DENVER--(BUSINESS WIRE)--Nov. 7, 2012--
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 $104.3 million for the
three months ended September 30, 2012, and $304.6 million for the nine
months ended September 30, 2012. Distributable cash flow for the three
months ended September 30, 2012, represents distribution coverage of 109
percent. The third quarter distribution of $95.3 million, or $0.81 per
common unit, will be paid to unitholders on November 14, 2012. The third
quarter 2012 distribution represents an increase of $0.01 per common
unit, or 1.3 percent, over the second quarter 2012 distribution and an
increase of $0.08 per common unit, or 11.0 percent, over the third
quarter 2011 distribution. As a Master Limited Partnership, cash
distributions to common unitholders are largely determined based on DCF.
A reconciliation of DCF to net income, the most directly comparable GAAP
financial measure, is provided within the financial tables of this press
release.
The Partnership reported Adjusted EBITDA for the three and nine months
ended September 30, 2012, of $108.2 million and $371.7 million,
respectively, as compared to $107.0 million and $323.2 million for the
three and nine months ended September 30, 2011. The Partnership 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, the most
directly comparable GAAP financial measure, is provided within the
financial tables of this press release.
The Partnership reported (loss) income before provision for income tax
for the three and nine months ended September 30, 2012, of $(22.2)
million and $230.3 million, respectively. (Loss) income before provision
for income tax includes non-cash (loss) gain associated with the change
in mark-to-market of derivative instruments of $(43.7) million and
$101.8 million for the three and nine months ended September 30, 2012,
respectively. Excluding these items, income before provision for income
tax for the three and nine months ended September 30, 2012, would have
been $21.5 million and $128.5 million, respectively.
“Our organic growth strategy continues to deliver solid financial
results and significant opportunities for future expansion and capital
investment,” said Frank Semple, Chairman, President and Chief Executive
Officer. “MarkWest’s diverse set of assets and focus on delivering high
quality customer service resulted in year over year volume increases of
over 20% and 11% distribution growth. In addition, our ongoing
development in the Marcellus Shale and the Utica Shale continues to
provide critical midstream infrastructure for our producer customers’
drilling programs and provides a significant inventory of future growth
projects.”
BUSINESS HIGHLIGHTS
Business Development
-
Liberty: In July 2012, the Partnership announced a new long-term,
fee-based agreement with XTO Energy (XTO) to transport, fractionate
and market natural gas liquids (NGLs) from their 125 million cubic
feet per day (MMcf/d) processing plant located in Butler County,
Pennsylvania. NGLs will initially be transported by truck from XTO’s
plant to the Houston fractionation and marketing complex in Washington
County, Pennsylvania. By the end of 2013, an extension of the
Partnership’s NGL gathering pipeline into northwest Pennsylvania is
expected to be complete, which will connect the Keystone complex and
XTO facility to the Houston complex.
In September 2012, the
Partnership announced a 10-year agreement to become a firm shipper on
the Mariner East pipeline project (“Mariner East”) subject to final
regulatory approvals. Mariner East is currently designed to transport
ethane and propane sourced at the Partnership’s Houston complex to
Sunoco, Inc’s Marcus Hook facility located near Philadelphia,
Pennsylvania. Once delivered, the ethane-propane mix will be
re-fractionated into purity products for sale to domestic and
international markets.
During the third quarter, the
Partnership continued to transport propane from the Houston
fractionation complex to Marcus Hook for delivery to international
markets. Since the commencement of propane exports in July 2012, the
Partnership has marketed over 900,000 barrels. Total propane volumes
loaded onto ships at Marcus Hook include the Partnership’s volume and
purchased product sourced at Sunoco’s local-area facilities. The
Partnership anticipates the continuation of exports from Marcus Hook
as long as it is economically possible for our producer customers to
capture premium prices that currently exist in the international
markets.
In October 2012, the Partnership commenced
operations of the 200 MMcf/d Sherwood I processing facility and
associated gathering and compression in Doddridge County, West
Virginia. These assets are supported by a long-term, fee-based
agreement with Antero Resources. The initiation of Sherwood operations
represents the first phase of the Partnership’s development of
midstream infrastructure in Doddridge County. The Partnership expects
the Sherwood II facility, a 200 MMcf/d cryogenic processing plant, to
be operational in the second quarter of 2013.
In November
2012, the Partnership announced plans to further expand the processing
capacity at its Mobley complex in Wetzel County, West Virginia by 200
MMcf/d. This expansion is supported by an existing long-term,
fee-based agreement with EQT Corporation and is expected to be
completed in the fourth quarter of 2013.
-
Utica: In November 2012, MarkWest Utica EMG, LLC (MarkWest Utica) a
joint venture between MarkWest and The Energy and Minerals Group,
announced the execution of definitive agreements with Antero Resources
to provide gas processing, fractionation and marketing services in
Noble County, Ohio. Under long-term, fee-based agreements, MarkWest
Utica will initially bring online an interim 45 MMcf/d refrigeration
processing plant at its Seneca processing complex, with an expected
second quarter of 2013 completion date. This interim facility will be
followed by Seneca I, a 200 MMcf/d cryogenic gas processing facility,
which is expected to begin operations by the third quarter of 2013.
The definitive agreements contemplate the construction of additional
facility, Seneca II, a 200 MMcf/d cryogenic processing facility, which
may be installed as soon as the end of 2013. In addition to its Seneca
processing complex, MarkWest Utica will construct an NGL gathering
system to its Cadiz processing complex and then on to the Harrison
County, Ohio fractionation and marketing complex. The Cadiz complex
will include a de-ethanization facility where purity ethane will be
produced and delivered into the ATEX ethane pipeline. The propane and
heavier natural gas liquids will then flow via pipeline to the
Harrison County fractionator for further separation into purity
products. The completion of the NGL gathering system and fractionation
will provide Antero Resources direct market access to the planned
ethane and propane pipeline projects in the northeast.
