MarkWest Energy Partners Reports First Quarter Financial Results
DENVER, May 08, 2013 (BUSINESS WIRE) -- --Placed into service four additional processing facilities with combined capacity of 645 MMcf/d. The Partnership has 18 major processing and fractionation projects currently under construction, which are expected to be completed by the end of 2014.
--Executed an agreement with Antero Resources to expand the Sherwood processing complex by 200 MMcf/d, bringing total capacity in the Marcellus Shale to 3.2 Bcf/d by the end of 2014.
--Executed agreements with four producers in the Utica Shale, bringing total producers under contract to six.
--Executed long-term fee-based agreement with Newfield Exploration to acquire and develop rich- gas gathering facilities in the Eagle Ford Shale.
--Fee-based net operating margin increased from 39 percent to 58 percent when compared to the first quarter of last year.
MarkWest Energy Partners, L.P. MWE +4.17% (the Partnership) today reported quarterly cash available for distribution to common unitholders, or distributable cash flow (DCF), of $110.2 million for the three months ended March 31, 2013, compared to $109.2 million for the three months ended March 31, 2012. DCF for the three months ended March 31, 2013 represents 102 percent coverage of the first quarter distribution of $108.4 million or $0.83 per common unit, which will be paid to unitholders on May 15, 2013. The first quarter 2013 distribution represents an increase of $0.01 per common unit or 1.2 percent over the fourth quarter 2012 distribution and an increase of $0.04 per common unit or 5.1 percent compared to the first quarter 2012 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 of $140.8 million for the three months ended March 31, 2013, compared to $153.1 million for the same period in 2012. 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 months ended March 31, 2013 of ($14.2) million, compared to $20.8 million for the same period in 2012. Income (loss) before provision for income tax includes non-cash gains (losses) associated with the change in fair value of derivative instruments of $9.0 million and ($48.2) million for the three months ended March 31, 2013 and March 31, 2012, respectively, and a (loss) associated with the redemption of debt of ($38.5) million for the three months ended March 31, 2013. Excluding these items, income before provision for income tax for the three months ended March 31, 2013 and 2012 would have been $15.3 million and $69.0 million, respectively.
"Our diverse set of midstream assets continues to deliver strong financial results and create opportunities for future growth," said Frank Semple, Chairman, President and Chief Executive Officer. "The recent completion of nine major projects since last October and the planned completion of 18 additional major projects over the next year and a half will continue to grow our fee-based income and distributable cash flow for years to come. In addition, we are very pleased with the acquisition of the Chesapeake assets in the Granite Wash and our entrance into the liquids-rich Eagle Ford Shale through our strategic agreement with Newfield Exploration."
BUSINESS HIGHLIGHTS
Liberty:
-- In February 2013, the Partnership commenced operations of an additional 120 million cubic feet per day (MMcf/d) processing facility at the Mobley complex in Wetzel County, West Virginia. This facility is supported by long-term, fee-based agreements with EQT Corporation EQT +1.03% , Magnum Hunter Resources Corporation MHR +3.49% and other producers. With the completion of the second facility, total processing capacity at Mobley is 320 MMcf/d and in less than six months the utilization of the complex has increased to approximately 70 percent.
-- In May 2013, the Partnership commenced operations of Majorsville III, a 200 MMcf/d processing facility in Marshall County, West Virginia. Majorsville III is supported by long-term, fee-based agreements with Consol Energy, Inc. CNX +0.29% (CNX) and Noble Energy, Inc. NBL -1.21% . The facility will also provide additional processing capacity to Range Resources Corporation RRC +2.21% (Range), Chesapeake Energy Corporation CHK +0.16%(Chesapeake) and other producers prior to the completion of subsequent facilities. The Partnership's first two processing facilities are operating at approximately 90 percent utilization and with the addition of the third facility, total processing capacity of the Majorsville complex has increased to 470 MMcf/d.
