DENVER--(BUSINESS WIRE)--May. 7, 2012--
MarkWest Energy Partners, LP (NYSE: MWE) (the Partnership) today
reported record quarterly cash available for distribution to common
unitholders, or distributable cash flow (DCF), of $109.2 million for the
three months ended March 31, 2012, compared to $76.1 million for the
three months ended March 31, 2011. DCF for the three months ended March
31, 2012 represents 135 percent coverage of the first quarter
distribution of $81.1 million, or $0.79 per common unit, which will be
paid to unitholders on May 15, 2012. As a Master Limited Partnership
(MLP), 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 record quarterly Adjusted EBITDA of $132.9
million for the three months ended March 31, 2012, compared to $96.2
million for the same period in 2011. The Partnership believes the
presentation of Adjusted EBITDA provides useful information because it
is commonly used by investors in MLPs 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 ended March 31, 2012 of $20.8 million, compared to a loss
of $88.8 million for the same period in 2011. Income (loss) before
provision for income tax includes non-cash losses associated with the
change in fair value of derivative instruments of $48.2 million and
$79.8 million for the three months ended March 31, 2012 and March 31,
2011, respectively, and costs associated with the redemption of debt of
$43.3 million for the three months ended March 31, 2011. Excluding these
items, income (loss) before provision for income tax for the three
months ended March 31, 2012 and 2011 would have been $69.0 million and
$34.3 million, respectively.
“Our record distributable cash flow for the first quarter allowed us to
deliver year-over-year distribution growth of nearly 18 percent while
maintaining a coverage ratio of 1.35 times,” said Frank Semple,
Chairman, President and Chief Executive Officer. “Our strategy of
developing fully integrated midstream services in the liquids rich areas
of the major U.S. shale plays continues to provide significant growth
opportunities. We are in the process of constructing 13 cryogenic
natural gas processing facilities and a world class fractionation
facility to support our producers in the Marcellus, Utica, Huron and the
Haynesville/Cotton Valley. Also, the Keystone acquisition and our NGL
gathering system expansion will further extend our Marcellus midstream
platform into the rich gas corridor of Northwest Pennsylvania. The
quality of our existing core assets and our ongoing expansion projects
support our objective of providing long term sustainable top quartile
returns for our unitholders.”
BUSINESS HIGHLIGHTS
Keystone Midstream Services Acquisition
-
The Partnership announced today that it is acquiring 100% of the
ownership interests of Keystone Midstream Services, LLC (Keystone),
for consideration of $512 million. Keystone is owned by Stonehenge
Energy Resources, LP, and affiliates of Rex Energy Corporation (Rex
Energy), and Sumitomo Corporation (Sumitomo). Keystone’s existing
assets are located in Butler County, Pennsylvania and include two
cryogenic gas processing plants totaling 90 million cubic feet per day
(MMcf/d) of capacity, a gas gathering system and associated field
compression. Rex Energy and Sumitomo have dedicated an 895 square mile
area to the Partnership. To date they have jointly leased 68,400
highly prospective acres in Butler County, an acreage position that
continues to grow. The Partnership will gather and process the rich
gas and fractionate the natural gas liquids (NGLs) under long-term
fee-based agreements.
-
In conjunction with the acquisition of Keystone, MarkWest Utica EMG,
LLC (MarkWest Utica) executed a letter agreement to discuss gathering,
processing, and NGL fractionation agreements for portions of Rex
Energy’s Ohio Utica acreage.
Business Development
-
Southwest – In March 2012, the Partnership announced it has entered
into long-term gathering and processing agreements with Anadarko,
Chevron, PetroQuest Energy, and Samson Lone Star that support a 120
MMcf/d expansion of the Partnership’s cryogenic processing capacity in
East Texas (Carthage East). Carthage East is under construction and is
scheduled to come on line in the first quarter of 2013. With the
completion of this plant, total processing capacity in East Texas will
increase to 400 MMcf/d.
