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MarkWest Energy Partners Reports Record Second Quarter Results and Announces Plans to form a Joint Venture with Kinder Morgan to Support Northern Ohio Rich-Gas Development and NGL Pipeline to Gulf Coast
  • MarkWest Utica EMG announced plans to form a Joint Venture with Kinder Morgan to support northern Ohio rich-gas processing, an NGL pipeline to the Gulf Coast, and additional Gulf Coast fractionation facilities.
  • Placed into service three processing facilities with combined capacity of 525 MMcf/d.
  • Commenced operations of the first large-scale de-ethanization facility in the Northeast, which is producing purity ethane for delivery initially to Mariner West and ultimately to all planned ethane projects including ATEX and Mariner East.
  • Announced expansion of Mobley processing complex by 200 MMcf/d to support EQT and other producers, bringing total expected capacity in the Marcellus Shale to nearly 3.6 billion cubic feet per day.
  • Executed agreements with Antero Resources to expand the Seneca processing complex by 200 MMcf/d, bringing total capacity in the Utica Shale to over 900 MMcf/d by the third quarter of 2014.
  • Announced four additional fractionation projects, which will increase total fractionation capacity in the Marcellus and Utica Shales by 96,000 to 332,000 barrels per day by the first quarter of 2015.
  • The Partnership has 23 major processing and fractionation currently under construction.
  • Fee-based net operating margin increased from 50 percent to 61 percent when compared to the second quarter of 2012.

DENVER--(BUSINESS WIRE)--Aug. 7, 2013-- MarkWest Energy Partners, L.P. (NYSE: MWE) (the Partnership) today reported record quarterly cash available for distribution to common unitholders, or distributable cash flow (DCF), of $128.4 million for the three months ended June 30, 2013, and $238.2 million for the six months ended June 30, 2013. DCF for the three months ended June 30, 2013 represents 108 percent coverage of the second quarter distribution of $118.4 million or $0.84 per common unit, which will be paid to unitholders on August 14, 2013. The second quarter 2013 distribution represents an increase of $0.01 per common unit or 1.2 percent over the first quarter 2013 distribution and an increase of $0.04 per common unit or 5.0 percent compared to the second 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 for the three and six months ended June 30, 2013, of $156.1 million and $296.5 million, respectively, as compared to $121.9 million and $275.0 million for the three and six months ended June 30, 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 income before provision for income tax for the three and six months ended June 30, 2013, of $101.8 million and $87.2 million, respectively. Income before provision for income tax includes non-cash gains associated with the change in fair value of derivative instruments of $37.3 million and $46.3 million for the three and six months ended June 30, 2013, a gain of $38.2 million related to the divestiture of gathering assets in the Marcellus Shale for the three months ended June 30, 2013 and a loss associated with the redemption of debt of $38.5 million for the six months ended June 30, 2013. Excluding these items, income before provision for income tax for the three and six months ended June 30, 2013 would have been $26.3 million and $41.2 million, respectively.

“Our full-service midstream model and commitment to delivering exceptional customer service continues to deliver record volumes and financial performance,” said Frank Semple, Chairman, President and Chief Executive Officer. “We are excited to announce new strategic opportunities and growth projects throughout our core operating areas, which continue to support the ongoing success of our producer customers.”

BUSINESS HIGHLIGHTS

Liberty:

  • In May 2013, the Partnership commenced operations of Majorsville III, a 200 million cubic feet per day (MMcf/d) processing facility in Marshall County, West Virginia. Majorsville III is supported by long-term, fee-based agreements with Consol Energy, Inc. (NYSE: CNX) (CNX) and Noble Energy, Inc. (NYSE: NBL). The facility will also provide additional processing capacity to Range Resources Corporation (NYSE: RRC) (Range), Chesapeake Energy Corporation (NYSE: CHK) (Chesapeake) and other producers prior to the completion of subsequent facilities. The 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 total processing capacity at the Sherwood complex has increased to 400 MMcf/d.
  • In June 2013, the Partnership closed on the sale of a non-strategic, high-pressure gas gathering system in Doddridge County, West Virginia to Summit Midstream Partners, LP (NYSE: SMLP) for $207.9 million in cash, net of fees. Rich-gas gathered by this system is supported by a long-term, fee-based contract with an affiliate of Antero, and is dedicated to the Partnership for processing at the Sherwood complex.
  • In July 2013, the Partnership commenced operations of the Houston De-ethanizer, a 38,000 barrel per day (Bbl/d) fractionator that is producing purity ethane from Marcellus rich-gas production. The Houston De-ethanizer will initially support Mariner West, a joint project with Sunoco Logistics Partners, L.P. (NYSE: SXL) and in the future will support all the planned ethane takeaway pipeline projects.
  • Today, the Partnership is announcing an expansion of the Mobley Complex in Wetzel County, West Virginia to support EQT Corporation (EQT) and other producers’ rich-gas development. EQT has requested 145 MMcf/d of additional priority capacity at the Mobley complex. To support the increase in priority capacity, MarkWest will construct Mobley IV, a new 200 MMcf/d processing facility that is scheduled to begin operations by the first quarter of 2015. Upon completion of this facility, Mobley’s processing capacity will be 720 MMcf/d.
  • The Partnership is also announcing the development of additional fractionation facilities to support producers’ growing rich-gas production in the Marcellus Shale. By the first quarter of 2014, the Partnership will install de-ethanization and de-propanization units totaling 20,000 Bbl/d of capacity at the Keystone complex in Butler County, Pennsylvania. In addition, the Partnership will install a 38,000 Bbl/d de-ethanization facility at the Sherwood complex in Doddridge County, West Virginia, which is expected to be operational during the first quarter of 2015.

Utica:

  • In May 2013, MarkWest Utica EMG executed definitive agreements with CNX and two additional producers to provide processing, fractionation, and marketing services in the Utica Shale.
  • In May 2013, MarkWest Utica EMG commenced 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 (NASDAQ: GPOR), Antero and other producers.
  • In June 2013, MarkWest Utica EMG executed definitive agreements with Antero for the development of Seneca III, a 200 MMcf/d processing facility in Noble County, Ohio. Seneca III is scheduled to be operational during the second quarter of 2014 and will support rich-gas production from Antero and other producers in the southern core area of the Utica Shale.
  • Today, MarkWest Utica EMG is announcing installation of a 38,000 Bbl/d de-ethanization facility at the Seneca complex, which is expected to be operational as soon as the fourth quarter of 2014.
  • Today, MarkWest Utica EMG announced plans to form a Joint Venture (JV) with Kinder Morgan Energy Partners, LP (NYSE: KMP) (Kinder Morgan) to pursue three critical new projects to support producers in the Utica and Marcellus Shales:
  • Under the first joint project, Kinder Morgan and MarkWest Utica EMG would develop a processing complex to be constructed on Kinder Morgan’s existing 220-acre site in Tuscarawas County, Ohio (JV processing complex) with an initial processing capacity of 200 MMcf/d, expandable to 400 MMcf/d of processing capacity. In addition, Kinder Morgan would convert a 65-mile segment of its existing 26-inch Tennessee Gas Pipeline into rich-gas gathering service. MarkWest Utica EMG would also construct additional rich-gas and NGL pipelines to connect the complex with its large-scale full-service midstream infrastructure. This project would serve new customers in Carroll, Columbiana, Mahoning and Trumbull counties in northern Ohio. The JV would own the processing complex on a 50-50 basis.
  • The second joint project with Kinder Morgan would involve the development of a 200,000 Bbl/d C2+ NGL pipeline originating at the JV processing complex to Gulf Coast fractionation facilities. This would be accomplished through the conversion of over 900 miles of existing Kinder Morgan pipeline assets and the construction of approximately 200 miles of additional pipeline to connect to Gulf Coast liquids and fractionation infrastructure. The NGL pipeline would be expandable to 400,000 Bbl/d. Subject to sufficient shipper commitments, permitting and all related regulatory approvals, the pipeline would be operational during the fourth quarter of 2015. The Partnership and MarkWest Utica EMG would utilize their extensive NGL pipeline network to deliver NGLs from the Marcellus and Utica to the new NGL pipeline. By converting over 900 miles of existing pipeline and utilizing the Partnership and MarkWest Utica EMG’s existing NGL network, the JV’s NGL pipeline solution is best positioned to provide a cost effective outlet from the Utica and Marcellus Shale plays to Gulf Coast area markets. Kinder Morgan would own at least 75 percent of the NGL pipeline and MarkWest Utica EMG would have the option to invest up to 25 percent.
  • The third joint project with Kinder Morgan would involve the development of new fractionation facilities, as well as utilizing third-party fractionation facilities, throughout the Gulf Coast.