-- In May 2013, the Partnership commenced operations of Sherwood II, a 200 MMcf/d processing facility in Doddridge County, West Virginia. Sherwood II is supported by long-term, fee-based agreements with Antero Resources (Antero). The Partnership's first 200 MMcf/d facility is operating near full capacity in just over six months and the completion of the second facility brings total processing capacity at the Sherwood complex to 400 MMcf/d.
Utica:
-- In February 2013, the Partnership, together with EMG, completed an Amended and Restated Limited Liability Company Agreement (Amended LLC Agreement) for MarkWest Utica EMG. The Amended LLC Agreement increases EMG's capital commitment to MarkWest Utica EMG from $500 million to $950 million. The transaction provides the Partnership with flexibility in the timing of future capital contributions to MarkWest Utica EMG and accelerates the continued development of critical midstream infrastructure in the highly prospective Utica Shale.
-- In February 2013, MarkWest Utica EMG announced the execution of definitive agreements with Rex Energy Corporation REXX -0.30% (Rex) to provide gathering, processing, fractionation, and marketing services in the Utica Shale. MarkWest Utica EMG expects to begin providing the full-suite of midstream services for Rex by the end of the second quarter of 2013.
-- In March 2013, MarkWest Utica EMG announced the execution of definitive agreements with PDC Energy, Inc. PDCE -1.90% (PDC) to provide gathering, processing, fractionation, and marketing services in the Utica Shale. MarkWest Utica EMG expects to begin providing the full-suite of midstream services for PDC by the end of the second quarter of 2013.
-- In May 2013, MarkWest Utica EMG announced the execution of definitive agreements with CNX and an additional producer to provide processing, fractionation, and marketing services in the Utica Shale.
-- In May 2013, MarkWest Utica EMG is commencing operations of Cadiz I, a 125 MMcf/d cryogenic processing facility in Harrison County, Ohio. Cadiz I is supported by fee-based agreements with Gulfport Energy Corporation GPOR -1.94% , Antero and other producers.
Southwest:
-- Today, the Partnership announced the execution of definitive agreements to acquire 100% of the ownership interests of midstream assets in the Texas Panhandle and Western Oklahoma from a wholly owned subsidiary of Chesapeake for consideration of $245 million in cash. In conjunction with the acquisition, the Partnership has executed long-term, fee-based agreements with Chesapeake for gas gathering and processing services. As part of the gas processing agreement, Chesapeake has dedicated to the Partnership approximately 130,000 acres throughout the Anadarko Basin. The transaction is immediately accretive and the Partnership expects it to contribute $30 million to EBITDA for the full-year 2014.
-- In May 2013, the Partnership announced the execution of long-term fee-based agreement with Newfield Exploration NFX +0.31% (Newfield) to acquire and develop rich-gas gathering facilities in the Eagle Ford Shale. The Partnership will construct additional gathering pipelines, field compression, and liquids storage to support production from Newfield's West Asherton project in Dimmit County, Texas. The Partnership plans capital investment of approximately $50 million to support Newfield's development plans.
Capital Markets
-- In January 2013, the Partnership completed a public offering of $1.0 billion of 4.50% senior unsecured notes priced at par due in 2023. A portion of the net proceeds of approximately $986.0 million, together with cash on hand resulting in part from recent equity offerings, was used to fund the redemption of all of its outstanding 8.75% senior notes due 2018, and a portion of its 6.50% senior notes due 2021 and 6.25% senior notes due 2022, with the balance of such proceeds to be used to fund the Partnership's capital expenditure program and for general partnership purposes.
-- During the first quarter of 2013, the Partnership offered 1.9 million units and received net proceeds of approximately $103.9 million under the continuous offering program that was launched in the fourth quarter of 2012.
FINANCIAL RESULTS
Balance Sheet
-- As of March 31, 2013, the Partnership had $502.3 million of cash and cash equivalents in wholly owned subsidiaries and $1.19 billion remaining capacity under its $1.2 billion revolving credit facility after consideration of $11.3 million of outstanding letters of credit.