-
Northeast: In October 2012, the Partnership commenced operations of
its 150 MMcf/d Langley processing plant expansion supporting
producers’ gas development in the Huron/Berea Shale. This expansion
increases the Partnership’s total processing capacity in the Northeast
Segment to 655 MMcf/d and further expands the Partnership’s position
as the largest natural gas processor in the Appalachian Basin.
-
Southwest: In September 2012, Centrahoma Processing, LLC a joint
venture between MarkWest and Cardinal Midstream, LLC in Southeast
Oklahoma agreed to construct a 120 MMcf/d processing plant expansion
in order to support drilling programs in the Woodford Shale. The plant
is expected to be operational in the fourth quarter of 2013.
Capital Markets
-
On August 10, 2012, the Partnership completed a public offering of
$750 million aggregate principal amount of 5.5% senior unsecured notes
due 2023 issued at 99.015% of par. The aggregate net proceeds of
approximately $731 million were used to repay borrowings under the
Partnership’s revolving credit facility, to partially fund the
Partnership’s capital expenditure program and for other general
partnership purposes.
-
On August 17, 2012, the Partnership completed a common unit equity
offering of 6.9 million common units. The net proceeds of approximately
$338 million were used to partially fund the Partnership’s capital
expenditure program and for other general partnership purposes.
FINANCIAL RESULTS
Balance Sheet
-
At September 30, 2012, the Partnership had $411.5 million of cash and
cash equivalents in wholly owned subsidiaries and $1.18 billion
available for borrowing under its $1.2 billion revolving credit
facility after consideration of $21.6 million of outstanding letters
of credit.
Operating Results
-
Operating income before items not allocated to segments for the three
months ended September 30, 2012, was $145.5 million, a decrease of
$2.3 million when compared to segment operating income of $147.8
million over the same period in 2011. This decrease was primarily
attributable to lower commodity prices compared to the prior year
quarter. Processed volumes continued to remain strong, growing over 20
percent when compared to the third quarter of 2011, primarily due to
the Partnership’s Liberty and Southwest segments.
A
reconciliation of operating income before items not allocated to
segments to income (loss) before provision for income tax, the most
directly comparable GAAP financial measure, is provided within the
financial tables of this press release.
-
Operating income before items not allocated to segments does not
include loss on commodity derivative instruments. Realized losses on
commodity derivative instruments were $8.4 million in the third
quarter of 2012 and $15.8 million in the third quarter of 2011.
Capital Expenditures
-
For the three and nine months ended September 30, 2012, the
Partnership’s portion of capital expenditures was $603.7 million and
$1,185.9 million, respectively. These expenditures do not include the
Keystone purchase price of $509.6 million.
2012 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST
For 2012, the Partnership forecasts DCF in a range of $410 million to
$430 million based on its current forecast of operational volumes and
prices for crude oil, natural gas and natural gas liquids; derivative
instruments currently outstanding; and the Keystone acquisition, as
mentioned above. The midpoint of this range results in approximately 117
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 2012 has
increased primarily due to accelerated spending on key expansion
projects in the Marcellus Shale, and is forecasted to be approximately
$1.8 billion. This range excludes the Keystone purchase price of $509.6
million.
2013 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST
For 2013, the Partnership forecasts DCF in a range of $500 million to
$575 million based on its current forecast of operational volumes and
prices for crude oil, natural gas and natural gas liquids; and
derivative instruments currently outstanding. The midpoint of this range
results in approximately 141 percent coverage of the Partnership’s
full-year distribution based on current quarterly distributions and
common units outstanding. A commodity price sensitivity analysis for
forecasted 2013 DCF is provided within the tables of this press release.
The Partnership’s portion of growth capital expenditures for 2013 is
forecasted in a range of $1.4 billion to $1.9 billion.
CONFERENCE CALL
The Partnership will host a conference call and webcast on Thursday,
November 8, 2012, at 12:00 p.m. Eastern Time to review its third quarter
2012 financial results. Interested parties can participate in the call
by dialing (800) 475-0218 (passcode “MarkWest”) approximately ten
minutes prior to the scheduled start time. To access the webcast, please
visit the Investor Relations section of the Partnership’s website at www.markwest.com.
