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MarkWest Energy Partners Reports Third Quarter Financial Results and Increases Common Unit Distribution by 11 Percent
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DENVER--(BUSINESS WIRE)--Nov. 7, 2012-- MarkWest Energy Partners, L.P. (NYSE: MWE) (the Partnership) today reported quarterly cash available for distribution to common unitholders, or distributable cash flow (DCF), of $104.3 million for the three months ended September 30, 2012, and $304.6 million for the nine months ended September 30, 2012. Distributable cash flow for the three months ended September 30, 2012, represents distribution coverage of 109 percent. The third quarter distribution of $95.3 million, or $0.81 per common unit, will be paid to unitholders on November 14, 2012. The third quarter 2012 distribution represents an increase of $0.01 per common unit, or 1.3 percent, over the second quarter 2012 distribution and an increase of $0.08 per common unit, or 11.0 percent, over the third quarter 2011 distribution. As a Master Limited Partnership, cash distributions to common unitholders are largely determined based on DCF. A reconciliation of DCF to net income, the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.

The Partnership reported Adjusted EBITDA for the three and nine months ended September 30, 2012, of $108.2 million and $371.7 million, respectively, as compared to $107.0 million and $323.2 million for the three and nine months ended September 30, 2011. The Partnership believes the presentation of Adjusted EBITDA provides useful information because it is commonly used by investors in Master Limited Partnerships to assess financial performance and operating results of ongoing business operations. A reconciliation of Adjusted EBITDA to net income, the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.

The Partnership reported (loss) income before provision for income tax for the three and nine months ended September 30, 2012, of $(22.2) million and $230.3 million, respectively. (Loss) income before provision for income tax includes non-cash (loss) gain associated with the change in mark-to-market of derivative instruments of $(43.7) million and $101.8 million for the three and nine months ended September 30, 2012, respectively. Excluding these items, income before provision for income tax for the three and nine months ended September 30, 2012, would have been $21.5 million and $128.5 million, respectively.

“Our organic growth strategy continues to deliver solid financial results and significant opportunities for future expansion and capital investment,” said Frank Semple, Chairman, President and Chief Executive Officer. “MarkWest’s diverse set of assets and focus on delivering high quality customer service resulted in year over year volume increases of over 20% and 11% distribution growth. In addition, our ongoing development in the Marcellus Shale and the Utica Shale continues to provide critical midstream infrastructure for our producer customers’ drilling programs and provides a significant inventory of future growth projects.”

BUSINESS HIGHLIGHTS

Business Development

  • Liberty: In July 2012, the Partnership announced a new long-term, fee-based agreement with XTO Energy (XTO) to transport, fractionate and market natural gas liquids (NGLs) from their 125 million cubic feet per day (MMcf/d) processing plant located in Butler County, Pennsylvania. NGLs will initially be transported by truck from XTO’s plant to the Houston fractionation and marketing complex in Washington County, Pennsylvania. By the end of 2013, an extension of the Partnership’s NGL gathering pipeline into northwest Pennsylvania is expected to be complete, which will connect the Keystone complex and XTO facility to the Houston complex.

    In September 2012, the Partnership announced a 10-year agreement to become a firm shipper on the Mariner East pipeline project (“Mariner East”) subject to final regulatory approvals. Mariner East is currently designed to transport ethane and propane sourced at the Partnership’s Houston complex to Sunoco, Inc’s Marcus Hook facility located near Philadelphia, Pennsylvania. Once delivered, the ethane-propane mix will be re-fractionated into purity products for sale to domestic and international markets.

    During the third quarter, the Partnership continued to transport propane from the Houston fractionation complex to Marcus Hook for delivery to international markets. Since the commencement of propane exports in July 2012, the Partnership has marketed over 900,000 barrels. Total propane volumes loaded onto ships at Marcus Hook include the Partnership’s volume and purchased product sourced at Sunoco’s local-area facilities. The Partnership anticipates the continuation of exports from Marcus Hook as long as it is economically possible for our producer customers to capture premium prices that currently exist in the international markets.