Operating Results
-- Operating income before items not allocated to segments for the three months ended March 31, 2013, was $163.1 million, a decrease of $31.1 million when compared to segment operating income of $194.2 million over the same period in 2012. This decrease was primarily attributable to lower commodity prices compared to the prior year quarter. Processed volumes continued to remain strong, growing approximately 40 percent when compared to the first quarter of 2012, primarily due to the Partnership's Liberty Segment and East Texas operations. 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 gains (losses) on commodity derivative instruments. Realized gains (losses) on commodity derivative instruments were $1.8 million in the first quarter of 2013 and ($17.6) million in the first quarter of 2012.
Capital Expenditures
-- For the three months ended March 31, 2013, the Partnership's portion of capital expenditures was $366.2 million.
2013 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST
For 2013, the Partnership's forecast for DCF has been narrowed to a range of $500 million to $540 million based on its current forecast of operational volumes and revised prices for crude oil, natural gas and natural gas liquids; and derivative instruments currently 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 unchanged and remains in a range of $1.5 billion to $1.8 billion. These expenditures do not include the Granite Wash acquisition cost of $245 million.
CONFERENCE CALL
The Partnership will host a conference call and webcast on Thursday, May 9, 2013, at 12:00 p.m. Eastern Time to review its first quarter 2013 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 (888) 402-8736 (no passcode required).
MarkWest Energy Partners, L.P. is a master limited partnership engaged in the gathering, processing and transportation of natural gas; the gathering, transportation, fractionation, storage and marketing of natural gas liquids; and the gathering and transportation of crude oil. MarkWest has a leading presence in many unconventional gas plays including the Marcellus Shale, Utica Shale, Huron/Berea Shale, Haynesville Shale, Woodford Shale and Granite Wash formation.
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, 2012 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2013. 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 March 31,
-------------------------------------
Statement of Operations Data 2013 2012
------------------ ------------------
Revenue:
Revenue $ 376,137 $ 399,181
Derivative loss (185) (48,715)
--------- - --------- -
Total revenue 375,952 350,466
--------- ---------
Operating expenses:
Purchased product costs 152,557 154,555
Derivative (gain) loss related to purchased product costs (10,704) 18,800
Facility expenses 59,755 48,840
Derivative gain related to facility expenses (332) (1,746)
Selling, general and administrative expenses 25,408 25,224
Depreciation 69,597 41,145
Amortization of intangible assets 14,830 10,985
Loss on disposal of property, plant and equipment 138 986
Accretion of asset retirement obligations 353 238
--------- ---------
Total operating expenses 311,602 299,027
--------- ---------
Income from operations 64,350 51,439
Other (expense) income:
Loss from unconsolidated affiliate (85) (9)
Interest income 149 72
Interest expense (38,336) (29,472)
Amortization of deferred financing costs and discount (a component (1,830) (1,270)
of interest expense)
Loss on redemption of debt (38,455) -
Miscellaneous income, net - 58
--------- ---------
(Loss) income before provision for income tax (14,207) 20,818
Provision for income tax (benefit) expense:
Current (5,414) 15,341
Deferred 11,971 (10,796)
--------- --------- -
Total provision for income tax 6,557 4,545
--------- ---------
Net (loss) income (20,764) 16,273
Net loss (income) attributable to non-controlling interest 5,304 (253)
Net (loss) income attributable to the Partnership's unitholders $ (15,460) $ 16,020
===== ========= = ===== =========
Net (loss) income attributable to the Partnership's common
unitholders per common unit:
Basic $ (0.12) $ 0.16
===== ========= = ===== =========
Diluted $ (0.12) $ 0.14
===== ========= = ===== =========
Weighted average number of outstanding common units:
Basic 128,615 96,840
========= =========
Diluted 128,615 117,593
========= =========
Cash Flow Data
Net cash flow provided by (used in):
Operating activities $ 85,043 $ 207,913
Investing activities $ (609,361) $ (252,969)
Financing activities $ 830,589 $ 278,674
Other Financial Data
Distributable cash flow $ 110,194 $ 109,177
Adjusted EBITDA $ 140,810 $ 153,140
Balance Sheet Data March 31, 2013 December 31, 2012
------------------ ------------------
Working capital $ 173,419 $ (82,587)
Total assets 7,720,554 6,835,716
Total debt 3,022,521 2,523,051
Total equity 3,240,300 3,215,591
MarkWest Energy Partners, L.P.