A replay of the conference call will be available on the MarkWest
website or by dialing (866) 495-9346 (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 MarkWest believes that the expectations reflected in the
forward-looking statements are reasonable, MarkWest can give no
assurance that such expectations will prove to be correct. The
forward-looking statements involve risks and uncertainties that affect
operations, financial performance, and other factors as discussed in
filings with the Securities and Exchange Commission (SEC). Among
the factors that could cause results to differ materially are those
risks discussed in the periodic reports filed with the SEC, including
MarkWest’s Annual Report on Form 10-K for the year ended December 31,
2011 and its Quarterly Reports on Form 10-Q for the quarters ended March
31, 2012, June 30, 2012 and September 30, 2012. You are urged to
carefully review and consider the cautionary statements and other
disclosures made in those filings, specifically those under the heading
“Risk Factors.” MarkWest does 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
|
|
2012
|
|
|
2011
|
|
2012
|
|
2011
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
320,137
|
|
|
|
$
|
400,883
|
|
|
$
|
1,029,304
|
|
|
$
|
1,109,632
|
|
|
Derivative (loss) gain
|
|
|
(36,400
|
)
|
|
|
|
106,943
|
|
|
|
50,952
|
|
|
|
61,854
|
|
|
Total revenue
|
|
|
283,737
|
|
|
|
|
507,826
|
|
|
|
1,080,256
|
|
|
|
1,171,486
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
Purchased product costs
|
|
|
119,369
|
|
|
|
|
189,284
|
|
|
|
386,655
|
|
|
|
497,493
|
|
|
Derivative loss (gain) related to purchased product costs
|
|
|
11,643
|
|
|
|
|
(1,274
|
)
|
|
|
(21,136
|
)
|
|
|
17,866
|
|
|
Facility expenses
|
|
|
53,293
|
|
|
|
|
44,236
|
|
|
|
150,671
|
|
|
|
124,358
|
|
|
Derivative loss (gain) related to facility expenses
|
|
|
4,028
|
|
|
|
|
(2,787
|
)
|
|
|
1,136
|
|
|
|
(2,871
|
)
|
|
Selling, general and administrative expenses
|
|
|
21,922
|
|
|
|
|
20,162
|
|
|
|
69,025
|
|
|
|
60,454
|
|
|
Depreciation
|
|
|
48,136
|
|
|
|
|
38,715
|
|
|
|
132,199
|
|
|
|
110,280
|
|
|
Amortization of intangible assets
|
|
|
14,988
|
|
|
|
|
10,985
|
|
|
|
38,280
|
|
|
|
32,632
|
|
|
Loss on disposal of property, plant and equipment
|
|
|
655
|
|
|
|
|
147
|
|
|
|
2,983
|
|
|
|
4,619
|
|
|
Accretion of asset retirement obligations
|
|
|
141
|
|
|
|
|
557
|
|
|
|
540
|
|
|
|
934
|
|
|
Total operating expenses
|
|
|
274,175
|
|
|
|
|
300,025
|
|
|
|
760,353
|
|
|
|
845,765
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
9,562
|
|
|
|
|
207,801
|
|
|
|
319,903
|
|
|
|
325,721
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) from unconsolidated affiliates
|
|
|
246
|
|
|
|
|
(507
|
)
|
|
|
788
|
|
|
|
(1,262
|
)
|
|
Interest income
|
|
|
64
|
|
|
|
|
62
|
|
|
|
295
|
|
|
|
214
|
|
|
Interest expense
|
|
|
(30,621
|
)
|
|
|
|
(26,899
|
)
|
|
|
(86,855
|
)
|
|
|
(83,036
|
)
|
|
Amortization of deferred financing costs and discount (a component
of interest expense)
|
|
|
(1,428
|
)
|
|
|
|
(1,002
|
)
|
|
|
(3,943
|
)
|
|
|
(3,873
|
)
|
|
Loss on redemption of debt
|
|
|
-
|
|
|
|
|
(133
|
)
|
|
|
-
|
|
|
|
(43,461
|
)
|
|
Miscellaneous income (expense), net
|
|
|
1
|
|
|
|
|
(4
|
)
|
|
|
63
|
|
|
|
127
|
|
|
(Loss) Income before provision for income tax
|
|
|
(22,176
|
)
|
|
|
|
179,318
|
|
|
|
230,251
|
|
|
|
194,430
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income tax (benefit) expense:
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
(17,948
|
)
|
|
|
|
3,959
|
|
|
|
2,202
|
|
|
|
8,104
|
|
|
Deferred
|
|
|
10,528
|
|
|
|
|
21,905
|
|
|
|
39,396
|
|
|
|
18,338
|
|
|
Total provision for income tax
|
|
|
(7,420
|
)
|
|
|
|
25,864
|
|
|
|
41,598
|
|
|
|
26,442
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
|
(14,756
|
)
|
|
|
|
153,454
|
|
|
|
188,653
|
|
|
|
167,988
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss (income) attributable to non-controlling interest
|
|
|
416
|
|
|
|
|
(13,142
|
)
|
|
|
(65
|
)
|
|
|
(33,208
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income attributable to the Partnership
|
|
$
|
(14,340
|
)
|
|
|
$
|
140,312
|
|
|
$
|
188,588
|
|
|
$
|
134,780
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income attributable to the Partnership's common
unitholders per common unit:
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.13
|
)
|
|
|
$
|
1.77
|
|
|
$
|
1.77
|
|
|
$
|
1.75
|
|
|
Diluted
|
|
$
|
(0.13
|
)
|
|
|
$
|
1.77
|
|
|
$
|
1.49
|
|
|
$
|
1.75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of outstanding common units:
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
113,994
|
|
|
|
|
78,619
|
|
|
|
105,916
|
|
|
|
76,118
|
|
|
Diluted
|
|
|
113,994
|
|
|
|
|
78,760
|
|
|
|
126,595
|
|
|
|
76,276
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Data
|
|
|
|
|
|
|
|
|
|
|
Net cash flow provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
133,281
|
|
|
|
$
|
124,885
|
|
|
$
|
389,718
|
|
|
$
|
331,249
|
|
|
Investing activities
|
|
$
|
(658,573
|
)
|
|
|
$
|
(125,637
|
)
|
|
$
|
(1,746,071
|
)
|
|
$
|
(587,686
|
)
|
|
Financing activities
|
|
$
|
814,894
|
|
|
|
$
|
64,894
|
|
|
$
|
1,654,401
|
|
|
$
|
348,164
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Financial Data
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow
|
|
$
|
104,289
|
|
|
|
$
|
85,311
|
|
|
$
|
304,649
|
|
|
$
|
244,391
|
|
|
Adjusted EBITDA
|
|
$
|
108,180
|
|
|
|
$
|
107,013
|
|
|
$
|
371,655
|
|
|
$
|
323,204
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data
|
|
September 30, 2012
|
|
|
December 31, 2011
|
|
|
|
|
|
Working capital
|
|
$
|
(17,336
|
)
|
|
|
$
|
4,234
|
|
|
|
|
|
|
Total assets
|
|
|
6,237,143
|
|
|
|
|
4,070,425
|
|
|
|
|
|
|
Total debt
|
|
|
2,522,854
|
|
|
|
|
1,846,062
|
|
|
|
|
|
|
Total equity
|
|
$
|
2,620,940
|
|
|
|
$
|
1,502,067
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MarkWest Energy Partners, L.P.