-
Liberty – In January 2012, the Partnership announced significant
expansion projects to serve producer customers in the hydrocarbon-rich
area of the Marcellus Shale in northern West Virginia and southwest
Pennsylvania area including a 400 MMcf/d expansion of its Majorsville
processing complex which includes two, 200 MMcf/d processing plants
that are expected to be completed in 2013 and are supported by
long-term agreements with CONSOL Energy, Noble Energy, and Range
Resources.
|
In May 2012, the Partnership announced additional major expansion
projects to serve producer customers in the hydrocarbon-rich area of
the Marcellus Shale in northern West Virginia and southwest
Pennsylvania area, including another 400 MMcf/d expansion of its
Majorsville processing complex which includes two, 200 MMcf/d
processing plants that are expected to be completed in late 2013 and
mid 2014 and are supported by long-term agreements with Chesapeake
Energy. Considering the expansions announced in January and May
2012, the Partnership will have 1.1 billion cubic feet per day of
cryogenic processing capacity at its Majorsville processing complex.
|
|
|
|
In May 2012, the Partnership announced a long-term fee-based
agreement with Antero Resources Appalachian Corporation to install
gathering facilities in support of Antero’s rapidly growing rich
natural gas production in Doddridge and Harrison Counties in
northern West Virginia. The new gathering system will have the
capacity to initially deliver more than 300 MMcf/d of Antero’s rich
gas to the Partnership’s Sherwood gas processing complex. The first
phase of the gathering system will be completed in the third quarter
of 2012 in conjunction with the completion of the 200 MMcf/d
Sherwood I processing facility.
|
|
|
|
The Partnership also announced today that it is extending its
existing NGL gathering pipeline from its Houston, Pennsylvania
fractionation complex into Beaver, Butler and Lawrence Counties to
gather NGLs from the Keystone processing facilities and other
planned processing projects in northwest Pennsylvania. The NGL
pipeline expansion will allow Rex Energy and other producers to
access all of the anticipated ethane pipeline projects.
|
-
Utica – In March 2012, MarkWest Utica announced the execution of a
letter of intent with Gulfport Energy Corporation to provide
gathering, processing, fractionation, and marketing services in the
liquids-rich corridor of the Utica Shale. MarkWest Utica has begun
construction of its facilities and the first phase is expected to come
online beginning in the second half of 2012. MarkWest Utica will
process the gas at its Harrison County processing complex, and will
provide NGL fractionation and marketing services at the Harrison
County fractionator, where NGL purity products will be marketed by
truck, rail, and pipeline.
Capital Markets
-
During the first quarter 2012, the Partnership completed a common unit
equity offering of 6.8 million common units, which included the
exercise of the underwriters’ over-allotment option. The net proceeds
of approximately $388 million were used to partially fund its ongoing
capital expenditure program.
FINANCIAL RESULTS
Balance Sheet
-
At March 31, 2012, the Partnership had $347.8 million of cash and cash
equivalents in wholly owned subsidiaries and $877.7 million available
for borrowing under its $900 million revolving credit facility after
consideration of $22.3 million of outstanding letters of credit.
Operating Results
-
Operating income before items not allocated to segments for the three
months ended March 31, 2012, was $194.2 million, an increase of $45.8
million when compared to $148.4 million for the same period in 2011.
This increase is primarily attributable to the ongoing expansion as
well as the acquisition of the noncontrolling interest in the Liberty
segment, and increased NGL volumes in the Southwest and Northeast
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 gain (loss) on commodity derivative instruments. Realized
losses on commodity derivative instruments were $17.6 million in the
first quarter of 2012 compared to realized losses of $22.3 million in
the first quarter of 2011.
Capital Expenditures
-
For the three months ended March 31, 2012, the Partnership’s portion
of capital expenditures was $254.3 million.