Operating Statistics
Three months ended March 31,
-----------------------------
2013 2012
--------- -----------------
Liberty
Gathering system throughput (Mcf/d) 605,400 308,100
Natural gas processed (Mcf/d) 828,100 392,100
NGLs fractionated (Bbl/d) 37,000 20,000
NGL sales (gallons, in thousands) (1) 145,900 97,500
Utica (2)
Gathering system throughput (Mcf/d) 9,000 N/A
Natural gas processed (Mcf/d) 7,900 N/A
Northeast
Natural gas processed (Mcf/d) 302,600 321,700
NGLs fractionated (Bbl/d) 17,100 16,700
Keep-whole sales (gallons, in thousands) 37,400 49,500
Percent-of-proceeds sales (gallons, in thousands) 34,900 33,000
--------- -----------------
Total NGL sales (gallons, in thousands) 72,300 82,500
Crude oil transported for a fee (Bbl/d) 10,300 10,400
Southwest
East Texas gathering systems throughput (Mcf/d) 500,300 410,000
East Texas natural gas processed (Mcf/d) 339,500 242,500
East Texas NGL sales (gallons, in thousands) 80,600 63,400
Western Oklahoma gathering system throughput (Mcf/d) (3) 202,600 262,000
Western Oklahoma natural gas processed (Mcf/d) 186,300 203,800
Western Oklahoma NGL sales (gallons, in thousands) 54,800 57,300
Southeast Oklahoma gathering system throughput (Mcf/d) 461,300 501,200
Southeast Oklahoma natural gas processed (Mcf/d) (4) 151,200 101,700
Southeast Oklahoma NGL sales (gallons, in thousands) 39,300 33,000
Arkoma Connector Pipeline throughput (Mcf/d) 273,800 328,700
Other Southwest gathering system throughput (Mcf/d) (5) 20,600 25,000
Gulf Coast refinery off-gas processed (Mcf/d) 95,300 120,300
Gulf Coast liquids fractionated (Bbl/d) 17,200 23,400
Gulf Coast NGL sales (gallons excluding hydrogen, in thousands) 65,100 89,300
(1) Includes sale of all purity products fractionated at the Liberty
facilities and sale of all unfractionated NGLs.
(2) Utica operations began in August 2012.
(3) Includes natural gas gathered in Western Oklahoma and from the
Granite Wash formation in the Texas Panhandle as management
considers this one integrated area of operations.
(4) The natural gas processing in Southeast Oklahoma is outsourced to
Centrahoma or other third party processors.
(5) Excludes lateral pipelines where revenue is not based on throughput.