    In October 2012, the Partnership commenced operations of the 200 MMcf/d Sherwood I processing facility and associated gathering and compression in Doddridge County, West Virginia. These assets are supported by a long-term, fee-based agreement with Antero Resources. The initiation of Sherwood operations represents the first phase of the Partnership’s development of midstream infrastructure in Doddridge County. The Partnership expects the Sherwood II facility, a 200 MMcf/d cryogenic processing plant, to be operational in the second quarter of 2013.

    In November 2012, the Partnership announced plans to further expand the processing capacity at its Mobley complex in Wetzel County, West Virginia by 200 MMcf/d. This expansion is supported by an existing long-term, fee-based agreement with EQT Corporation and is expected to be completed in the fourth quarter of 2013.
  • Utica: In November 2012, MarkWest Utica EMG, LLC (MarkWest Utica) a joint venture between MarkWest and The Energy and Minerals Group, announced the execution of definitive agreements with Antero Resources to provide gas processing, fractionation and marketing services in Noble County, Ohio. Under long-term, fee-based agreements, MarkWest Utica will initially bring online an interim 45 MMcf/d refrigeration processing plant at its Seneca processing complex, with an expected second quarter of 2013 completion date. This interim facility will be followed by Seneca I, a 200 MMcf/d cryogenic gas processing facility, which is expected to begin operations by the third quarter of 2013. The definitive agreements contemplate the construction of additional facility, Seneca II, a 200 MMcf/d cryogenic processing facility, which may be installed as soon as the end of 2013. In addition to its Seneca processing complex, MarkWest Utica will construct an NGL gathering system to its Cadiz processing complex and then on to the Harrison County, Ohio fractionation and marketing complex. The Cadiz complex will include a de-ethanization facility where purity ethane will be produced and delivered into the ATEX ethane pipeline. The propane and heavier natural gas liquids will then flow via pipeline to the Harrison County fractionator for further separation into purity products. The completion of the NGL gathering system and fractionation will provide Antero Resources direct market access to the planned ethane and propane pipeline projects in the northeast.
  • Northeast: In October 2012, the Partnership commenced operations of its 150 MMcf/d Langley processing plant expansion supporting producers’ gas development in the Huron/Berea Shale. This expansion increases the Partnership’s total processing capacity in the Northeast Segment to 655 MMcf/d and further expands the Partnership’s position as the largest natural gas processor in the Appalachian Basin.
  • Southwest: In September 2012, Centrahoma Processing, LLC a joint venture between MarkWest and Cardinal Midstream, LLC in Southeast Oklahoma agreed to construct a 120 MMcf/d processing plant expansion in order to support drilling programs in the Woodford Shale. The plant is expected to be operational in the fourth quarter of 2013.

Capital Markets

  • On August 10, 2012, the Partnership completed a public offering of $750 million aggregate principal amount of 5.5% senior unsecured notes due 2023 issued at 99.015% of par. The aggregate net proceeds of approximately $731 million were used to repay borrowings under the Partnership’s revolving credit facility, to partially fund the Partnership’s capital expenditure program and for other general partnership purposes.
  • On August 17, 2012, the Partnership completed a common unit equity offering of 6.9 million common units. The net proceeds of approximately $338 million were used to partially fund the Partnership’s capital expenditure program and for other general partnership purposes.

FINANCIAL RESULTS

Balance Sheet

  • At September 30, 2012, the Partnership had $411.5 million of cash and cash equivalents in wholly owned subsidiaries and $1.18 billion available for borrowing under its $1.2 billion revolving credit facility after consideration of $21.6 million of outstanding letters of credit.

Operating Results

  • Operating income before items not allocated to segments for the three months ended September 30, 2012, was $145.5 million, a decrease of $2.3 million when compared to segment operating income of $147.8 million over the same period in 2011. This decrease was primarily attributable to lower commodity prices compared to the prior year quarter. Processed volumes continued to remain strong, growing over 20 percent when compared to the third quarter of 2011, primarily due to the Partnership’s Liberty and Southwest segments.

    A reconciliation of operating income before items not allocated to segments to income (loss) before provision for income tax, the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.
  • Operating income before items not allocated to segments does not include loss on commodity derivative instruments. Realized losses on commodity derivative instruments were $8.4 million in the third quarter of 2012 and $15.8 million in the third quarter of 2011.