2012 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST
For 2012, the Partnership forecasts DCF in a range of $440 million to
$500 million based on forecasted operational volumes from existing
operations and growth capital projects; derivative instruments currently
outstanding; a reasonable range of price estimates for crude oil,
natural gas and natural gas liquids; and the Keystone acquisition, as
mentioned above. The midpoint of this range results in approximately 145
percent coverage of the Partnership’s full-year distribution based on
current quarterly distributions and common units outstanding. A
sensitivity analysis for forecasted 2012 DCF is provided within the
tables of this press release. The Partnership’s portion of growth
capital expenditures for 2012 was increased for the expected additional
capital requirements to develop the Keystone assets and is forecasted in
a range of $1.1 billion to $1.5 billion. This range excludes the
Keystone purchase price of $512 million. Maintenance capital for 2012 is
forecasted at approximately $20 million.
CONFERENCE CALL
The Partnership will host a conference call and webcast on Tuesday, May
8, 2012, at 12:00 p.m. Eastern Time to review its first 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 (800) 272-5921 (no passcode required).
MarkWest Energy Partners, L.P. is a master limited partnership
engaged in the gathering, transportation, and processing of natural gas;
the transportation, fractionation, marketing, and storage of natural gas
liquids; and the gathering and transportation of crude oil. MarkWest has
extensive natural gas gathering, processing, and transmission operations
in the southwest, Gulf Coast, and northeast regions of the United
States, including the Marcellus Shale, and is the largest natural gas
processor and fractionator in the Appalachian region.
This press release includes “forward-looking statements.” All
statements other than statements of historical facts included or
incorporated herein may constitute forward-looking statements. Actual
results could vary significantly from those expressed or implied in such
statements and are subject to a number of risks and uncertainties.
Although we believe that the expectations reflected in the
forward-looking statements are reasonable, we can give no assurance that
such expectations will prove to be correct. The forward-looking
statements involve risks and uncertainties that affect our operations,
financial performance, and other factors as discussed in our filings
with the Securities and Exchange Commission. Among the factors
that could cause results to differ materially are those risks discussed
in the periodic reports filed with the SEC, including MarkWest's Annual
Report on Form 10-K for the year ended December 31, 2011, and our
Quarterly Report on Form 10-Q for the quarter ended March 31, 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.” 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 March 31,
|
|
Statement of Operations Data
|
|
|
2012
|
|
|
|
|
2011
|
|
|
Revenue:
|
|
|
|
|
|
|
Revenue
|
|
$
|
399,181
|
|
|
|
$
|
348,900
|
|
|
Derivative loss
|
|
|
(48,715
|
)
|
|
|
|
(85,679
|
)
|
|
Total revenue
|
|
|
350,466
|
|
|