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, 2013 Southwest Northeast Liberty Utica Total
------------------ ------------------ ------------ --------------- ------------
Revenue $ 211,446 $ 57,336 $ 108,497 $ 623 $ 377,902
Operating expenses:
Purchased product costs 114,102 19,662 18,793 - 152,557
Facility expenses 29,123 6,524 22,636 3,962 62,245
------- ------- ------- ------ -------
Total operating expenses before items not allocated to segments 143,225 26,186 41,429 3,962 214,802
Portion of operating income (loss) attributable to non-controlling 1,387 - - (1,339) 48
interests
------- ------- ------- ------ --- -------
Operating income (loss) before items not allocated to segments $ 66,834 $ 31,150 $ 67,068 $ (2,000) $ 163,052
==== ======= ==== ======= === ======= === ====== === === =======
Three months ended March 31, 2012 Southwest Northeast Liberty Utica Total
------------------ ------------------ ------------ --------------- ------------
Revenue $ 238,954 $ 86,918 $ 75,577 $ - $ 401,449
Operating expenses:
Purchased product costs 104,233 25,687 24,635 - 154,555
Facility expenses 32,630 6,378 12,247 - 51,255
------- ------- ------- ------ -------
Total operating expenses before items not allocated to segments 136,863 32,065 36,882 - 205,810
Portion of operating income attributable to non-controlling interests 1,446 - - - 1,446
------- ------- ------- ------ -------
Operating income before items not allocated to segments $ 100,645 $ 54,853 $ 38,695 $ - $ 194,193
==== ======= ==== ======= === ======= === ====== === =======
Three months ended March 31,
-------------------------------------
2013 2012
------------------ ------------------
Operating income before items not allocated to segments $ 163,052 $ 194,193
Portion of operating income attributable to non-controlling interests 48 1,446
Derivative gain (loss) not allocated to segments 10,851 (65,769)
Revenue deferral adjustment (1,765) (2,268)
Compensation expense included in facility expenses not allocated to (387) (449)
segments
Facility expenses adjustments 2,877 2,864
Selling, general and administrative expenses (25,408) (25,224)
Depreciation (69,597) (41,145)
Amortization of intangible assets (14,830) (10,985)
Loss on disposal of property, plant and equipment (138) (986)
Accretion of asset retirement obligations (353) (238)
------- ---- ------- ----
Income from operations 64,350 51,439
Other income (expense):
Loss from unconsolidated affiliate (85) (9)
Interest income 149 72
Interest expense (38,336) (29,472)
Amortization of deferred financing costs and discount (a component (1,830) (1,270)
of interest expense)
Loss on redemption of debt (38,455) -
Miscellaneous income, net - 58
------- -------
(Loss) income before provision for income tax $ (14,207) $ 20,818
==== ======= ==== ==== =======
Reconciliation of GAAP Financial Measure to Non-GAAP Financial
Measure
Distributable Cash Flow
(unaudited, in thousands)
Three months ended March 31,
------------------------------------
2013 2012
------------------ -----------------
Net (loss) income $ (20,764) $ 16,273
Depreciation, amortization, impairment, and other non-cash operating 84,996 53,432
expenses
Loss on redemption of debt, net of tax benefit 36,178 -
Amortization of deferred financing costs and discount 1,830 1,270
Non-cash loss from unconsolidated affiliate 85 9
Distributions from unconsolidated affiliate - 900
Non-cash compensation expense 2,384 2,710
Non-cash derivative activity (9,033) 48,217
Provision for income tax - deferred 11,971 (10,796)
Cash adjustment for non-controlling interest of consolidated 633 (1,017)
subsidiaries
Revenue deferral adjustment 1,765 2,268
Other 2,040 2,208
Maintenance capital expenditures, net of joint venture partner (1,891) (6,297)
contributions
-------- - ------- -
Distributable cash flow $ 110,194 $ 109,177
====== ======== ====== =======
Maintenance capital expenditures $ 1,891 $ 6,297
Growth capital expenditures 629,667 247,966
-------- -------
Total capital expenditures 631,558 254,263
Acquisitions, net of cash acquired - -
-------- -------
Total capital expenditures and acquisitions 631,558 254,263
Joint venture partner contributions (265,320) -
-------- - -------
Total capital expenditures and acquisitions, net $ 366,238 $ 254,263
====== ======== ====== =======
Distributable cash flow $ 110,194 $ 109,177
Maintenance capital expenditures, net of joint venture partner 1,891 6,297
contributions
Changes in receivables and other assets 1,109 57,655
Changes in accounts payable, accrued liabilities and other long-term (27,608) 35,244
liabilities
Cash adjustment for non-controlling interest of consolidated (633) 1,017
subsidiaries
Other 90 (1,477)
-------- ------- -
Net cash provided by operating activities $ 85,043 $ 207,913
====== ======== ====== =======
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,
-----------------------------------
2013 2012
----------------- -----------------
Net (loss) income $ (20,764) $ 16,273
Non-cash compensation expense 2,384 2,710
Non-cash derivative activity (9,033) 48,217
Interest expense (1) 38,022 28,552
Depreciation, amortization, impairment, and other non-cash operating 84,996 53,432
expenses
Loss on redemption of debt 38,455 -
Provision for income tax 6,557 4,545
Adjustment for cash flow from unconsolidated affiliate 85 909
Other 108 (1,498)
------- ------- -
Adjusted EBITDA $ 140,810 $ 153,140
====== ======= ====== =======
(1) Includes amortization of deferred financing costs and discount, and
excludes interest expense related to the Steam Methane Reformer.