Capital Expenditures

  • For the three and nine months ended September 30, 2012, the Partnership’s portion of capital expenditures was $603.7 million and $1,185.9 million, respectively. These expenditures do not include the Keystone purchase price of $509.6 million.

2012 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

For 2012, the Partnership forecasts DCF in a range of $410 million to $430 million based on its current forecast of operational volumes and prices for crude oil, natural gas and natural gas liquids; derivative instruments currently outstanding; and the Keystone acquisition, as mentioned above. The midpoint of this range results in approximately 117 percent coverage of the Partnership’s full-year distribution based on current quarterly distributions and common units outstanding.

The Partnership’s portion of growth capital expenditures for 2012 has increased primarily due to accelerated spending on key expansion projects in the Marcellus Shale, and is forecasted to be approximately $1.8 billion. This range excludes the Keystone purchase price of $509.6 million.

2013 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

For 2013, the Partnership forecasts DCF in a range of $500 million to $575 million based on its current forecast of operational volumes and prices for crude oil, natural gas and natural gas liquids; and derivative instruments currently outstanding. The midpoint of this range results in approximately 141 percent coverage of the Partnership’s full-year distribution based on current quarterly distributions and common units outstanding. A commodity price sensitivity analysis for forecasted 2013 DCF is provided within the tables of this press release.

The Partnership’s portion of growth capital expenditures for 2013 is forecasted in a range of $1.4 billion to $1.9 billion.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Thursday, November 8, 2012, at 12:00 p.m. Eastern Time to review its third quarter 2012 financial results. Interested parties can participate in the call by dialing (800) 475-0218 (passcode “MarkWest”) approximately ten minutes prior to the scheduled start time. To access the webcast, please visit the Investor Relations section of the Partnership’s website at www.markwest.com. A replay of the conference call will be available on the MarkWest website or by dialing (866) 495-9346 (no passcode required).

MarkWest Energy Partners, L.P. is a master limited partnership engaged in the gathering, transportation, and processing of natural gas; the transportation, fractionation, marketing, and storage of natural gas liquids; and the gathering and transportation of crude oil. MarkWest has extensive natural gas gathering, processing, and transmission operations in the southwest, Gulf Coast, and northeast regions of the United States, including the Marcellus Shale, and is the largest natural gas processor and fractionator in the Appalachian region.

This press release includes “forward-looking statements.” All statements other than statements of historical facts included or incorporated herein may constitute forward-looking statements. Actual results could vary significantly from those expressed or implied in such statements and are subject to a number of risks and uncertainties. Although MarkWest believes that the expectations reflected in the forward-looking statements are reasonable, MarkWest can give no assurance that such expectations will prove to be correct. The forward-looking statements involve risks and uncertainties that affect operations, financial performance, and other factors as discussed in filings with the Securities and Exchange Commission (SEC). Among the factors that could cause results to differ materially are those risks discussed in the periodic reports filed with the SEC, including MarkWest’s Annual Report on Form 10-K for the year ended December 31, 2011 and its Quarterly Reports on Form 10-Q for the quarters ended March 31, 2012, June 30, 2012 and September 30, 2012. You are urged to carefully review and consider the cautionary statements and other disclosures made in those filings, specifically those under the heading “Risk Factors.” MarkWest does not undertake any duty to update any forward-looking statement except as required by law.

 

MarkWest Energy Partners, L.P.
Financial Statistics
(unaudited, in thousands, except per unit data)

         
Three months ended September 30, Nine months ended September 30,
Statement of Operations Data 2012 2011 2012 2011
Revenue:
Revenue $ 320,137 $ 400,883 $ 1,029,304 $ 1,109,632
Derivative (loss) gain   (36,400 )   106,943     50,952     61,854  
Total revenue   283,737     507,826     1,080,256     1,171,486  
 
