 

 

 

 

MarkWest Energy Partners, L.P.Operating Statistics
 

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

2009
2008
2009
2008Southwest

East Texas

Gathering systems throughput (Mcf/d)

455,100

441,800

456,700

431,700

NGL product sales (gallons)

66,996,400

49,422,700

180,059,000

140,777,800

 
Oklahoma

Foss Lake gathering system throughput (Mcf/d)

82,200

94,200

89,300

97,800

Stiles Ranch gathering system throughput (Mcf/d) (1)

87,800

N/A

90,700

N/A

Grimes gathering system throughput (Mcf/d)

9,400

13,400

10,100

13,400

Arapaho NGL product sales (gallons)

33,723,900

20,327,200

92,854,000

62,487,300

Southeast Oklahoma gathering systems throughput (Mcf/d)

389,100

282,500

403,700

247,000

Arkoma Connector Pipeline throughput (Mcf/d) (2)

229,000

N/A

229,000

N/A

 
Other Southwest

Appleby gathering system throughput (Mcf/d)

44,200

58,200

50,200

60,700

Other gathering systems throughput (Mcf/d) (3)

10,500

12,000

10,700

11,100

 
Northeast

Appalachia (4)

Natural gas processed (Mcf/d)

197,200

202,900

197,700

201,300

 

Keep-whole sales (gallons)

26,668,300

27,482,700

104,381,200

96,335,000

Percent-of-proceeds sales (gallons)

23,858,400

13,772,300

69,922,200

35,142,100

Total NGL product sales (gallons) (5)

50,526,700

41,255,000

174,303,400

131,477,100

 
Michigan

Crude oil transported for a fee (Bbl/d)

12,100

13,000

12,400

13,500

 
Liberty (6)

Gathering systems throughput (Mcf/d)

56,100

N/A

44,500

N/A

NGL product sales (gallons)

10,558,900

N/A

18,995,200

N/A

 
Gulf Coast

Javelina

Refinery off-gas processed (Mcf/d)

127,800

120,100

119,000

123,400

Liquids fractionated (Bbl/d)

24,500

24,200

23,200

24,700

 

(1) We acquired the Stiles Ranch gathering system in August 2008,
and completed construction of a 60-mile pipeline connecting the
system to our Arapaho processing plants in November 2008.

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

(3) Excludes lateral pipelines where revenue is not based on
throughput.

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

(5) Represents sales at the Siloam fractionator. Total NGL product
sales for 2009 excludes 6.6 million gallons and 13.1 million
gallons for the three months and nine months ended September 30,
2009, respectively, that were sold by the Northeast segment on
behalf of the Liberty segment.

(6) We began natural gas gathering and processing operations in
the Marcellus Shale in October 2008.

 

MarkWest Energy Partners, L.P.Segment Operating Income and Reconciliation to GAAP Financial
Measure(unaudited, in thousands)

 

 

 

 

 

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, 2008:
Southwest
Northeast
Liberty (1)
Gulf Coast
Total
Revenue

$

192,675

$

82,418

$

-

$

28,467

$

303,560

 

Operating expenses:

Purchased product costs

120,208

51,331

-

-

171,539

Facility expenses

 

16,670

 

 

6,172

 

 

-

 

5,085

 

27,927

Operating income before items not allocated to segments

$

55,797

 

$

24,915

 

$

-

$

23,382

$

104,094

 

(1) The Partnership began construction in the Liberty segment in May
2008 and operations commenced in October 2008.