|
|
263,221
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
Purchased product costs
|
|
|
154,555
|
|
|
|
|
153,629
|
|
|
Derivative loss related to purchased product costs
|
|
|
18,800
|
|
|
|
|
19,394
|
|
|
Facility expenses
|
|
|
48,840
|
|
|
|
|
39,424
|
|
|
Derivative gain related to facility expenses
|
|
|
(1,746
|
)
|
|
|
|
(3,011
|
)
|
|
Selling, general and administrative expenses
|
|
|
25,224
|
|
|
|
|
21,712
|
|
|
Depreciation
|
|
|
41,145
|
|
|
|
|
34,364
|
|
|
Amortization of intangible assets
|
|
|
10,985
|
|
|
|
|
10,817
|
|
|
Loss on disposal of property, plant and equipment
|
|
|
986
|
|
|
|
|
2,099
|
|
|
Accretion of asset retirement obligations
|
|
|
238
|
|
|
|
|
87
|
|
|
Total operating expenses
|
|
|
299,027
|
|
|
|
|
278,515
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
51,439
|
|
|
|
|
(15,294
|
)
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
Loss from unconsolidated affiliates
|
|
|
(9
|
)
|
|
|
|
(539
|
)
|
|
Interest income
|
|
|
72
|
|
|
|
|
89
|
|
|
Interest expense
|
|
|
(29,472
|
)
|
|
|
|
(28,263
|
)
|
|
Amortization of deferred financing costs and discount (a component
of interest expense)
|
|
|
(1,270
|
)
|
|
|
|
(1,428
|
)
|
|
Loss on redemption of debt
|
|
|
-
|
|
|
|
|
(43,328
|
)
|
|
Miscellaneous income (loss), net
|
|
|
58
|
|
|
|
|
(38
|
)
|
|
Income (loss) before provision for income tax
|
|
|
20,818
|
|
|
|
|
(88,801
|
)
|
|
|
|
|
|
|
|
|
Provision for income tax expense (benefit):
|
|
|
|
|
|
|
Current
|
|
|
15,341
|
|
|
|
|
56
|
|
|
Deferred
|
|
|
(10,796
|
)
|
|
|
|
(14,186
|
)
|
|
Total provision for income tax
|
|
|
4,545
|
|
|
|
|
(14,130
|
)
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
16,273
|
|
|
|
|
(74,671
|
)
|
|
|
|
|
|
|
|
|
Net income attributable to non-controlling interest
|
|
|
(253
|
)
|
|
|
|
(9,358
|
)
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to the Partnership
|
|
$
|
16,020
|
|
|
|
$
|
(84,029
|
)
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to the Partnership's common
unitholders per common unit:
|
|
|
|
|
|
Basic
|
|
$
|
0.16
|
|
|
|
$
|
(1.13
|
)
|
|
Diluted
|
|
$
|
0.14
|
|
|
|
$
|
(1.13
|
)
|
|
|
|
|
|
|
|
|
Weighted average number of outstanding common units:
|
|
|
|
|
|
|
Basic
|
|
|
96,840
|
|
|
|
|
74,531
|
|
|
Diluted
|
|
|
117,593
|
|
|
|
|
74,531
|
|
|
|
|
|
|
|
|
|
Cash Flow Data
|
|
|
|
|
|
|
Net cash flow provided by (used in):
|
|
|
|
|
|
|
Operating activities
|
|
$
|
207,913
|
|
|
|
$
|
115,319
|
|
|
Investing activities
|
|
|
(252,969
|
)
|
|
|
|
(341,621
|
)
|
|
Financing activities
|
|
|
278,674
|
|
|
|
|
232,004
|
|
|
|
|
|
|
|
|
|
Other Financial Data
|
|
|
|
|
|
|
Distributable cash flow
|
|
$
|
109,177
|
|
|
|
$
|
76,136
|
|
|
Adjusted EBITDA
|
|
|
132,943
|
|
|
|
|
96,187
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data
|
|
March 31, 2012
|
|
|
December 31, 2011
|
|
Working capital
|
|
$
|
113,344
|
|
|
|
$
|
4,234
|
|
|
Total assets
|
|
|
4,445,647
|
|
|
|
|
4,070,425
|
|
|
Total debt
|
|
|
1,780,091
|
|
|
|
|
1,846,062
|
|
|
Total equity
|
|
|
1,852,301
|
|
|
|
|
1,502,067
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MarkWest Energy Partners, L.P.
|
|
Operating Statistics