Operating expenses:
Purchased product costs 119,369 189,284 386,655 497,493
Derivative loss (gain) related to purchased product costs 11,643 (1,274 ) (21,136 ) 17,866
Facility expenses 53,293 44,236 150,671 124,358
Derivative loss (gain) related to facility expenses 4,028 (2,787 ) 1,136 (2,871 )
Selling, general and administrative expenses 21,922 20,162 69,025 60,454
Depreciation 48,136 38,715 132,199 110,280
Amortization of intangible assets 14,988 10,985 38,280 32,632
Loss on disposal of property, plant and equipment 655 147 2,983 4,619
Accretion of asset retirement obligations   141     557     540     934  
Total operating expenses   274,175     300,025     760,353     845,765  
 
Income from operations 9,562 207,801 319,903 325,721
 
Other income (expense):
Earnings (loss) from unconsolidated affiliates 246 (507 ) 788 (1,262 )
Interest income 64 62 295 214
Interest expense (30,621 ) (26,899 ) (86,855 ) (83,036 )
Amortization of deferred financing costs and discount (a component of interest expense) (1,428 ) (1,002 ) (3,943 ) (3,873 )
Loss on redemption of debt - (133 ) - (43,461 )
Miscellaneous income (expense), net   1     (4 )   63     127  
(Loss) Income before provision for income tax (22,176 ) 179,318 230,251 194,430
 
Provision for income tax (benefit) expense:
Current (17,948 ) 3,959 2,202 8,104
Deferred   10,528     21,905     39,396     18,338  
Total provision for income tax   (7,420 )   25,864     41,598     26,442  
 
Net (loss) income (14,756 ) 153,454 188,653 167,988
 
Net loss (income) attributable to non-controlling interest 416 (13,142 ) (65 ) (33,208 )
       
Net (loss) income attributable to the Partnership $ (14,340 ) $ 140,312   $ 188,588   $ 134,780  
 
Net (loss) income attributable to the Partnership's common unitholders per common unit:
Basic $ (0.13 ) $ 1.77   $ 1.77   $ 1.75  
Diluted $ (0.13 ) $ 1.77   $ 1.49   $ 1.75  
 
Weighted average number of outstanding common units:
Basic   113,994     78,619     105,916     76,118  
Diluted   113,994     78,760     126,595     76,276  
 
Cash Flow Data
Net cash flow provided by (used in):
Operating activities $ 133,281 $ 124,885 $ 389,718 $ 331,249
Investing activities $ (658,573 ) $ (125,637 ) $ (1,746,071 ) $ (587,686 )
Financing activities $ 814,894 $ 64,894 $ 1,654,401 $ 348,164
 
Other Financial Data
Distributable cash flow $ 104,289 $ 85,311 $ 304,649 $ 244,391
Adjusted EBITDA $ 108,180 $ 107,013 $ 371,655 $ 323,204
 
Balance Sheet Data September 30, 2012 December 31, 2011
Working capital $ (17,336 ) $ 4,234
Total assets 6,237,143 4,070,425
Total debt 2,522,854 1,846,062
Total equity $ 2,620,940 $ 1,502,067
 
MarkWest Energy Partners, L.P.
Operating Statistics
       
Three months ended September 30, Nine months ended September 30,
2012 2011 2012 2011
Southwest
East Texas gathering systems throughput (Mcf/d) 471,200 417,400 440,700 423,800
East Texas natural gas processed (Mcf/d) 270,200 229,700 260,400 226,000
East Texas NGL sales (gallons, in thousands) 67,800 59,000 199,300 175,200
 
Western Oklahoma gathering system throughput (Mcf/d) (1) 227,900 241,300 247,300 224,400
Western Oklahoma natural gas processed (Mcf/d) 209,600 153,200 210,800 156,600
Western Oklahoma NGL sales (gallons, in thousands) 50,900 37,000 169,900 111,100
 
Southeast Oklahoma gathering system throughput (Mcf/d) 484,400 512,600 496,200 507,500
Southeast Oklahoma natural gas processed (Mcf/d) (2) 128,600 105,400 116,700 103,100
Southeast Oklahoma NGL sales (gallons, in thousands) 46,700 30,600 121,000 92,100
Arkoma Connector Pipeline throughput (Mcf/d) 310,400 298,600 323,400 294,300
 