Operating Statistics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
|
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
Southwest
|
|
|
|
|
|
|
|
|
|
East Texas gathering systems throughput (Mcf/d)
|
|
471,200
|
|
417,400
|
|
440,700
|
|
423,800
|
|
East Texas natural gas processed (Mcf/d)
|
|
270,200
|
|
229,700
|
|
260,400
|
|
226,000
|
|
East Texas NGL sales (gallons, in thousands)
|
|
67,800
|
|
59,000
|
|
199,300
|
|
175,200
|
|
|
|
|
|
|
|
|
|
|
|
Western Oklahoma gathering system throughput (Mcf/d) (1)
|
|
227,900
|
|
241,300
|
|
247,300
|
|
224,400
|
|
Western Oklahoma natural gas processed (Mcf/d)
|
|
209,600
|
|
153,200
|
|
210,800
|
|
156,600
|
|
Western Oklahoma NGL sales (gallons, in thousands)
|
|
50,900
|
|
37,000
|
|
169,900
|
|
111,100
|
|
|
|
|
|
|
|
|
|
|
|
Southeast Oklahoma gathering system throughput (Mcf/d)
|
|
484,400
|
|
512,600
|
|
496,200
|
|
507,500
|
|
Southeast Oklahoma natural gas processed (Mcf/d) (2)
|
|
128,600
|
|
105,400
|
|
116,700
|
|
103,100
|
|
Southeast Oklahoma NGL sales (gallons, in thousands)
|
|
46,700
|
|
30,600
|
|
121,000
|
|
92,100
|
|
Arkoma Connector Pipeline throughput (Mcf/d)
|
|
310,400
|
|
298,600
|
|
323,400
|
|
294,300
|
|
|
|
|
|
|
|
|
|
|
|
Other Southwest gathering system throughput (Mcf/d)
|
|
23,600
|
|
29,900
|
|
25,000
|
|
31,500
|
|
|
|
|
|
|
|
|
|
|
|
Northeast
|
|
|
|
|
|
|
|
|
|
Natural gas processed (Mcf/d) (3)
|
|
318,500
|
|
277,400
|
|
322,800
|
|
300,700
|
|
NGLs fractionated (Bbl/d) (4)
|
|
16,500
|
|
19,300
|
|
16,800
|
|
21,400
|
|
|
|
|
|
|
|
|
|
|
|
Keep-whole sales (gallons, in thousands)
|
|
23,200
|
|
21,700
|
|
96,500
|
|
82,600
|
|
Percent-of-proceeds sales (gallons, in thousands)
|
|
33,700
|
|
31,600
|
|
103,500
|
|
95,600
|
|
Total NGL sales (gallons, in thousands) (5)
|
|
56,900
|
|
53,300
|
|
200,000
|
|
178,200
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil transported for a fee (Bbl/d)
|
|
8,700
|
|
9,900
|
|
9,100
|
|
10,500
|
|
|
|
|
|
|
|
|
|
|
|
Liberty
|
|
|
|
|
|
|
|
|
|
Natural gas processed (Mcf/d)
|
|
479,400
|
|
366,200
|
|
424,300
|
|
306,700
|
|
Gathering system throughput (Mcf/d)
|
|
444,700
|
|
258,300
|
|
373,700
|
|
228,900
|
|
NGLs fractionated (Bbl/d) (6)
|
|
22,300
|
|
12,400
|
|
20,700
|
|
9,300
|
|
NGL sales (gallons, in thousands) (7)
|
|
90,800
|
|
61,100
|
|
264,200
|
|
163,500
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
|
|
|
|
|
|
|
|
Refinery off-gas processed (Mcf/d)
|
|
123,800
|
|
122,000
|
|
120,000
|
|
113,200
|
|
Liquids fractionated (Bbl/d)
|
|
23,800
|
|
23,100
|
|
23,000
|
|
21,400
|
|
NGL sales (gallons excluding hydrogen, in thousands)
|
|
92,100
|
|
89,200
|
|
264,400
|
|
245,500
|
|
(1)
|
|
Includes natural gas gathered in Western Oklahoma and from the
Granite Wash formation in the Texas Panhandle as it is one
integrated area of operations.
|
|
|
|
|
|
(2)
|
|
The natural gas processing in Southeast Oklahoma is outsourced to
Centrahoma, our equity investment, or other third-party processors.
|
|
|
|
|
|
(3)
|
|
Includes throughput from the Kenova, Cobb, Boldman and Langley
processing plants. We acquired the Langley processing plants in
February 2011. The volumes reported for the nine months ended
September 30, 2011 are the average daily rates for the days of
operation.
|
|
|
|
|
|
(4)
|
|
Amount includes zero barrels per day and 4,400 barrels per day
fractionated on behalf of Liberty for the three months ended
September 30, 2012 and 2011, respectively and includes zero barrels
per day and 5,100 barrels per day fractionated on behalf of Liberty
for the nine months ended September 30, 2012 and 2011, respectively.
