MarkWest Energy Partners Reports Third Quarter Financial Results and Increases Common Unit Distribution by 11 Percent
MarkWest Energy Partners Reports Third Quarter Financial Results and
Increases Common Unit Distribution by 11 Percent
Business Wire
DENVER -- November 07, 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 Nine months ended September
30, 30,
Statement of 2012 2011 2012 2011
Operations Data
Revenue:
Revenue $ 320,137 $ 400,883 $ 1,029,304 $ 1,109,632
Derivative (36,400 ) 106,943 50,952 61,854
(loss) gain
Total revenue 283,737 507,826 1,080,256 1,171,486
Operating
expenses:
Purchased 119,369 189,284 386,655 497,493
product costs
Derivative loss
(gain) related 11,643 (1,274 ) (21,136 ) 17,866
to purchased
product costs
Facility 53,293 44,236 150,671 124,358
expenses
Derivative loss
(gain) related 4,028 (2,787 ) 1,136 (2,871 )
to facility
expenses
Selling,
general and 21,922 20,162 69,025 60,454
administrative
expenses
Depreciation 48,136 38,715 132,199 110,280
Amortization of
intangible 14,988 10,985 38,280 32,632
assets
Loss on
disposal of 655 147 2,983 4,619
property, plant
and equipment
Accretion of
asset 141 557 540 934
retirement
obligations
Total operating 274,175 300,025 760,353 845,765
expenses
Income from 9,562 207,801 319,903 325,721
operations
Other income
(expense):
Earnings (loss)
from 246 (507 ) 788 (1,262 )
unconsolidated
affiliates
Interest income 64 62 295 214
Interest (30,621 ) (26,899 ) (86,855 ) (83,036 )
expense
Amortization of
deferred
financing costs
and discount (a (1,428 ) (1,002 ) (3,943 ) (3,873 )
component of
interest
expense)
Loss on
redemption of - (133 ) - (43,461 )
debt
Miscellaneous
income 1 (4 ) 63 127
(expense), net
(Loss) Income
before (22,176 ) 179,318 230,251 194,430
provision for
income tax
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 (7,420 ) 25,864 41,598 26,442
for income tax
Net (loss) (14,756 ) 153,454 188,653 167,988
income
Net loss
(income)
attributable to 416 (13,142 ) (65 ) (33,208 )
non-controlling
interest
Net (loss)
income $ (14,340 ) $ 140,312 $ 188,588 $ 134,780
attributable to
the Partnership
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 $ 133,281 $ 124,885 $ 389,718 $ 331,249
activities
Investing $ (658,573 ) $ (125,637 ) $ (1,746,071 ) $ (587,686 )
activities
Financing $ 814,894 $ 64,894 $ 1,654,401 $ 348,164
activities
Other Financial
Data
Distributable $ 104,289 $ 85,311 $ 304,649 $ 244,391
cash flow
Adjusted EBITDA $ 108,180 $ 107,013 $ 371,655 $ 323,204
Balance Sheet September 30, December 31,
Data 2012 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 Nine months ended
September 30, September 30,
2012 2011 2012 2011
Southwest
East Texas gathering systems 471,200 417,400 440,700 423,800
throughput (Mcf/d)
East Texas natural gas processed 270,200 229,700 260,400 226,000
(Mcf/d)
East Texas NGL sales (gallons, 67,800 59,000 199,300 175,200
in thousands)
Western Oklahoma gathering 227,900 241,300 247,300 224,400
system throughput (Mcf/d) (1)
Western Oklahoma natural gas 209,600 153,200 210,800 156,600
processed (Mcf/d)
Western Oklahoma NGL sales 50,900 37,000 169,900 111,100
(gallons, in thousands)
Southeast Oklahoma gathering 484,400 512,600 496,200 507,500
system throughput (Mcf/d)
Southeast Oklahoma natural gas 128,600 105,400 116,700 103,100
processed (Mcf/d) (2)
Southeast Oklahoma NGL sales 46,700 30,600 121,000 92,100
(gallons, in thousands)
Arkoma Connector Pipeline 310,400 298,600 323,400 294,300
throughput (Mcf/d)
Other Southwest gathering system 23,600 29,900 25,000 31,500
throughput (Mcf/d)
Northeast
Natural gas processed (Mcf/d) 318,500 277,400 322,800 300,700
(3)
NGLs fractionated (Bbl/d) (4) 16,500 19,300 16,800 21,400
Keep-whole sales (gallons, in 23,200 21,700 96,500 82,600
thousands)
Percent-of-proceeds sales 33,700 31,600 103,500 95,600
(gallons, in thousands)
Total NGL sales (gallons, in 56,900 53,300 200,000 178,200
thousands) (5)
Crude oil transported for a fee 8,700 9,900 9,100 10,500
(Bbl/d)
Liberty
Natural gas processed (Mcf/d) 479,400 366,200 424,300 306,700
Gathering system throughput 444,700 258,300 373,700 228,900
(Mcf/d)
NGLs fractionated (Bbl/d) (6) 22,300 12,400 20,700 9,300
NGL sales (gallons, in 90,800 61,100 264,200 163,500
thousands) (7)
Gulf Coast
Refinery off-gas processed 123,800 122,000 120,000 113,200
(Mcf/d)
Liquids fractionated (Bbl/d) 23,800 23,100 23,000 21,400
NGL sales (gallons excluding 92,100 89,200 264,400 245,500
hydrogen, in thousands)
Includes natural gas gathered in Western Oklahoma and from the Granite
(1) 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.