Other Southwest gathering system throughput (Mcf/d) 23,600 29,900 25,000 31,500
 
Northeast
Natural gas processed (Mcf/d) (3) 318,500 277,400 322,800 300,700
NGLs fractionated (Bbl/d) (4) 16,500 19,300 16,800 21,400
 
Keep-whole sales (gallons, in thousands) 23,200 21,700 96,500 82,600
Percent-of-proceeds sales (gallons, in thousands) 33,700 31,600 103,500 95,600
Total NGL sales (gallons, in thousands) (5) 56,900 53,300 200,000 178,200
 
Crude oil transported for a fee (Bbl/d) 8,700 9,900 9,100 10,500
 
Liberty
Natural gas processed (Mcf/d) 479,400 366,200 424,300

306,700

Gathering system throughput (Mcf/d) 444,700 258,300 373,700 228,900
NGLs fractionated (Bbl/d) (6) 22,300 12,400 20,700 9,300
NGL sales (gallons, in thousands) (7) 90,800 61,100 264,200 163,500
 
Gulf Coast
Refinery off-gas processed (Mcf/d) 123,800 122,000 120,000 113,200
Liquids fractionated (Bbl/d) 23,800 23,100 23,000 21,400
NGL sales (gallons excluding hydrogen, in thousands) 92,100 89,200 264,400 245,500
(1)   Includes natural gas gathered in Western Oklahoma and from the Granite Wash formation in the Texas Panhandle as it is one integrated area of operations.
 
(2) The natural gas processing in Southeast Oklahoma is outsourced to Centrahoma, our equity investment, or other third-party processors.
 
(3) Includes throughput from the Kenova, Cobb, Boldman and Langley processing plants. We acquired the Langley processing plants in February 2011. The volumes reported for the nine months ended September 30, 2011 are the average daily rates for the days of operation.
 
(4) Amount includes zero barrels per day and 4,400 barrels per day fractionated on behalf of Liberty for the three months ended September 30, 2012 and 2011, respectively and includes zero barrels per day and 5,100 barrels per day fractionated on behalf of Liberty for the nine months ended September 30, 2012 and 2011, respectively. Beginning in the fourth quarter of 2011, Siloam no longer fractionates NGLs on behalf of Liberty due to the operation of Liberty’s fractionation facility that began in September 2011, except during outages or force majeure events.
 
(5) Represents sales from the Siloam facilities. The total sales exclude approximately 600,000 gallons and 17,100,000 gallons sold by the Northeast on behalf of Liberty for the three months ended September 30, 2012 and 2011, respectively and 975,000 gallons and 58,600,000 gallons sold for the nine months ended September 30, 2012 and 2011, respectively. These volumes are included as part of NGLs sold at Liberty.
 
(6) Amount includes all NGLs that were produced at the Liberty processing facilities and fractionated into purity products at our Liberty fractionation facility.
 
(7) Includes sale of all purity products fractionated at the Liberty facilities and sale of all unfractionated NGLs. Also includes the sale of purity products fractionated and sold from the Siloam facilities on behalf of Liberty.
 
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Operating Income before Items not Allocated to Segments
(unaudited, in thousands)
         
Three months ended September 30, 2012 Southwest Northeast Liberty Gulf Coast Total
Revenue $ 181,456 $ 39,987 $ 78,852 $ 21,477 $ 321,772
 
Operating expenses:
Purchased product costs 92,112 11,054 16,203 - 119,369
Facility expenses   20,527     6,267     20,241     8,928   55,963
Total operating expenses before items not allocated to segments 112,639 17,321 36,444 8,928 175,332
 
Portion of operating income attributable to non-controlling interests   1,543     -     (627 )   -   916
Operating income before items not allocated to segments $ 67,274   $ 22,666   $ 43,035   $ 12,549 $ 145,524
 
 
Three months ended September 30, 2011 Southwest Northeast Liberty Gulf Coast Total
Revenue $ 241,998 $ 55,920 $ 78,586 $ 26,868 $ 403,372
 
Operating expenses:
Purchased product costs 141,067 15,947 32,270 - 189,284
Facility expenses   21,043     6,879     9,108     9,798   46,828
Total operating expenses before items not allocated to segments 162,110 22,826 41,378 9,798 236,112
 