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31,
|
|
|
|
|
2012
|
|
|
2011
|
|
Southwest
|
|
|
|
|
|
|
East Texas gathering systems throughput (Mcf/d)
|
|
410,000
|
|
|
425,800
|
|
East Texas natural gas processed (Mcf/d)
|
|
242,500
|
|
|
219,200
|
|
East Texas NGL sales (gallons, in thousands)
|
|
63,400
|
|
|
56,700
|
|
|
|
|
|
|
|
|
|
Western Oklahoma gathering system throughput (Mcf/d) (1)
|
|
262,000
|
|
|
207,400
|
|
Western Oklahoma natural gas processed (Mcf/d)
|
|
203,800
|
|
|
157,100
|
|
Western Oklahoma NGL sales (gallons, in thousands)
|
|
57,300
|
|
|
39,000
|
|
|
|
|
|
|
|
|
|
Southeast Oklahoma gathering system throughput (Mcf/d)
|
|
501,200
|
|
|
498,000
|
|
Southeast Oklahoma natural gas processed (Mcf/d) (2)
|
|
101,700
|
|
|
93,700
|
|
Southeast Oklahoma NGL sales (gallons, in thousands)
|
|
33,000
|
|
|
29,400
|
|
Arkoma Connector Pipeline throughput (Mcf/d)
|
|
328,700
|
|
|
285,900
|
|
|
|
|
|
|
|
|
|
Other Southwest gathering system throughput (Mcf/d)
|
|
25,000
|
|
|
33,100
|
|
|
|
|
|
|
|
|
|
Northeast
|
|
|
|
|
|
|
Natural gas processed (Mcf/d) (3)
|
|
321,700
|
|
|
304,800
|
|
NGLs fractionated (Bbl/d) (4)
|
|
16,700
|
|
|
22,200
|
|
|
|
|
|
|
|
|
|
Keep-whole sales (gallons, in thousands)
|
|
49,500
|
|
|
39,800
|
|
Percent-of-proceeds sales (gallons, in thousands)
|
|
33,000
|
|
|
30,900
|
|
Total NGL sales (gallons, in thousands) (5)
|
|
82,500
|
|
|
70,700
|
|
|
|
|
|
|
|
|
|
Crude oil transported for a fee (Bbl/d)
|
|
10,400
|
|
|
10,200
|
|
|
|
|
|
|
|
|
|
Liberty
|
|
|
|
|
|
|
Natural gas processed (Mcf/d)
|
|
392,100
|
|
|
254,500
|
|
Gathering system throughput (Mcf/d)
|
|
308,100
|
|
|
195,900
|
|
NGLs fractionated (Bbl/d) (6)
|
|
20,000
|
|
|
6,900
|
|
NGL sales (gallons, in thousands) (7)
|
|
97,500
|
|
|
51,800
|
|
|
|
|
|
|
|
|
|
Gulf Coast
|
|
|
|
|
|
|
Refinery off-gas processed (Mcf/d)
|
|
120,300
|
|
|
102,800
|
|
Liquids fractionated (Bbl/d)
|
|
23,400
|
|
|
19,200
|
|
NGL sales (gallons excluding hydrogen, in thousands)
|
|
89,300
|
|
|
72,700
|
|
|
|
|
|
|
|
|
(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 plant in
February 2011. The volumes reported for the three months ended March
31, 2011 are the average daily rates for the days of operation.
|
|
(4)
|
|
Amount includes zero barrels per day and 5,500 barrels per day
fractionated on behalf of Liberty for the three months ended March
31, 2012 and 2011, respectively. Beginning in the fourth quarter of
2011, Siloam no longer fractionated NGLs on behalf of Liberty due to
the operation of Liberty’s fractionation facility that began in
September 2011.
|
|
(5)
|
|
Represents sales from the Siloam facilities. The total sales exclude
approximately zero gallons and 20,700,000 gallons sold by the
Northeast on behalf of Liberty for the three months ended March 31,
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 March 31, 2012
|
|
Southwest
|
|
|
Northeast
|
|
|
Liberty
|
|
|
Gulf Coast
|
|
|
Total
|
|
Revenue
|
|
$
|
214,725
|
|
|
$
|
86,918
|
|
|
$
|
75,577
|
|
|
$
|
24,229
|
|
|
$
|
401,449
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased product costs
|
|
|
104,233
|
|
|
|
25,687
|
|
|
|
24,635
|
|
|
|
-
|
|
|
|
154,555
|
|
Facility expenses
|
|
|
22,992