 

Three months ended September 30,

2009
2008

 

Operating income before items not allocated to segments

$

83,368

$

104,094

Portion of operating income attributable to non-controlling interests

3,450

-

Derivative gain not allocated to segments

595

193,489

Compensation expense included in facility expenses not allocated tosegments

(243

)

(286

)

Facility expenses elimination

107

-

Selling, general and administrative expenses

(15,477

)

(15,331

)

Depreciation

(25,264

)

(17,510

)

Amortization of intangible assets

(10,193

)

(10,732

)

Other operating expenses

 

(689

)

 

(38

)

Income from operations

35,654

253,686

Other income (expense):

Earnings (loss) from unconsolidated affiliates

169

(196

)

Interest expense

(23,440

)

(18,928

)

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

(3,091

)

(1,080

)

Derivative gain related to interest expense

2,265

-

Other income, net

 

925

 

 

1,322

 

Income before provision for income tax

$

12,482

 

$

234,804

 

 

 
MarkWest Energy Partners, L.P.Segment Operating Income and Reconciliation to GAAP Financial
Measure(unaudited, in thousands)

 
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, 2008:
Southwest
Northeast
Liberty (1)
Gulf Coast
Total
Revenue

$

536,563

$

251,115

$

-

$

79,082

$

866,760

 

Operating expenses:

Purchased product costs

322,370

157,377

-

-

479,747

Facility expenses

 

45,189

 

 

16,161

 

 

-

 

13,341

 

74,691

Operating income before items not allocated to segments

$

169,004

 

$

77,577

 

$

-

$

65,741

$

312,322

 

(1) The Partnership began construction in the Liberty segment in May
2008 and operations commenced in October 2008.

 

Nine months ended September 30,

2009
2008

 

Operating income before items not allocated to segments

$

203,769

$

312,322

Portion of operating income attributable to non-controlling interests

5,120

-

Derivative loss not allocated to segments

(105,249

)

(85,905

)

Compensation expense included in facility expenses not allocated tosegments

(801

)

(950

)

Facility expenses elimination

215

-

Selling, general and administrative expenses

(46,265

)

(54,406

)

Depreciation

(69,621

)

(48,533

)

Amortization of intangible assets

(30,638

)

(28,050

)

Other operating expenses

(1,579

)

(106

)

Impairment of long-lived assets

 

(5,855

)

 

(5,009

)

(Loss) income from operations

(50,904

)

89,363

Other income (expense):

Earnings from unconsolidated affiliates

1,260

1,932

Interest expense

(63,964

)

(47,527

)

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

(6,528

)

(7,287

)

Derivative gain related to interest expense

2,265

-

Other income, net

 

2,747

 

 

4,640

 

(Loss) income before provision for income tax

$

(115,124

)

$

41,121

 

 
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,

2009
2008
2009
2008

 

Net income (loss) attributable to the Partnership

$

8,280

$

186,546

$

(88,875

)

$

27,930

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

36,224

28,358

107,927

81,932

Amortization of deferred financing costs

3,091

1,080

6,528

7,287

Non-cash (earnings) loss from unconsolidated affiliates

(169

)

196

(1,260

)

(1,932

)

(Contributions to) distributions from unconsolidated affiliates

(1,451

)

1,875

(6,435

)

5,445

Starfish partial insurance settlement

3,293

-

3,293

-

Non-cash compensation expense

723

2,869

3,342

11,430

Non-cash derivative activity

(7,667

)

(208,267

)

147,240

36,802

Provision for income tax – deferred

624

40,592

(34,693

)

(6,414

)

Adjustment for non-controlling interest of consolidated subsidiaries

394

-

(2,552

)

-

Other

(695

)

(5,733

)

(24

)

(1,149

)

Maintenance capital expenditures

 

(2,304

)

 

(2,163

)

 

(5,295

)

 

(4,594

)

Distributable cash flow allocable to common units

$

40,343

 

$

45,353

 

$

129,196

 

$

156,737

 

 

Maintenance capital expenditures

$

2,304

$

2,163

$

5,295

$

4,594

Growth capital expenditures, equity investments, and acquisitions

 

66,861

 

 

187,248

 

 

389,642

 

 

380,625

 

Total capital expenditures, equity investments, and acquisitions

$

69,165

 

$

189,411

 

$

394,937

 

$

385,219

 

 

Distributable cash flow allocable to common units

$

40,343

$

45,353

$

129,196

$

156,737

Maintenance capital expenditures

2,304

2,163

5,295

4,594

Changes in receivables and other assets

(20,108

)

(20,409

)