Portion of operating income attributable to non-controlling interests   1,227     -     18,223     -   19,450
Operating income before items not allocated to segments $ 78,661   $ 33,094   $ 18,985   $ 17,070 $ 147,810
 
 

Three months ended September 30,

2012 2011
 
Operating income before items not allocated to segments $ 145,524 $ 147,810
Portion of operating income attributable to non-controlling interests 916 19,450
Derivative (loss) gain not allocated to segments (52,071 ) 111,004
Revenue deferral adjustment (1,635 ) (2,489 )
Compensation expense included in facility expenses not allocated to segments (193 ) (263 )
Facility expenses adjustments 2,863 2,855
Selling, general and administrative expenses (21,922 ) (20,162 )
Depreciation (48,136 ) (38,715 )
Amortization of intangible assets (14,988 ) (10,985 )
Loss on disposal of property, plant and equipment (655 ) (147 )
Accretion of asset retirement obligations   (141 )   (557 )
Income from operations 9,562 207,801
Other income (expense):
Earnings (loss) from unconsolidated affiliate 246 (507 )
Interest income 64 62
Interest expense (30,621 ) (26,899 )
Amortization of deferred financing costs and discount (a component of interest expense) (1,428 ) (1,002 )
Loss on redemption of debt - (133 )
Miscellaneous income (expense), net   1     (4 )
(Loss) Income before provision for income tax $ (22,176 ) $ 179,318  
 
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Operating Income before Items not Allocated to Segments
(unaudited, in thousands)
         
Nine months ended September 30, 2012 Southwest Northeast Liberty Gulf Coast Total
Revenue $ 585,343 $ 168,956 $ 213,906 $ 66,703 $ 1,034,908
 
Operating expenses:
Purchased product costs 288,137 49,662 48,856 - 386,655
Facility expenses   66,553     17,577     46,135     28,173   158,438
Total operating expenses before items not allocated to segments 354,690 67,239 94,991 28,173 545,093
 
Portion of operating income attributable to non-controlling interests   4,579     -     (740 )   -   3,839
Operating income before items not allocated to segments $ 226,074   $ 101,717   $ 119,655   $ 38,530 $ 485,976
 
 
Nine months ended September 30, 2011 Southwest Northeast Liberty Gulf Coast Total
Revenue $ 679,347 $ 201,687 $ 168,142 $ 73,310 $ 1,122,486
 
Operating expenses:
Purchased product costs 373,251 72,527 51,715 - 497,493
Facility expenses   62,055     19,402     22,875     27,100   131,432
Total operating expenses before items not allocated to segments 435,306 91,929 74,590 27,100 628,925
 
Portion of operating income attributable to non-controlling interests   3,745     -     45,782     -   49,527
Operating income before items not allocated to segments $ 240,296   $ 109,758   $ 47,770   $ 46,210 $ 444,034
 
 
Nine months ended September 30,
2012 2011
 
Operating income before items not allocated to segments $ 485,976 $ 444,034
Portion of operating income attributable to non-controlling interests 3,839 49,527
Derivative gain not allocated to segments 70,952 46,859
Revenue deferral adjustment (5,604 ) (12,854 )
Compensation expense included in facility expenses not allocated to segments (826 ) (1,491 )
Facility expenses adjustments 8,593 8,565
Selling, general and administrative expenses (69,025 ) (60,454 )
Depreciation (132,199 ) (110,280 )
Amortization of intangible assets (38,280 ) (32,632 )
Loss on disposal of property, plant and equipment (2,983 ) (4,619 )
Accretion of asset retirement obligations   (540 )   (934 )
Income from operations 319,903 325,721
Other income (expense):
Earnings (loss) from unconsolidated affiliate 788 (1,262 )
Interest income 295 214
Interest expense (86,855 ) (83,036 )
Amortization of deferred financing costs and discount (a component of interest expense) (3,943 ) (3,873 )
Loss on redemption of debt - (43,461 )
Miscellaneous income, net   63     127  
Income before provision for income tax $ 230,251   $ 194,430  
 
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Distributable Cash Flow
(unaudited, in thousands)
       