|
|
|
|
6,378
|
|
|
|
12,247
|
|
|
|
9,638
|
|
|
|
51,255
|
|
Total operating expenses before items not allocated to segments
|
|
|
87,500
|
|
|
|
54,853
|
|
|
|
38,695
|
|
|
|
14,591
|
|
|
|
195,639
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Portion of operating income attributable to non-controlling interests
|
|
|
1,446
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,446
|
|
Operating income before items not allocated to segments
|
|
$
|
86,054
|
|
|
$
|
54,853
|
|
|
$
|
38,695
|
|
|
$
|
14,591
|
|
|
$
|
194,193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31, 2011
|
|
Southwest
|
|
|
Northeast
|
|
|
Liberty
|
|
|
Gulf Coast
|
|
|
Total
|
|
Revenue
|
|
$
|
201,774
|
|
|
$
|
92,091
|
|
|
$
|
41,219
|
|
|
$
|
21,759
|
|
|
$
|
356,843
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased product costs
|
|
|
103,196
|
|
|
|
40,878
|
|
|
|
9,555
|
|
|
|
-
|
|
|
|
153,629
|
|
Facility expenses
|
|
|
20,157
|
|
|
|
5,594
|
|
|
|
6,498
|
|
|
|
8,990
|
|
|
|
41,239
|
|
Total operating expenses before items not allocated to segments
|
|
|
78,421
|
|
|
|
45,619
|
|
|
|
25,166
|
|
|
|
12,769
|
|
|
|
161,975
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Portion of operating income attributable to non-controlling interests
|
|
|
1,172
|
|
|
|
-
|
|
|
|
12,377
|
|
|
|
-
|
|
|
|
13,549
|
|
Operating income before items not allocated to segments
|
|
$
|
77,249
|
|
|
$
|
45,619
|
|
|
$
|
12,789
|
|
|
$
|
12,769
|
|
|
$
|
148,426
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31,
|
|
|
|
|
2012
|
|
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
Operating income before items not allocated to segments
|
|
$
|
194,193
|
|
|
|
$
|
148,426
|
|
|
Portion of operating income attributable to non-controlling interests
|
|
|
1,446
|
|
|
|
|
13,549
|
|
|
Derivative loss not allocated to segments
|
|
|
(65,769
|
)
|
|
|
|
(102,062
|
)
|
|
Revenue deferral adjustment
|
|
|
(2,268
|
)
|
|
|
|
(7,943
|
)
|
|
Compensation expense included in facility expenses not allocated to
segments
|
|
|
(449
|
)
|
|
|
|
(1,040
|
)
|
|
Facility expenses adjustments
|
|
|
2,864
|
|
|
|
|
2,855
|
|
|
Selling, general and administrative expenses
|
|
|
(25,224
|
)
|
|
|
|
(21,712
|
)
|
|
Depreciation
|
|
|
(41,145
|
)
|
|
|
|
(34,364
|
)
|
|
Amortization of intangible assets
|
|
|
(10,985
|
)
|
|
|
|
(10,817
|
)
|
|
Loss on disposal of property, plant and equipment
|
|
|
(986
|
)
|
|
|
|
(2,099
|
)
|
|
Accretion of asset retirement obligations
|
|
|
(238
|
)
|
|
|
|
(87
|
)
|
|
Income (loss) from operations
|
|
|
51,439
|
|
|
|
|
(15,294
|
)
|
|
Other income (expense):
|
|
|
|
|
|
|
Loss from unconsolidated affiliates
|
|
|
(9
|
)
|
|
|
|
(539
|
)
|
|
Interest income
|
|
|
72
|
|
|
|
|
89
|
|
|
Interest expense
|
|
|
(29,472
|
)
|
|
|
|
(28,263
|
)
|
|
Amortization of deferred financing costs and discount (a component
of interest expense)
|
|
|
(1,270
|
)
|
|
|
|
(1,428
|
)
|
|
Loss on redemption of debt
|
|
|
-
|
|
|
|
|
(43,328
|
)
|
|
Miscellaneous income, net
|
|
|
58
|
|
|
|
|
(38
|
)
|
|
Income (loss) before provision for income tax
|
|
$
|
20,818
|
|
|
|
$
|
(88,801
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MarkWest Energy Partners, L.P.