Southwest:

  • In May 2013, the Partnership acquired midstream assets in the Texas Panhandle and Western Oklahoma from a wholly owned subsidiary of Chesapeake for consideration of $225.2 million in cash (Granite Wash Acquisition). In conjunction with the acquisition, the Partnership executed long-term, fee-based agreements with Chesapeake for gas gathering and processing services. As part of the fee-based gas processing agreement, Chesapeake has dedicated to the Partnership approximately 130,000 acres throughout the Anadarko Basin.
  • In May 2013, the Partnership executed a long-term fee-based agreement with Newfield Exploration (NYSE: NFX) (Newfield) to develop rich-gas gathering facilities in the Eagle Ford Shale. The Partnership will construct gathering pipelines, field compression, and liquids storage to support production from Newfield’s West Asherton project in Dimmit County, Texas.

Capital Markets

  • During the second quarter of 2013, the Partnership offered 3.8 million units and received net proceeds of approximately $244.5 million under the continuous offering program that was launched in the fourth quarter of 2012. The Partnership completed the $600 million program in July 2013.

FINANCIAL RESULTS

Balance Sheet

  • As of June 30, 2013, the Partnership had $278.9 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 June 30, 2013, was $177.5 million, an increase of $32.8 million when compared to segment operating income of $144.7 million over the same period in 2012. This increase was primarily attributable to higher processing volumes, offset by lower commodity prices compared to the prior year quarter. Processed volumes continued to remain strong, growing approximately 53 percent when compared to the second 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 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 $2.0 million in the second quarter of 2013 and ($5.0) million in the second quarter of 2012.

Capital Expenditures

  • For the three months ended June 30, 2013, the Partnership’s portion of capital expenditures was $443.0 million.

2013 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

For 2013, the Partnership’s DCF forecast remains in a range of $500 million to $540 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. 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 or the divestiture of the high-pressure gathering system in the Marcellus Shale.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Thursday, August 8, 2013, at 12:00 p.m. Eastern Time to review its second 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 (866) 454-1418 (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 June 30, 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 June 30, Six months ended June 30,
Statement of Operations Data 2013 2012 2013 2012
Revenue:
Revenue $ 395,421 $ 306,755 $ 768,879 $ 702,733
Derivative gain   19,699     136,067     19,514     87,352  
Total revenue   415,120     442,822     788,393     790,085  
 
Operating expenses:
Purchased product costs 155,359 112,731 307,916 267,286
Derivative gain related to purchased product costs (20,432 ) (51,579 ) (31,136 ) (32,779 )
Facility expenses 62,797 48,230 122,307 96,555
Derivative loss (gain) related to facility expenses 800 (1,146 ) 468 (2,892 )
Selling, general and administrative expenses 25,499 21,700 50,741 46,748
Depreciation 71,562 41,336 139,579 80,918
Amortization of intangible assets 17,092 12,307 31,922 23,292
(Gain) loss on sale or disposal of property, plant and equipment (37,736 ) 1,342 (37,598 ) 2,328
Accretion of asset retirement obligations   157     160     509     396  
Total operating expenses   275,098     185,081     584,708     481,852  
 