Includes throughput from the Kenova, Cobb, Boldman and Langley
(3) 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.
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
(4) 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.
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,
(5) 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.
Amount includes all NGLs that were produced at the Liberty processing
(6) facilities and fractionated into purity products at our Liberty
fractionation facility.
Includes sale of all purity products fractionated at the Liberty
(7) 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 Gulf
ended September Southwest Northeast Liberty Coast Total
30, 2012
Revenue $ 181,456 $ 39,987 $ 78,852 $ 21,477 $ 321,772
Operating
expenses:
Purchased 92,112 11,054 16,203 - 119,369
product costs
Facility 20,527 6,267 20,241 8,928 55,963
expenses
Total operating
expenses before
items not 112,639 17,321 36,444 8,928 175,332
allocated to
segments
Portion of
operating
income 1,543 - (627 ) - 916
attributable to
non-controlling
interests
Operating
income before
items not $ 67,274 $ 22,666 $ 43,035 $ 12,549 $ 145,524
allocated to
segments
Three months Gulf
ended September Southwest Northeast Liberty Coast Total
30, 2011
Revenue $ 241,998 $ 55,920 $ 78,586 $ 26,868 $ 403,372
Operating
expenses:
Purchased 141,067 15,947 32,270 - 189,284
product costs
Facility 21,043 6,879 9,108 9,798 46,828
expenses
Total operating
expenses before
items not 162,110 22,826 41,378 9,798 236,112
allocated to
segments
Portion of
operating
income 1,227 - 18,223 - 19,450
attributable to
non-controlling
interests
Operating
income before
items not $ 78,661 $ 33,094 $ 18,985 $ 17,070 $ 147,810
allocated to
segments
Three months ended
September 30,
2012 2011
Operating
income before
items not $ 145,524 $ 147,810
allocated to
segments
Portion of
operating
income 916 19,450
attributable to
non-controlling
interests
Derivative
(loss) gain not (52,071 ) 111,004
allocated to
segments
Revenue
deferral (1,635 ) (2,489 )
adjustment
Compensation
expense
included in
facility (193 ) (263 )
expenses not
allocated to
segments
Facility
expenses 2,863 2,855
adjustments
Selling,
general and (21,922 ) (20,162 )
administrative
expenses
Depreciation (48,136 ) (38,715 )
Amortization of
intangible (14,988 ) (10,985 )
assets
Loss on
disposal of (655 ) (147 )
property, plant
and equipment
Accretion of
asset (141 ) (557 )
retirement
obligations
Income from 9,562 207,801
operations
Other income
(expense):
Earnings (loss)
from 246 (507 )
unconsolidated
affiliate
Interest income 64 62
Interest (30,621 ) (26,899 )
expense
Amortization of
deferred
financing costs
and discount (a (1,428 ) (1,002 )
component of
interest
expense)
Loss on
redemption of - (133 )
debt
Miscellaneous
income 1 (4 )
(expense), net
(Loss) Income
before $ (22,176 ) $ 179,318
provision for
income tax
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 Gulf
ended September Southwest Northeast Liberty Coast Total
30, 2012
Revenue $ 585,343 $ 168,956 $ 213,906 $ 66,703 $ 1,034,908
Operating
expenses:
Purchased 288,137 49,662 48,856 - 386,655
product costs
Facility 66,553 17,577 46,135 28,173 158,438
expenses
Total operating
expenses before
items not 354,690 67,239 94,991 28,173 545,093
allocated to
segments
Portion of
operating
income 4,579 - (740 ) - 3,839
attributable to
non-controlling
interests
Operating
income before
items not $ 226,074 $ 101,717 $ 119,655 $ 38,530 $ 485,976
allocated to
segments
Nine months Gulf
ended September Southwest Northeast Liberty Coast Total
30, 2011
Revenue $ 679,347 $ 201,687 $ 168,142 $ 73,310 $ 1,122,486
Operating
expenses:
Purchased 373,251 72,527 51,715 - 497,493
product costs
Facility 62,055 19,402 22,875 27,100 131,432
expenses
Total operating
expenses before
items not 435,306 91,929 74,590 27,100 628,925
allocated to
segments
Portion of
operating
income 3,745 - 45,782 - 49,527
attributable to
non-controlling
interests
Operating
income before
items not $ 240,296 $ 109,758 $ 47,770 $ 46,210 $ 444,034
allocated to
segments
Nine months ended September
30,
2012 2011
Operating
income before
items not $ 485,976 $ 444,034
allocated to
segments
Portion of
operating
income 3,839 49,527
attributable to
non-controlling
interests
Derivative gain
not allocated 70,952 46,859
to segments
Revenue
deferral (5,604 ) (12,854 )
adjustment
Compensation
expense