Beginning in the fourth quarter of 2011, Siloam no longer
fractionates NGLs on behalf of Liberty due to the operation of
Liberty’s fractionation facility that began in September 2011,
except during outages or force majeure events.
|
|
|
|
|
|
(5)
|
|
Represents sales from the Siloam facilities. The total sales exclude
approximately 600,000 gallons and 17,100,000 gallons sold by the
Northeast on behalf of Liberty for the three months ended September
30, 2012 and 2011, respectively and 975,000 gallons and 58,600,000
gallons sold for the nine months ended September 30, 2012 and 2011,
respectively. These volumes are included as part of NGLs sold at
Liberty.
|
|
|
|
|
|
(6)
|
|
Amount includes all NGLs that were produced at the Liberty
processing facilities and fractionated into purity products at our
Liberty fractionation facility.
|
|
|
|
|
|
(7)
|
|
Includes sale of all purity products fractionated at the Liberty
facilities and sale of all unfractionated NGLs. Also includes the
sale of purity products fractionated and sold from the Siloam
facilities on behalf of Liberty.
|
|
|
|
|
MarkWest Energy Partners, L.P.
Reconciliation of GAAP
Financial Measure to Non-GAAP Financial Measure
Operating
Income before Items not Allocated to Segments
(unaudited,
in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, 2012
|
|
Southwest
|
|
Northeast
|
|
Liberty
|
|
Gulf Coast
|
|
Total
|
|
Revenue
|
|
$
|
181,456
|
|
|
$
|
39,987
|
|
|
$
|
78,852
|
|
|
$
|
21,477
|
|
$
|
321,772
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
Purchased product costs
|
|
|
92,112
|
|
|
|
11,054
|
|
|
|
16,203
|
|
|
|
-
|
|
|
119,369
|
|
Facility expenses
|
|
|
20,527
|
|
|
|
6,267
|
|
|
|
20,241
|
|
|
|
8,928
|
|
|
55,963
|
|
Total operating expenses before items not allocated to segments
|
|
|
112,639
|
|
|
|
17,321
|
|
|
|
36,444
|
|
|
|
8,928
|
|
|
175,332
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Portion of operating income attributable to non-controlling interests
|
|
|
1,543
|
|
|
|
-
|
|
|
|
(627
|
)
|
|
|
-
|
|
|
916
|
|
Operating income before items not allocated to segments
|
|
$
|
67,274
|
|
|
$
|
22,666
|
|
|
$
|
43,035
|
|
|
$
|
12,549
|
|
$
|
145,524
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, 2011
|
|
Southwest
|
|
Northeast
|
|
Liberty
|
|
Gulf Coast
|
|
Total
|
|
Revenue
|
|
$
|
241,998
|
|
|
$
|
55,920
|
|
|
$
|
78,586
|
|
|
$
|
26,868
|
|
$
|
403,372
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
Purchased product costs
|
|
|
141,067
|
|
|
|
15,947
|
|
|
|
32,270
|
|
|
|
-
|
|
|
189,284
|
|
Facility expenses
|
|
|
21,043
|
|
|
|
6,879
|
|
|
|
9,108
|
|
|
|
9,798
|
|
|
46,828
|
|
Total operating expenses before items not allocated to segments
|
|
|
162,110
|
|
|
|
22,826
|
|
|
|
41,378
|
|
|
|
9,798
|
|
|
236,112
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Portion of operating income attributable to non-controlling interests
|
|
|
1,227
|
|
|
|
-
|
|
|
|
18,223
|
|
|
|
-
|
|
|
19,450
|
|
Operating income before items not allocated to segments
|
|
$
|
78,661
|
|
|
$
|
33,094
|
|
|
$
|
18,985
|
|
|
$
|
17,070
|
|
$
|
147,810
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
|
|
|
|
|
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income before items not allocated to segments
|
|
$
|
145,524
|
|
|
$
|
147,810
|
|
|
|
|
|
|
|
|
Portion of operating income attributable to non-controlling interests
|
|
|
916
|
|
|
|
19,450
|
|
|
|
|
|
|
|
|
Derivative (loss) gain not allocated to segments
|
|
|
(52,071
|
)
|
|
|
111,004
|
|
|
|
|
|
|
|
|
Revenue deferral adjustment
|
|
|
(1,635
|
)
|
|
|
(2,489
|
)
|
|
|
|
|
|
|
|
Compensation expense included in facility expenses not allocated to
segments
|
|
|
(193
|
)
|
|
|
(263
|
)
|
|
|
|
|
|
|
|
Facility expenses adjustments
|
|
|
2,863
|
|
|
|
2,855
|
|
|
|
|
|
|
|
|
Selling, general and administrative expenses
|
|
|
(21,922
|
)
|
|
|
(20,162
|
)
|
|
|
|
|
|
|
|
Depreciation
|
|
|
(48,136
|
)
|
|
|
(38,715
|
)
|
|
|
|
|
|
|
|
Amortization of intangible assets
|
|
|
(14,988
|
)
|
|
|
(10,985
|
)
|
|
|
|
|
|
|
|
Loss on disposal of property, plant and equipment
|
|
|
(655
|
)
|
|
|
(147
|
)
|
|
|
|
|
|
|
|
Accretion of asset retirement obligations
|
|
|
(141
|
)
|
|
|
(557
|
)
|
|
|
|
|
|
|
|
Income from operations
|
|
|
9,562
|
|
|
|
207,801
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) from unconsolidated affiliate