|
|
Reconciliation of GAAP Financial Measure to Non-GAAP Financial
Measure
|
|
Distributable Cash Flow
|
|
(unaudited, in thousands)
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31,
|
|
|
|
|
2012
|
|
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
16,273
|
|
|
|
$
|
(74,671
|
)
|
|
Depreciation, amortization, impairment, and other non-cash operating
expenses
|
|
|
53,432
|
|
|
|
|
47,445
|
|
|
Loss on redemption of debt, net of tax benefit
|
|
|
-
|
|
|
|
|
39,499
|
|
|
Amortization of deferred financing costs and discount
|
|
|
1,270
|
|
|
|
|
1,428
|
|
|
Non-cash loss from unconsolidated affiliate
|
|
|
9
|
|
|
|
|
539
|
|
|
Distributions from unconsolidated affiliate
|
|
|
900
|
|
|
|
|
-
|
|
|
Non-cash compensation expense
|
|
|
2,710
|
|
|
|
|
1,578
|
|
|
Non-cash derivative activity
|
|
|
48,217
|
|
|
|
|
79,784
|
|
|
Provision for income tax - deferred
|
|
|
(10,796
|
)
|
|
|
|
(14,186
|
)
|
|
Cash adjustment for non-controlling interest of consolidated
subsidiaries
|
|
|
(1,017
|
)
|
|
|
|
(12,522
|
)
|
|
Revenue deferral adjustment
|
|
|
2,268
|
|
|
|
|
7,943
|
|
|
Other
|
|
|
2,208
|
|
|
|
|
1,707
|
|
|
Maintenance capital expenditures, net of joint venture partner
contributions
|
|
|
(6,297
|
)
|
|
|
|
(2,408
|
)
|
|
Distributable cash flow
|
|
$
|
109,177
|
|
|
|
$
|
76,136
|
|
|
|
|
|
|
|
|
|
Maintenance capital expenditures
|
|
$
|
6,297
|
|
|
|
$
|
2,506
|
|
|
Growth capital expenditures
|
|
|
247,966
|
|
|
|
|
111,146
|
|
|
Total capital expenditures
|
|
|
254,263
|
|
|
|
|
113,652
|
|
|
Acquisition
|
|
|
-
|
|
|
|
|
230,728
|
|
|
Total capital expenditures and acquisition
|
|
|
254,263
|
|
|
|
|
344,380
|
|
|
Joint venture partner contributions
|
|
|
-
|
|
|
|
|
(35,176
|
)
|
|
Total capital expenditures and acquisition, net
|
|
$
|
254,263
|
|
|
|
$
|
309,204
|
|
|
|
|
|
|
|
|
|
Distributable cash flow
|
|
$
|
109,177
|
|
|
|
$
|
76,136
|
|
|
Maintenance capital expenditures, net
|
|
|
6,297
|
|
|
|
|
2,408
|
|
|
Changes in receivables and other assets
|
|
|
57,655
|
|
|
|
|
19,869
|
|
|
Changes in accounts payable, accrued liabilities and other long-term
liabilities
|
|
|
35,244
|
|
|
|
|
5,102
|
|
|
Derivative instrument premium payments, net of amortization
|
|
|
-
|
|
|
|
|
1,045
|
|
|
Cash adjustment for non-controlling interest of consolidated
subsidiaries
|
|
|
1,017
|
|
|
|
|
12,522
|
|
|
Other
|
|
|
(1,477
|
)
|
|
|
|
(1,763
|
)
|
|
Net cash provided by operating activities
|
|
$
|
207,913
|
|
|
|
$
|
115,319
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MarkWest Energy Partners, L.P.
|
|
Reconciliation of GAAP Financial Measure to Non-GAAP Financial
Measure
|
|
Adjusted EBITDA
|
|
(unaudited, in thousands)
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31,
|
|
|
|
|
2012
|
|
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
16,273
|
|
|
|
$
|
(74,671
|
)
|
|
Non-cash compensation expense
|
|
|
2,710
|
|
|
|
|
1,578
|
|
|
Non-cash derivative activity
|
|
|
48,217
|
|
|
|
|
79,784
|
|
|
Interest expense (1)
|
|
|
28,552
|
|
|
|
|
27,456
|
|
|
Depreciation, amortization, impairment, and other non-cash operating
expenses
|
|
|
53,432
|
|
|
|
|
47,445
|
|
|
Loss on redemption of debt
|
|
|
-
|
|
|
|
|
43,328
|
|
|
Provision for income tax
|
|
|
4,545
|
|
|
|
|
(14,130
|
)
|
|
Adjustment for cash flow from unconsolidated affiliate
|
|
|
909
|
|
|
|
|
539
|
|
|
Adjustment related to non-guarantor, consolidated subsidiaries (2)
|
|
|
(21,198
|
)
|
|
|
|
(14,690
|
)
|
|
Other
|
|
|
(497
|
)
|
|
|
|
(452
|
)
|
|
Adjusted EBITDA
|
|
$
|
132,943
|
|
|
|
$
|
96,187
|
|
|
|
|
|
|
|
|
|
(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.