MarkWest Energy Partners, L.P.
Distributable Cash Flow Sensitivity Analysis
(unaudited, in millions)
MarkWest periodically estimates the effect on DCF resulting from its
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 55% for 2013.
b. NGL-to-crude oil ratio at 45% for 2013.
c. NGL-to-crude oil ratio at 35% for 2013.
The analysis further assumes derivative instruments outstanding as
of May 8, 2013, and production volumes estimated through December
31, 2013. The range of stated hypothetical changes in commodity
prices considers current and historic market performance.
Estimated Range of 2013 DCF
Natural Gas Price (Henry Hub)
--------------------------------------------
Crude Oil NGL-to-Crude $ 3.00 $ 3.50 $ 4.00 $ 4.50 $ 5.00
Price (WTI) oil ratio
----------- ------------ - ---- - ---- - ---- - ---- - ----
55% of WTI $ 568 $ 566 $ 564 $ 563 $ 561
------------ - ---- - ---- - ---- - ---- - ----
$110 45% of WTI $ 526 $ 524 $ 522 $ 520 $ 518
------------ - ---- - ---- - ---- - ---- - ----
35% of WTI $ 484 $ 483 $ 481 $ 479 $ 477
------------ - ---- - ---- - ---- - ---- - ----
55% of WTI $ 551 $ 549 $ 547 $ 546 $ 544
------------ - ---- - ---- - ---- - ---- - ----
$100 45% of WTI $ 512 $ 511 $ 509 $ 507 $ 505
------------ - ---- - ---- - ---- - ---- - ----
35% of WTI $ 475 $ 473 $ 471 $ 469 $ 468
------------ - ---- - ---- - ---- - ---- - ----
55% of WTI $ 531 $ 529 $ 527 $ 526 $ 524
------------ - ---- - ---- - ---- - ---- - ----
$90 45% of WTI $ 497 $ 495 $ 493 $ 491 $ 489
------------ - ---- - ---- - ---- - ---- - ----
35% of WTI $ 461 $ 459 $ 457 $ 455 $ 453
------------ - ---- - ---- - ---- - ---- - ----
55% of WTI $ 513 $ 512 $ 510 $ 508 $ 506
------------ - ---- - ---- - ---- - ---- - ----
$80 45% of WTI $ 484 $ 482 $ 480 $ 478 $ 476
------------ - ---- - ---- - ---- - ---- - ----
35% of WTI $ 451 $ 449 $ 447 $ 445 $ 442
------------ - ---- - ---- - ---- - ---- - ----
55% of WTI $ 501 $ 499 $ 497 $ 495 $ 493
------------ - ---- - ---- - ---- - ---- - ----
$70 45% of WTI $ 471 $ 469 $ 467 $ 466 $ 464
------------ - ---- - ---- - ---- - ---- - ----
35% of WTI $ 446 $ 443 $ 441 $ 438 $ 435
------------ - ---- - ---- - ---- - ---- - ----
(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."
http://cts.businesswire.com/ct/CT?id=bwnews&sty=20130508006760r1&sid=cmtx4&distro=nx
SOURCE: MarkWest Energy Partners, L.P.
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