Income from operations 140,022 257,741 203,685 308,233
 
Other income (expense):
Gain from unconsolidated affiliates 430 1,109 665 1,548
Interest income 62 159 211 231
Interest expense (36,955 ) (26,762 ) (75,291 ) (56,234 )
Amortization of deferred financing costs and discount (a component of interest expense) (1,784 ) (1,245 ) (3,614 ) (2,515 )
Loss on redemption of debt - - (38,455 ) -
Miscellaneous income, net   6     4     6     62  
Income before provision for income tax 101,781 231,006 87,207 251,325
 
Provision for income tax (benefit) expense:
Current (2,745 ) 4,809 (8,159 ) 20,150
Deferred   19,028     39,664     30,999     28,868  
Total provision for income tax   16,283     44,473     22,840     49,018  
 
Net income 85,498 186,533 64,367 202,307
 
Net (income) loss attributable to non-controlling interest (1,799 ) 375 3,874 621
       
Net income attributable to the Partnership's unitholders $ 83,699   $ 186,908   $ 68,241   $ 202,928  
 
Net income attributable to the Partnership's common unitholders per common unit:

 

Basic $ 0.63   $ 1.74   $ 0.52   $ 1.98  
Diluted $ 0.55   $ 1.47   $ 0.45   $ 1.66  
 
Weighted average number of outstanding common units:
Basic   131,227     106,825     129,928     101,833  
Diluted   151,866     127,468     150,580     122,531  
 
Cash Flow Data
Net cash flow provided by (used in):
Operating activities $ 92,553 $ 45,708 $ 177,596 $ 253,621
Investing activities $ (825,660 ) $ (834,145 ) $ (1,435,021 ) $ (1,087,114 )
Financing activities $ 435,634 $ 562,860 $ 1,266,223 $ 841,534
 
Other Financial Data
Distributable cash flow $ 128,390 $ 91,183 $ 238,216 $ 200,379
Adjusted EBITDA $ 156,110 $ 121,853 $ 296,541 $ 274,991
 
 
Balance Sheet Data June 30, 2013 December 31, 2012
Working capital $ (116,922 ) $ (84,512 )
Total assets 8,200,883 6,728,362
Total debt 3,022,704 2,523,051
Total equity 3,482,316 3,111,398
 
       
MarkWest Energy Partners, L.P.
Operating Statistics
 

Three months ended June 30,

Six months ended June 30,

2013 2012 2013 2012
Liberty
Gathering system throughput (Mcf/d) 683,600 367,400 644,700 337,800
Natural gas processed (Mcf/d) 1,033,700 400,600 931,400 396,400
NGLs fractionated (Bbl/d) 48,900 19,800 43,000 19,900
NGL sales (gallons, in thousands) (1) 160,300 75,900 306,200 173,400
 
Utica (2)
Gathering system throughput (Mcf/d) 46,300 - 27,800 -
Natural gas processed (Mcf/d) 46,300 - 27,200 -
 
Northeast
Natural gas processed (Mcf/d) 296,400 328,200 299,500 324,900
NGLs fractionated (Bbl/d) 18,100 17,200 17,600 16,900
 
Keep-whole sales (gallons, in thousands) 27,100 23,700 60,000 73,300
Percent-of-proceeds sales (gallons, in thousands) 32,200 36,800 67,100 69,800
Total NGL sales (gallons, in thousands) 59,300 60,500 127,100 143,100
 
Crude oil transported for a fee (Bbl/d) 9,700 8,300 10,000 9,400
 
Southwest
East Texas gathering systems throughput (Mcf/d) 521,700 440,400 510,500 425,200
East Texas natural gas processed (Mcf/d) 377,600 268,300 358,600 255,400
East Texas NGL sales (gallons, in thousands) 90,200 68,000 170,700 131,400
 