included in
facility (826 ) (1,491 )
expenses not
allocated to
segments
Facility
expenses 8,593 8,565
adjustments
Selling,
general and (69,025 ) (60,454 )
administrative
expenses
Depreciation (132,199 ) (110,280 )
Amortization of
intangible (38,280 ) (32,632 )
assets
Loss on
disposal of (2,983 ) (4,619 )
property, plant
and equipment
Accretion of
asset (540 ) (934 )
retirement
obligations
Income from 319,903 325,721
operations
Other income
(expense):
Earnings (loss)
from 788 (1,262 )
unconsolidated
affiliate
Interest income 295 214
Interest (86,855 ) (83,036 )
expense
Amortization of
deferred
financing costs
and discount (a (3,943 ) (3,873 )
component of
interest
expense)
Loss on
redemption of - (43,461 )
debt
Miscellaneous 63 127
income, net
Income before
provision for $ 230,251 $ 194,430
income tax
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 Nine months ended September
30, 30,
2012 2011 2012 2011
Net income $ (14,756 ) $ 153,454 $ 188,653 $ 167,988
Depreciation,
amortization,
impairment, and 63,998 50,482 174,236 148,699
other non-cash
operating
expenses
Loss on
redemption of - 119 - 39,618
debt, net of tax
benefit
Amortization of
deferred 1,428 1,002 3,943 3,873
financing costs
and discount
Non-cash
(earnings) loss
from (246 ) 507 (788 ) 1,262
unconsolidated
affiliate
Distributions
from 500 - 2,200 300
unconsolidated
affiliate
Non-cash
compensation 981 995 6,270 3,707
expense
Non-cash
derivative 43,712 (126,802 ) (101,815 ) (102,681 )
activity
Provision for
income tax - 10,528 21,905 39,396 18,338
deferred
Cash adjustment
for
non-controlling (490 ) (18,227 ) (2,513 ) (46,285 )
interest of
consolidated
subsidiaries
Revenue deferral 1,635 2,489 5,604 12,854
adjustment
Other 1,173 1,334 3,962 4,537
Maintenance
capital
expenditures, (4,174 ) (1,947 ) (14,499 ) (7,819 )
net of joint
venture partner
contributions
Distributable $ 104,289 $ 85,311 $ 304,649 $ 244,391
cash flow
Maintenance
capital $ 4,174 $ 2,179 $ 14,499 $ 8,577
expenditures
Growth capital 654,489 123,631 1,226,367 351,349
expenditures
Total capital 658,663 125,810 1,240,866 359,926
expenditures
Acquisitions - - 506,797 230,728
Total capital
expenditures and 658,663 125,810 1,747,663 590,654
acquisitions
Joint venture
partner (55,000 ) (14,474 ) (55,000 ) (68,501 )
contributions
Total capital
expenditures and $ 603,663 $ 111,336 $ 1,692,663 $ 522,153
acquisitions,
net
Distributable $ 104,289 $ 85,311 $ 304,649 $ 244,391
cash flow
Maintenance
capital 4,174 1,947 14,499 7,819
expenditures,
net
Changes in
receivables and (85,436 ) (17,856 ) 26,946 (33,255 )
other assets
Changes in
accounts
payable, accrued 110,559 38,405 45,368 69,372
liabilities and
other long-term
liabilities
Derivative
instrument
premium - 1,137 - 3,281
payments, net of
amortization
Cash adjustment
for
non-controlling 490 18,227 2,513 46,285
interest of
consolidated
subsidiaries
Other (795 ) (2,286 ) (4,257 ) (6,644 )
Net cash
provided by $ 133,281 $ 124,885 $ 389,718 $ 331,249
operating
activities
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Adjusted EBITDA
(unaudited, in thousands)
Three months ended September Nine months ended September
30, 30,
2012 2011 2012 2011
Net income $ (14,756 ) $ 153,454 $ 188,653 $ 167,988
Non-cash
compensation 981 995 6,270 3,707
expense
Non-cash
derivative 43,712 (126,802 ) (101,815 ) (102,681 )
activity
Interest 29,882 25,687 84,260 80,235
expense ^(1)
Depreciation,
amortization,
impairment, and 63,998 50,482 174,236 148,699
other non-cash
operating
expenses
Loss on
redemption of - 133 - 43,461
debt
Provision for (7,420 ) 25,864 41,598 26,442
income tax
Adjustment for
cash flow from 254 507 1,412 1,562
unconsolidated
affiliate
Adjustment
related to
non-guarantor, (7,951 ) (22,713 ) (21,434 ) (44,819 )
consolidated
subsidiaries
^(2)
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.
The non-guarantor subsidiaries, in accordance with Credit Facility
covenants, are MarkWest Liberty Midstream & Resources, L.L.C. and its
(2) 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 NGL-to-Crude
Price oil ratio (1) $ 2.50 $ 3.00 $ 3.50 $ 4.00 $ 4.50
(WTI)
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
The composition is based on MarkWest’s average projected barrel of
(1) 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.”
Contact:
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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