|
|
|
246
|
|
|
|
(507
|
)
|
|
|
|
|
|
|
|
Interest income
|
|
|
64
|
|
|
|
62
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(30,621
|
)
|
|
|
(26,899
|
)
|
|
|
|
|
|
|
|
Amortization of deferred financing costs and discount (a component
of interest expense)
|
|
|
(1,428
|
)
|
|
|
(1,002
|
)
|
|
|
|
|
|
|
|
Loss on redemption of debt
|
|
|
-
|
|
|
|
(133
|
)
|
|
|
|
|
|
|
|
Miscellaneous income (expense), net
|
|
|
1
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
(Loss) Income before provision for income tax
|
|
$
|
(22,176
|
)
|
|
$
|
179,318
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, 2012
|
|
Southwest
|
|
Northeast
|
|
Liberty
|
|
Gulf Coast
|
|
Total
|
|
Revenue
|
|
$
|
585,343
|
|
|
$
|
168,956
|
|
|
$
|
213,906
|
|
|
$
|
66,703
|
|
$
|
1,034,908
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
Purchased product costs
|
|
|
288,137
|
|
|
|
49,662
|
|
|
|
48,856
|
|
|
|
-
|
|
|
386,655
|
|
Facility expenses
|
|
|
66,553
|
|
|
|
17,577
|
|
|
|
46,135
|
|
|
|
28,173
|
|
|
158,438
|
|
Total operating expenses before items not allocated to segments
|
|
|
354,690
|
|
|
|
67,239
|
|
|
|
94,991
|
|
|
|
28,173
|
|
|
545,093
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Portion of operating income attributable to non-controlling interests
|
|
|
4,579
|
|
|
|
-
|
|
|
|
(740
|
)
|
|
|
-
|
|
|
3,839
|
|
Operating income before items not allocated to segments
|
|
$
|
226,074
|
|
|
$
|
101,717
|
|
|
$
|
119,655
|
|
|
$
|
38,530
|
|
$
|
485,976
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, 2011
|
|
Southwest
|
|
Northeast
|
|
Liberty
|
|
Gulf Coast
|
|
Total
|
|
Revenue
|
|
$
|
679,347
|
|
|
$
|
201,687
|
|
|
$
|
168,142
|
|
|
$
|
73,310
|
|
$
|
1,122,486
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
Purchased product costs
|
|
|
373,251
|
|
|
|
72,527
|
|
|
|
51,715
|
|
|
|
-
|
|
|
497,493
|
|
Facility expenses
|
|
|
62,055
|
|
|
|
19,402
|
|
|
|
22,875
|
|
|
|
27,100
|
|
|
131,432
|
|
Total operating expenses before items not allocated to segments
|
|
|
435,306
|
|
|
|
91,929
|
|
|
|
74,590
|
|
|
|
27,100
|
|
|
628,925
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Portion of operating income attributable to non-controlling interests
|
|
|
3,745
|
|
|
|
-
|
|
|
|
45,782
|
|
|
|
-
|
|
|
49,527
|
|
Operating income before items not allocated to segments
|
|
$
|
240,296
|
|
|
$
|
109,758
|
|
|
$
|
47,770
|
|
|
$
|
46,210
|
|
$
|
444,034
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30,
|
|
|
|
|
|
|
|
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income before items not allocated to segments
|
|
$
|
485,976
|
|
|
$
|
444,034
|
|
|
|
|
|
|
|
|
Portion of operating income attributable to non-controlling interests
|
|
|
3,839
|
|
|
|
49,527
|
|
|
|
|
|
|
|
|
Derivative gain not allocated to segments
|
|
|
70,952
|
|
|
|
46,859
|
|
|
|
|
|
|
|
|
Revenue deferral adjustment
|
|
|
(5,604
|
)
|
|
|
(12,854
|
)
|
|
|
|
|
|
|
|
Compensation expense included in facility expenses not allocated to
segments
|
|
|
(826
|
)
|
|
|
(1,491
|
)
|
|
|
|
|
|
|
|
Facility expenses adjustments
|
|
|
8,593
|
|
|
|
8,565
|
|
|
|
|
|
|
|
|
Selling, general and administrative expenses
|
|
|
(69,025
|
)
|
|
|
(60,454
|
)
|
|
|
|
|
|
|
|
Depreciation
|
|
|
(132,199
|
)
|
|
|
(110,280
|
)
|
|
|
|
|
|
|
|
Amortization of intangible assets
|
|
|
(38,280
|
)
|
|
|
(32,632
|
)
|
|
|
|
|
|
|
|
Loss on disposal of property, plant and equipment
|
|
|
(2,983
|
)
|
|
|
(4,619
|
)
|
|
|
|
|
|
|
|
Accretion of asset retirement obligations
|
|
|
(540
|
)
|
|
|
(934
|
)
|
|
|
|
|
|
|
|
Income from operations
|
|
|
319,903
|
|
|
|
325,721
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) from unconsolidated affiliate
|
|
|
788
|
|
|
|
(1,262
|
)
|
|
|
|
|
|
|
|
Interest income
|
|
|
295
|
|
|
|
214
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(86,855
|
)
|
|
|
(83,036
|
)
|
|
|
|
|
|
|
|
Amortization of deferred financing costs and discount (a component
of interest expense)
|
|
|
(3,943
|
)
|
|
|
(3,873
|
)
|
|
|
|
|
|
|
|
Loss on redemption of debt
|
|
|
-
|
|
|
|
(43,461
|
)
|
|
|
|
|
|
|
|
Miscellaneous income, net
|
|
|
63
|
|
|
|
127
|
|
|
|
|
|
|
|
|
Income before provision for income tax
|
|
$
|
230,251
|
|
|
$
|
194,430
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MarkWest Energy Partners, L.P.