Western Oklahoma gathering system throughput (Mcf/d) (3) 220,000 252,200 211,400 257,100
Western Oklahoma natural gas processed (Mcf/d) 189,900 218,900 188,100 211,400
Western Oklahoma NGL sales (gallons, in thousands) 42,900 61,700 97,700 119,000
 
Southeast Oklahoma gathering system throughput (Mcf/d) 473,300 503,300 467,300 502,200
Southeast Oklahoma natural gas processed (Mcf/d) (4) 160,400 119,600 155,800 110,700
Southeast Oklahoma NGL sales (gallons, in thousands) 54,000 41,300 93,300 74,300
 
Other Southwest gathering system throughput (Mcf/d) (5) 39,900 26,700 30,300 25,600
 
Gulf Coast refinery off-gas processed (Mcf/d) 117,700 115,800 106,600 118,000
Gulf Coast liquids fractionated (Bbl/d) 22,100 21,700 19,700 22,500
Gulf Coast NGL sales (gallons excluding hydrogen, in thousands) 84,600 83,000 149,700 172,300
 
(1)   Includes sale of all purity products fractionated at the Liberty facilities and the 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 June 30, 2013 Liberty Utica Northeast Southwest Total
Segment revenue $ 120,057 $ 3,594 $ 45,365 $ 227,842 $ 396,858
 
Operating expenses:
Purchased product costs 16,993 - 15,126 123,240 155,359
Facility expenses   22,272     6,412     6,655   29,778   65,117  
Total operating expenses before items not allocated to segments 39,265 6,412 21,781 153,018 220,476
 
Portion of operating (loss) income attributable to non-controlling interests   -     (1,143 )   -   53   (1,090 )
Operating income (loss) before items not allocated to segments $ 80,792   $ (1,675 ) $ 23,584 $ 74,771 $ 177,472  
 
 
Three months ended June 30, 2012 Liberty Utica Northeast Southwest Total
Segment revenue $ 59,477 $ - $ 42,051 $ 206,551 $ 308,079
 
Operating expenses:
Purchased product costs 8,018 - 12,921 91,792 112,731
Facility expenses   13,364     283     4,932   32,156   50,735  
Total operating expenses before items not allocated to segments 21,382 283 17,853 123,948 163,466
 
Portion of operating (loss) income attributable to non-controlling interests   -     (113 )   -   28   (85 )
Operating income (loss) before items not allocated to segments $ 38,095   $ (170 ) $ 24,198 $ 82,575 $ 144,698  
 
 

Three months ended June 30,

2013 2012
 
Operating income before items not allocated to segments $ 177,472 $ 144,698
Portion of operating (loss) income attributable to non-controlling interests (1,090 ) (85 )
Derivative gain not allocated to segments 39,331 188,792
Revenue deferral adjustment and other (1,437 ) (1,324 )
Compensation expense included in facility expenses not allocated to segments (368 ) (183 )
Facility expenses adjustments 2,688 2,688
Selling, general and administrative expenses (25,499 ) (21,700 )
Depreciation (71,562 ) (41,336 )
Amortization of intangible assets (17,092 ) (12,307 )
Gain (loss) on disposal of property, plant and equipment 37,736 (1,342 )
Accretion of asset retirement obligations   (157 )   (160 )
Income from operations 140,022 257,741
Other income (expense):
Earnings from unconsolidated affiliate 430 1,109
Interest income 62 159
Interest expense (36,955 ) (26,762 )
Amortization of deferred financing costs and discount (a component of interest expense) (1,784 ) (1,245 )
Miscellaneous income, net   6     4  
Income before provision for income tax $ 101,781   $ 231,006  
 
 
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)
 
Six months ended June 30, 2013 Liberty Utica Northeast Southwest Total
Segment revenue $ 228,554 $ 4,217 $ 102,701 $ 436,208 $ 771,680
 