Three months ended September 30, Nine months ended September 30,
2012 2011 2012 2011
 
Net income $ (14,756 ) $ 153,454 $ 188,653 $ 167,988
Depreciation, amortization, impairment, and other non-cash operating expenses 63,998 50,482 174,236 148,699
Loss on redemption of debt, net of tax benefit - 119 - 39,618
Amortization of deferred financing costs and discount 1,428 1,002 3,943 3,873
Non-cash (earnings) loss from unconsolidated affiliate (246 ) 507 (788 ) 1,262
Distributions from unconsolidated affiliate 500 - 2,200 300
Non-cash compensation expense 981 995 6,270 3,707
Non-cash derivative activity 43,712 (126,802 ) (101,815 ) (102,681 )
Provision for income tax - deferred 10,528 21,905 39,396 18,338
Cash adjustment for non-controlling interest of consolidated subsidiaries (490 ) (18,227 ) (2,513 ) (46,285 )
Revenue deferral adjustment 1,635 2,489 5,604 12,854
Other 1,173 1,334 3,962 4,537
Maintenance capital expenditures, net of joint venture partner contributions   (4,174 )   (1,947 )   (14,499 )   (7,819 )
Distributable cash flow $ 104,289   $ 85,311   $ 304,649   $ 244,391  
 
Maintenance capital expenditures $ 4,174 $ 2,179 $ 14,499 $ 8,577
Growth capital expenditures   654,489     123,631     1,226,367       351,349  
Total capital expenditures 658,663 125,810 1,240,866 359,926
Acquisitions   -     -     506,797     230,728  
Total capital expenditures and acquisitions 658,663 125,810 1,747,663 590,654
Joint venture partner contributions   (55,000 )   (14,474 )   (55,000 )   (68,501 )
Total capital expenditures and acquisitions, net $ 603,663   $ 111,336   $ 1,692,663   $ 522,153  
 
Distributable cash flow $ 104,289 $ 85,311 $ 304,649 $ 244,391
Maintenance capital expenditures, net 4,174 1,947 14,499 7,819
Changes in receivables and other assets (85,436 ) (17,856 ) 26,946 (33,255 )
Changes in accounts payable, accrued liabilities and other long-term liabilities 110,559 38,405 45,368 69,372
Derivative instrument premium payments, net of amortization - 1,137 - 3,281
Cash adjustment for non-controlling interest of consolidated subsidiaries 490 18,227 2,513 46,285
Other   (795 )   (2,286 )   (4,257 )   (6,644 )
Net cash provided by operating activities $ 133,281   $ 124,885   $ 389,718   $ 331,249  
 
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Adjusted EBITDA
(unaudited, in thousands)
       
Three months ended September 30, Nine months ended September 30,
2012 2011 2012 2011
 
Net income $ (14,756 ) $ 153,454 $ 188,653 $ 167,988
Non-cash compensation expense 981 995 6,270 3,707
Non-cash derivative activity 43,712 (126,802 ) (101,815 ) (102,681 )
Interest expense (1) 29,882 25,687 84,260 80,235
Depreciation, amortization, impairment, and other non-cash operating expenses 63,998 50,482 174,236 148,699
Loss on redemption of debt - 133 - 43,461
Provision for income tax (7,420 ) 25,864 41,598 26,442
Adjustment for cash flow from unconsolidated affiliate 254 507 1,412 1,562
Adjustment related to non-guarantor, consolidated subsidiaries (2) (7,951 ) (22,713 ) (21,434 ) (44,819 )
Other   (520 )   (594 )   (1,525 )   (1,390 )
Adjusted EBITDA $ 108,180   $ 107,013   $ 371,655   $ 323,204  

(1)

 

Includes amortization of deferred financing costs and discount, and excludes interest expense related to the Steam Methane Reformer.

(2)

The non-guarantor subsidiaries, in accordance with Credit Facility covenants, are MarkWest Liberty Midstream & Resources, L.L.C. and its subsidiaries (Liberty), MarkWest Utica EMG L.L.C., MarkWest Pioneer, L.L.C., Wirth Gathering Partnership, and Bright Star Partnership. As of January 1, 2012, Liberty is a wholly owned subsidiary but remains a non-guarantor in accordance with the Credit Facility.