Reconciliation of GAAP
Financial Measure to Non-GAAP Financial Measure
Distributable
Cash Flow
(unaudited, in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
|
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
(14,756
|
)
|
|
$
|
153,454
|
|
|
$
|
188,653
|
|
|
$
|
167,988
|
|
|
Depreciation, amortization, impairment, and other non-cash operating
expenses
|
|
|
63,998
|
|
|
|
50,482
|
|
|
|
174,236
|
|
|
|
148,699
|
|
|
Loss on redemption of debt, net of tax benefit
|
|
|
-
|
|
|
|
119
|
|
|
|
-
|
|
|
|
39,618
|
|
|
Amortization of deferred financing costs and discount
|
|
|
1,428
|
|
|
|
1,002
|
|
|
|
3,943
|
|
|
|
3,873
|
|
|
Non-cash (earnings) loss from unconsolidated affiliate
|
|
|
(246
|
)
|
|
|
507
|
|
|
|
(788
|
)
|
|
|
1,262
|
|
|
Distributions from unconsolidated affiliate
|
|
|
500
|
|
|
|
-
|
|
|
|
2,200
|
|
|
|
300
|
|
|
Non-cash compensation expense
|
|
|
981
|
|
|
|
995
|
|
|
|
6,270
|
|
|
|
3,707
|
|
|
Non-cash derivative activity
|
|
|
43,712
|
|
|
|
(126,802
|
)
|
|
|
(101,815
|
)
|
|
|
(102,681
|
)
|
|
Provision for income tax - deferred
|
|
|
10,528
|
|
|
|
21,905
|
|
|
|
39,396
|
|
|
|
18,338
|
|
|
Cash adjustment for non-controlling interest of consolidated
subsidiaries
|
|
|
(490
|
)
|
|
|
(18,227
|
)
|
|
|
(2,513
|
)
|
|
|
(46,285
|
)
|
|
Revenue deferral adjustment
|
|
|
1,635
|
|
|
|
2,489
|
|
|
|
5,604
|
|
|
|
12,854
|
|
|
Other
|
|
|
1,173
|
|
|
|
1,334
|
|
|
|
3,962
|
|
|
|
4,537
|
|
|
Maintenance capital expenditures, net of joint venture partner
contributions
|
|
|
(4,174
|
)
|
|
|
(1,947
|
)
|
|
|
(14,499
|
)
|
|
|
(7,819
|
)
|
|
Distributable cash flow
|
|
$
|
104,289
|
|
|
$
|
85,311
|
|
|
$
|
304,649
|
|
|
$
|
244,391
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance capital expenditures
|
|
$
|
4,174
|
|
|
$
|
2,179
|
|
|
$
|
14,499
|
|
|
$
|
8,577
|
|
|
Growth capital expenditures
|
|
|
654,489
|
|
|
|
123,631
|
|
|
|
1,226,367
|
|
|
|
351,349
|
|
|
Total capital expenditures
|
|
|
658,663
|
|
|
|
125,810
|
|
|
|
1,240,866
|
|
|
|
359,926
|
|
|
Acquisitions
|
|
|
-
|
|
|
|
-
|
|
|
|
506,797
|
|
|
|
230,728
|
|
|
Total capital expenditures and acquisitions
|
|
|
658,663
|
|
|
|
125,810
|
|
|
|
1,747,663
|
|
|
|
590,654
|
|
|
Joint venture partner contributions
|
|
|
(55,000
|
)
|
|
|
(14,474
|
)
|
|
|
(55,000
|
)
|
|
|
(68,501
|
)
|
|
Total capital expenditures and acquisitions, net
|
|
$
|
603,663
|
|
|
$
|
111,336
|
|
|
$
|
1,692,663
|
|
|
$
|
522,153
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow
|
|
$
|
104,289
|
|
|
$
|
85,311
|
|
|
$
|
304,649
|
|
|
$
|
244,391
|
|
|
Maintenance capital expenditures, net
|
|
|
4,174
|
|
|
|
1,947
|
|
|
|
14,499
|
|
|
|
7,819
|
|
|
Changes in receivables and other assets
|
|
|
(85,436
|
)
|
|
|
(17,856
|
)
|
|
|
26,946
|
|
|
|
(33,255
|
)
|
|
Changes in accounts payable, accrued liabilities and other long-term
liabilities
|
|
|
110,559
|
|
|
|
38,405
|
|
|
|
45,368
|
|
|
|
69,372
|
|
|
Derivative instrument premium payments, net of amortization
|
|
|
-
|
|
|
|
1,137
|
|
|
|
-
|
|
|
|
3,281
|
|
|
Cash adjustment for non-controlling interest of consolidated
subsidiaries
|
|
|
490
|
|
|
|
18,227
|
|
|
|
2,513
|
|
|
|
46,285
|
|
|
Other
|
|
|
(795
|
)
|
|
|
(2,286
|
)
|
|
|
(4,257
|
)
|
|
|
(6,644
|
)
|
|
Net cash provided by operating activities
|
|
$
|
133,281
|
|
|
$
|
124,885
|
|
|
$
|
389,718
|
|
|
$
|
331,249
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MarkWest Energy Partners, L.P.
Reconciliation of GAAP
Financial Measure to Non-GAAP Financial Measure
Adjusted
EBITDA
(unaudited, in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
|
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
(14,756
|
)
|
|
$
|
153,454
|
|
|
$
|
188,653
|
|
|
$
|
167,988
|
|
|
Non-cash compensation expense
|
|
|
981
|
|
|
|
995
|
|
|
|
6,270
|
|
|
|
3,707
|
|
|
Non-cash derivative activity
|
|
|
43,712
|
|
|
|
(126,802
|
)
|
|
|
(101,815
|
)
|
|
|
(102,681
|
)
|
|
Interest expense (1)
|
|
|
29,882
|
|
|
|
25,687
|
|
|
|
84,260
|
|
|
|
80,235
|
|
|
Depreciation, amortization, impairment, and other non-cash operating
expenses
|
|
|
63,998
|
|
|
|
50,482
|
|
|
|
174,236
|
|
|
|
148,699
|
|
|
Loss on redemption of debt
|
|
|
-
|
|
|
|
133
|
|
|
|
-
|
|
|
|
43,461
|
|
|
Provision for income tax
|
|
|
(7,420
|
)
|
|
|
25,864
|
|
|
|
41,598
|
|
|
|
26,442
|
|
|
Adjustment for cash flow from unconsolidated affiliate
|
|
|
254
|
|
|
|
507
|
|
|
|
1,412
|
|
|
|
1,562
|
|
|
Adjustment related to non-guarantor, consolidated subsidiaries (2)
|
|
|
(7,951
|
)
|
|
|
(22,713
|
)
|
|
|
(21,434
|
)
|
|
|
(44,819
|
)
|
|
Other
|
|
|
(520
|
)
|
|
|
(594
|
)
|
|
|
(1,525
|
)
|
|
|
(1,390
|
)
|
|
Adjusted EBITDA
|
|
$
|
108,180
|
|
|
$
|
107,013
|
|
|
$
|
371,655
|
|
|
$
|
323,204
|
|
|
(1)
|
|
Includes amortization of deferred financing costs and discount,
and excludes interest expense related to the Steam Methane
Reformer.