Operating expenses:
Purchased product costs 35,786 - 34,788 237,342 307,916
Facility expenses   44,908     10,374     13,179   58,468   126,929  
Total operating expenses before items not allocated to segments 80,694 10,374 47,967 295,810 434,845
 
Portion of operating (loss) income attributable to non-controlling interests   -     (2,482 )   -   117   (2,365 )
Operating income (loss) before items not allocated to segments $ 147,860   $ (3,675 ) $ 54,734 $ 140,281 $ 339,200  
 
 
Six months ended June 30, 2012 Liberty Utica Northeast Southwest Total
Segment revenue $ 135,054 $ - $ 128,969 $ 441,927 $ 705,950
 
Operating expenses:
Purchased product costs 32,653 - 38,608 196,025 267,286
Facility expenses   25,611     283     11,310   64,094   101,298  
Total operating expenses before items not allocated to segments 58,264 283 49,918 260,119 368,584
 
Portion of operating (loss) income attributable to non-controlling interests   -     (113 )   -   31   (82 )
Operating income (loss) before items not allocated to segments $ 76,790   $ (170 ) $ 79,051 $ 181,777 $ 337,448  
 
 

Six months ended June 30,

2013 2012
 
Operating income before items not allocated to segments $ 339,200 $ 337,448
Portion of operating (loss) income attributable to non-controlling interests (2,365 ) (82 )
Derivative gain not allocated to segments 50,182 123,023
Revenue deferral adjustment and other (2,801 ) (3,217 )
Compensation expense included in facility expenses not allocated to segments (754 ) (633 )
Facility expenses adjustments 5,376 5,376
Selling, general and administrative expenses (50,741 ) (46,748 )
Depreciation (139,579 ) (80,918 )
Amortization of intangible assets (31,922 ) (23,292 )
Gain (loss) on disposal of property, plant and equipment 37,598 (2,328 )
Accretion of asset retirement obligations   (509 )   (396 )
Income from operations 203,685 308,233
Other income (expense):
Earnings from unconsolidated affiliate 665 1,548
Interest income 211 231
Interest expense (75,291 ) (56,234 )
Amortization of deferred financing costs and discount (a component of interest expense) (3,614 ) (2,515 )
Loss on redemption of debt (38,455 ) -
Miscellaneous income, net   6     62  
Income before provision for income tax $ 87,207   $ 251,325  
 

 

       
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Distributable Cash Flow
(unaudited, in thousands)
 
Three months ended June 30, Six months ended June 30,
2013 2012 2013 2012
 
Net income $ 85,498 $ 186,533 $ 64,367 $ 202,307
Depreciation, amortization and other non-cash operating expenses 88,889 53,881 172,166 104,762
(Gain) loss on sale and or disposal of assets, net of tax benefit (34,689 ) 1,342 (34,551 ) 2,328
Loss on redemption of debt, net of tax benefit - - 36,178 -
Amortization of deferred financing costs and discount 1,784 1,245 3,614 2,515
Non-cash earnings from unconsolidated affiliate (430 ) (1,109 ) (665 ) (1,548 )
Distributions from unconsolidated affiliate 1,962 1,774 2,728 4,566
Non-cash compensation expense 1,157 2,580 3,541 5,290
Non-cash derivative activity (37,287 ) (193,744 ) (46,320 ) (145,527 )
Provision for income tax - deferred 19,028 39,664 30,999 28,868
Cash adjustment for non-controlling interest of consolidated subsidiaries 1,720 364 3,489 604
Revenue deferral adjustment 1,645 1,700 3,410 3,968
Other 2,827 647 4,865 2,235
Maintenance capital expenditures, net of joint venture partner contributions   (3,714 )   (3,694 )   (5,605 )   (9,989 )
Distributable cash flow $ 128,390   $ 91,183   $ 238,216   $ 200,379  
 