 

MarkWest Energy Partners, L.P.
Distributable Cash Flow Sensitivity Analysis
(unaudited, in millions)

MarkWest periodically estimates the effect on DCF resulting from its commodity risk management program, changes in crude oil and natural gas prices, and the ratio of NGL prices to crude oil. The table below reflects MarkWest’s estimate of the range of DCF for 2013 and forecasted crude oil and natural gas prices for 2013. The analysis assumes various combinations of crude oil and natural gas prices as well as three NGL-to-crude oil ratio scenarios, including:

a. NGL-to-crude oil ratio at 60% for 2013.
b. NGL-to-crude oil ratio at 50% for 2013.
c. NGL-to-crude oil ratio at 40% for 2013.

The analysis further assumes derivative instruments outstanding as of November 2, 2012, and production volumes estimated through December 31, 2013. The range of stated hypothetical changes in commodity prices considers current and historic market performance.

   
        Natural Gas Price (Henry Hub)

Crude Oil Price
(WTI)

 

NGL-to-Crude
oil ratio (1)

  $ 2.50     $ 3.00     $ 3.50     $ 4.00     $ 4.50
  60% of WTI   $ 699     $ 694     $ 689     $ 683     $ 678
$110 50% of WTI   $ 606     $ 601     $ 596     $ 591     $ 585
    40% of WTI   $ 517     $ 512     $ 507     $ 502     $ 496
60% of WTI   $ 668     $ 662     $ 657     $ 652     $ 647
$100 50% of WTI   $ 585     $ 580     $ 574     $ 569     $ 564
    40% of WTI   $ 504     $ 499     $ 494     $ 488     $ 483
60% of WTI   $ 634     $ 628     $ 623     $ 618     $ 613
$90 50% of WTI   $ 561     $ 556     $ 551     $ 545     $ 540
    40% of WTI   $ 488     $ 483     $ 478     $ 472     $ 467
60% of WTI   $ 611     $ 605     $ 600     $ 595     $ 590
$80 50% of WTI   $ 546     $ 541     $ 535     $ 530     $ 525
    40% of WTI   $ 481     $ 476     $ 470     $ 465     $ 460
60% of WTI   $ 592     $ 587     $ 582     $ 577     $ 572
$70 50% of WTI   $ 536     $ 530     $ 525     $ 520     $ 515
    40% of WTI   $ 479     $ 473     $ 467     $ 462     $ 456
    (1)   The composition is based on MarkWest’s average projected barrel of approximately: Ethane: 35%, Propane: 35%, Iso-Butane: 6%, Normal Butane: 12%, Natural Gasoline: 12%.

The table is based on current information, expectations, and beliefs concerning future developments and their potential effects, and does not consider actions MarkWest management may take to mitigate exposure to changes. Nor does the table consider the effects that such hypothetical adverse changes may have on overall economic activity. Historical prices and ratios of NGL-to-crude oil do not guarantee future results.

Although MarkWest believes the expectations reflected in this analysis are reasonable, MarkWest can give no assurance that such expectations will prove to be correct and readers are cautioned that projected performance, results, or distributions may not be achieved. Actual changes in market prices, and the ratio between crude oil and NGL prices, may differ from the assumptions utilized in the analysis. Actual results, performance, distributions, volumes, events, or transactions could vary significantly from those expressed, considered, or implied in this analysis. All results, performance, distributions, volumes, events, or transactions are subject to a number of uncertainties and risks. Those uncertainties and risks may not be factored into or accounted for in this analysis. Readers are urged to carefully review and consider the cautionary statements and disclosures made in MarkWest’s periodic reports filed with the SEC, specifically those under the heading “Risk Factors.”

Source: MarkWest Energy Partners, L.P.

MarkWest Energy Partners, L.P.
Frank Semple, 866-858-0482
Chairman, President & CEO
or
Nancy Buese, 866-858-0482
Senior VP and CFO
or
Josh Hallenbeck, 866-858-0482
VP of Finance & Treasurer
investorrelations@markwest.com