|
|
(2)
|
|
The non-guarantor subsidiaries, in accordance with Credit Facility
covenants, are MarkWest Liberty Midstream & Resources, L.L.C. and
its subsidiaries (Liberty), MarkWest Utica EMG L.L.C., MarkWest
Pioneer, L.L.C., Wirth Gathering Partnership, and Bright Star
Partnership. As of January 1, 2012, Liberty is a wholly owned
subsidiary but remains a non-guarantor in accordance with the
Credit Facility.
|
|
|
|
|
MarkWest Energy Partners, L.P.
Distributable Cash Flow
Sensitivity Analysis
(unaudited, in millions)
MarkWest periodically estimates the effect on DCF resulting from its
commodity risk management program, changes in crude oil and natural gas
prices, and the ratio of NGL prices to crude oil. The table below
reflects MarkWest’s estimate of the range of DCF for 2013 and forecasted
crude oil and natural gas prices for 2013. The analysis assumes various
combinations of crude oil and natural gas prices as well as three
NGL-to-crude oil ratio scenarios, including:
a. NGL-to-crude oil ratio at 60% for 2013.
b. NGL-to-crude oil
ratio at 50% for 2013.
c. NGL-to-crude oil ratio at 40% for 2013.
The analysis further assumes derivative instruments outstanding as of
November 2, 2012, and production volumes estimated through December 31,
2013. The range of stated hypothetical changes in commodity prices
considers current and historic market performance.
|
|
|
|
|
|
|
|
|
Natural Gas Price (Henry Hub)
|
|
Crude Oil Price
(WTI)
|
|
NGL-to-Crude
oil ratio (1)
|
|
$
|
2.50
|
|
|
$
|
3.00
|
|
|
$
|
3.50
|
|
|
$
|
4.00
|
|
|
$
|
4.50
|
|
|
|
60% of WTI
|
|
$
|
699
|
|
|
$
|
694
|
|
|
$
|
689
|
|
|
$
|
683
|
|
|
$
|
678
|
|
$110
|
|
50% of WTI
|
|
$
|
606
|
|
|
$
|
601
|
|
|
$
|
596
|
|
|
$
|
591
|
|
|
$
|
585
|
|
|
|
40% of WTI
|
|
$
|
517
|
|
|
$
|
512
|
|
|
$
|
507
|
|
|
$
|
502
|
|
|
$
|
496
|
|
|
|
60% of WTI
|
|
$
|
668
|
|
|
$
|
662
|
|
|
$
|
657
|
|
|
$
|
652
|
|
|
$
|
647
|
|
$100
|
|
50% of WTI
|
|
$
|
585
|
|
|
$
|
580
|
|
|
$
|
574
|
|
|
$
|
569
|
|
|
$
|
564
|
|
|
|
40% of WTI
|
|
$
|
504
|
|
|
$
|
499
|
|
|
$
|
494
|
|
|
$
|
488
|
|
|
$
|
483
|
|
|
|
60% of WTI
|
|
$
|
634
|
|
|
$
|
628
|
|
|
$
|
623
|
|
|
$
|
618
|
|
|
$
|
613
|
|
$90
|
|
50% of WTI
|
|
$
|
561
|
|
|
$
|
556
|
|
|
$
|
551
|
|
|
$
|
545
|
|
|
$
|
540
|
|
|
|
40% of WTI
|
|
$
|
488
|
|
|
$
|
483
|
|
|
$
|
478
|
|
|
$
|
472
|
|
|
$
|
467
|
|
|
|
60% of WTI
|
|
$
|
611
|
|
|
$
|
605
|
|
|
$
|
600
|
|
|
$
|
595
|
|
|
$
|
590
|
|
$80
|
|
50% of WTI
|
|
$
|
546
|
|
|
$
|
541
|
|
|
$
|
535
|
|
|
$
|
530
|
|
|
$
|
525
|
|
|
|
40% of WTI
|
|
$
|
481
|
|
|
$
|
476
|
|
|
$
|
470
|
|
|
$
|
465
|
|
|
$
|
460
|
|
|
|
60% of WTI
|
|
$
|
592
|
|
|
$
|
587
|
|
|
$
|
582
|
|
|
$
|
577
|
|
|
$
|
572
|
|
$70
|
|
50% of WTI
|
|
$
|
536
|
|
|
$
|
530
|
|
|
$
|
525
|
|
|
$
|
520
|
|
|
$
|
515
|
|
|
|
40% of WTI
|
|
$
|
479
|
|
|
$
|
473
|
|
|
$
|
467
|
|
|
$
|
462
|
|
|
$
|
456
|
|
|
|
(1)
|
|
The composition is based on MarkWest’s average projected barrel of
approximately: Ethane: 35%, Propane: 35%, Iso-Butane: 6%, Normal
Butane: 12%, Natural Gasoline: 12%.
|
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 ratios of NGL-to-crude oil 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 ratio 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
Josh Hallenbeck, 866-858-0482
VP of Finance
& Treasurer
investorrelations@markwest.com
|
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