Maintenance capital expenditures $ 3,714 $ 3,694 $ 5,605 $ 9,989
Growth capital expenditures   799,812     323,745     1,429,479     570,991  
Total capital expenditures 803,526 327,439 1,435,084 580,980
Acquisitions, net of cash acquired   225,210     506,797     225,210     506,797  
Total capital expenditures and acquisitions 1,028,736 834,236 1,660,294 1,087,777
Joint venture partner contributions   (360,499 )   -     (625,819 )   -  
Total capital expenditures and acquisitions, net $ 668,237   $ 834,236   $ 1,034,475   $ 1,087,777  
 
Distributable cash flow $ 128,390 $ 91,183 $ 238,216 $ 200,379
Maintenance capital expenditures, net of joint venture partner contributions 3,714 3,694 5,605 9,989
Changes in receivables and other assets (68,610 ) 54,300 (67,501 ) 111,955
Changes in accounts payable, accrued liabilities and other long-term liabilities 37,661 (100,434 ) 10,053 (65,190 )
Cash adjustment for non-controlling interest of consolidated subsidiaries (1,720 ) (364 ) (3,489 ) (604 )
Other   (6,882 )   (2,671 )   (5,288 )   (2,908 )
Net cash provided by operating activities $ 92,553   $ 45,708   $ 177,596   $ 253,621  
 
       
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Adjusted EBITDA
(unaudited, in thousands)
 
Three months ended June 30, Six months ended June 30,
2013 2012 2013 2012
 
Net income $ 85,498 $ 186,533 $ 64,367 $ 202,307
Non-cash compensation expense 1,157 2,580 3,541 5,290
Non-cash derivative activity (37,287 ) (193,744 ) (46,320 ) (145,527 )
Interest expense (1) 36,610 25,826 74,632 54,378
Depreciation, amortization and other non-cash operating expenses 88,889 53,881 172,166 104,762
(Gain) loss on sale and or disposal of assets (37,736 ) 1,342 (37,598 ) 2,328
Loss on redemption of debt - - 38,455 -
Provision for income tax 16,283 44,473 22,840 49,018
Adjustment for cash flow from unconsolidated affiliate 1,532 665 2,063 3,018
Other   1,164     297     2,395     (583 )
Adjusted EBITDA $ 156,110   $ 121,853   $ 296,541   $ 274,991  
 
(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 50% for 2013.
b. NGL-to-crude oil ratio at 40% for 2013.
c. NGL-to-crude oil ratio at 30% for 2013.

The analysis further assumes derivative instruments outstanding as of August 7, 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 Price
(WTI)

 

NGL-to-Crude
Oil ratio (1)

  $3.00   $3.50   $4.00   $4.50   $5.00

 

50% of WTI   $ 548   $ 546   $ 543   $ 541   $ 539

$120

40% of WTI   $ 518   $ 516   $ 514   $ 512   $ 509
    30% of WTI   $ 490   $ 488   $ 486   $ 483   $ 481

 

50% of WTI   $ 540   $ 538   $ 535   $ 533   $ 531

$110

40% of WTI   $ 513   $ 511   $ 508   $ 506   $ 504
    30% of WTI   $ 486   $ 484   $ 482   $ 479   $ 477

 

50% of WTI   $ 530   $ 528   $ 526   $ 524   $ 521

$100

40% of WTI   $ 506   $ 504   $ 502   $ 499   $ 497
    30% of WTI   $ 481   $ 478   $ 476   $ 474   $ 472

 

50% of WTI   $ 519   $ 517   $ 515   $ 512   $ 510

$90

40% of WTI   $ 497   $ 495   $ 493   $ 491   $ 488
    30% of WTI   $ 474   $ 472   $ 470   $ 468   $ 465

 

50% of WTI   $ 509   $ 507   $ 505   $ 503   $ 500

$80

40% of WTI   $ 489   $ 486   $ 484   $ 482   $ 480
    30% of WTI   $ 470   $ 467   $ 465   $ 462   $ 459
(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
Executive VP and CFO
or
Josh Hallenbeck, 866-858-0482
VP of Finance & Treasurer
investorrelations@markwest.com