(15,087

)

(12,039

)

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

10,159

18,366

17,893

78,971

Derivative instrument premium payments, net of amortization

1,517

665

4,151

(13,683

)

Contributions to unconsolidated affiliates

1,451

-

6,435

-

Starfish partial insurance settlement

(3,293

)

-

(3,293

)

-

Other

 

645

 

 

6,036

 

 

3,275

 

 

1,552

 

Net cash provided by operating activities

$

33,018

 

$

52,174

 

$

147,865

 

$

216,132

 

 

 
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,

2009
2008
2009
2008

 

Net income (loss) attributable to the Partnership

$

8,280

$

186,546

$

(88,875

)

$

27,930

Non-cash compensation expense

723

2,869

3,342

11,430

Non-cash derivative activity

(7,667

)

(208,267

)

147,240

36,802

Interest expense

26,531

20,008

70,492

54,814

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

36,224

28,358

107,927

81,932

Provision for income tax

578

48,136

(28,163

)

16,462

Adjustment for cash flow from unconsolidated investments

(169

)

2,439

(282

)

4,314

Adjustment for non-controlling interest of consolidated subsidiaries

 

(4,030

)

 

-

 

 

(9,431

)

 

(3,393

)

Adjusted EBITDA

$

60,470

 

$

80,089

 

$

202,250

 

$

230,291

 

 
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
November 6, 2009, 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 Ratio
Crude Oil Price
 
NGL Correlation
 

 

16:1

 

 

 

14:1

 

 

 

12:1

 

 

 

10:1

 

 

 

8:1

$90

 

One standard deviation above historical average

 

 

$ 272

 

 

 

$ 267

 

 

 

$ 261

 

 

 

$ 253

 

 

 

$ 241

 

Historical average

 

 

$ 228

 

 

 

$ 224

 

 

 

$ 218

 

 

 

$ 209

 

 

 

$ 206

 

One standard deviation below historical average

 

 

$ 185

 

 

 

$ 181

 

 

 

$ 180

 

 

 

$ 174

 

 

 

$ 146

$80

 

One standard deviation above historical average

 

 

$ 252

 

 

 

$ 248

 

 

 

$ 243

 

 

 

$ 236

 

 

 

$ 225

 

Historical average

 

 

$ 214

 

 

 

$ 210

 

 

 

$ 204

 

 

 

$ 197

 

 

 

$ 192

 

One standard deviation below historical average

 

 

$ 175

 

 

 

$ 172

 

 

 

$ 171

 

 

 

$ 164

 

 

 

$ 141

$70

 

One standard deviation above historical average

 

 

$ 236

 

 

 

$ 232

 

 

 

$ 228

 

 

 

$ 222

 

 

 

$ 212

 

Historical average

 

 

$ 202

 

 

 

$ 199

 

 

 

$ 194

 

 

 

$ 187

 

 

 

$ 183

 

One standard deviation below historical average

 

 

$ 169

 

 

 

$ 165

 

 

 

$ 164

 

 

 

$ 158

 

 

 

$ 138

$60

 

One standard deviation above historical average

 

 

$ 220

 

 

 

$ 217

 

 

 

$ 213

 

 

 

$ 207

 

 

 

$ 199

 

Historical average

 

 

$ 191

 

 

 

$ 188

 

 

 

$ 184

 

 

 

$ 178

 

 

 

$ 172

 

One standard deviation below historical average

 

 

$ 162

 

 

 

$ 159

 

 

 

$ 158

 

 

 

$ 151

 

 

 

$ 136

$50

 

One standard deviation above historical average

 

 

$ 205

 

 

 

$ 202

 

 

 

$ 199

 

 

 

$ 194

 

 

 

$ 187

 

Historical average

 

 

$ 181

 

 

 

$ 178

 

 

 

$ 174

 

 

 

$ 169

 

 

 

$ 164

 

One standard deviation below historical average

 

 

$ 156

 

 

 

$ 153

 

 

 

$ 151

 

 

 

$ 146

 

 

 

$ 134

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.”