(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 except commodity prices)
The Partnership periodically estimates the effect on DCF resulting from
its commodity risk management program, changes in crude oil and natural
gas prices, and the correlation of NGL prices to crude oil. The table
below reflects The Partnership’s estimate of the range of DCF for 2012
and forecasted crude oil and natural gas prices for 2012. The analysis
assumes various combinations of crude oil and natural gas prices as well
as three NGL to crude correlation scenarios for all NGLs (C2+),
including:
a. The three-year NGL correlation to crude for 2012.
b. One
standard deviation above the three-year NGL correlation to crude for
2012.
c. One standard deviation below the three-year NGL
correlation to crude for 2012.
The analysis further assumes derivative instruments outstanding as of
April 30, 2012, and production volumes estimated through December 31,
2012. The range of stated hypothetical changes in commodity prices
considers current and historic market performance.
|
Estimated Range of 2012 DCF
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Price
|
|
|
Crude Oil Price
|
|
Three-year NGL Correlation to Crude
|
|
|
$2.00
|
|
|
$2.50
|
|
|
$3.00
|
|
|
$3.50
|
|
|
$4.00
|
|
|
|
|
One standard deviation above
|
|
|
561
|
|
|
557
|
|
|
553
|
|
|
549
|
|
|
546
|
|
|
$120
|
|
Three-year NGL correlation to crude
|
|
|
501
|
|
|
497
|
|
|
494
|
|
|
490
|
|
|
486
|
|
|
|
|
One standard deviation below
|
|
|
443
|
|
|
439
|
|
|
435
|
|
|
432
|
|
|
428
|
|
|
|
|
One standard deviation above
|
|
|
543
|
|
|
540
|
|
|
536
|
|
|
532
|
|
|
529
|
|
|
$110
|
|
Three-year NGL correlation to crude
|
|
|
489
|
|
|
485
|
|
|
481
|
|
|
478
|
|
|
474
|
|
|
|
|
One standard deviation below
|
|
|
437
|
|
|
433
|
|
|
429
|
|
|
426
|
|
|
422
|
|
|
|
|
One standard deviation above
|
|
|
522
|
|
|
519
|
|
|
515
|
|
|
511
|
|
|
507
|
|
|
$100
|
|
Three-year NGL correlation to crude
|
|
|
473
|
|
|
469
|
|
|
466
|
|
|
462
|
|
|
458
|
|
|
|
|
One standard deviation below
|
|
|
426
|
|
|
422
|
|
|
419
|
|
|
415
|
|
|
411
|
|
|
|
|
One standard deviation above
|
|
|
499
|
|
|
495
|
|
|
491
|
|
|
487
|
|
|
484
|
|
|
$90
|
|
Three-year NGL correlation to crude
|
|
|
455
|
|
|
452
|
|
|
448
|
|
|
444
|
|
|
441
|
|
|
|
|
One standard deviation below
|
|
|
413
|
|
|
409
|
|
|
405
|
|
|
402
|
|
|
398
|
|
|
|
|
One standard deviation above
|
|
|
477
|
|
|
473
|
|
|
470
|
|
|
466
|
|
|
462
|
|
|
$80
|
|
Three-year NGL correlation to crude
|
|
|
440
|
|
|
436
|
|
|
433
|
|
|
429
|
|
|
425
|
|
|
|
|
One standard deviation below
|
|
|
402
|
|
|
398
|
|
|
394
|
|
|
391
|
|
|
388
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The table is based on current information, expectations, and beliefs
concerning future developments and their potential effects, and does not
consider actions the Partnership’s 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, particularly 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
|
View printer-friendly version
click here for PDF