MarkWest Energy Partners Reports Record Distributable Cash Flow and Full-Year Distribution Growth of 12.6 Percent

DENVER--()--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 $111.8 million for the three months ended December 31, 2012, and $416.4 million for the year ended December 31, 2012. Distributable cash flow for the three months and year ended December 31, 2012, represents distribution coverage of 106 percent and 112 percent, respectively. The fourth quarter distribution of $105.4 million, or $0.82 per common unit, was paid to unitholders on February 14, 2013. The fourth quarter 2012 distribution represents an increase of $0.01 per common unit over the third quarter 2012 distribution and a full-year increase of 12.6 percent compared to 2011. 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 $135.1 million for the three months ended December 31, 2012 and $528.2 million for the year ended December 31, 2012, as compared to $147.2 million and $515.3 million for the three months and year ended December 31, 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 income before provision for income tax for the three months and year ended December 31, 2012, of $26.9 million and $257.1 million, respectively. Income before provision for income tax includes non-cash gain associated with the change in mark-to-market of derivative instruments of $0.3 million and $102.1 million for the three months and year ended December 31, 2012, respectively. Excluding these items, income before provision for income tax for the three months and year ended December 31, 2012, would have been $26.6 million and $155.0 million, respectively.

“We are extremely pleased with our performance in 2012, which was highlighted by record distributable cash flow, our second consecutive year of double-digit distribution increases and 23 percent growth in processed volumes,” said Frank Semple, Chairman, President and Chief Executive Officer. “We have continued to build on our industry-leading position in the Marcellus Shale and as a result of our producer customers’ very successful drilling programs our fourth quarter year-over-year Liberty processed volumes increased by 86 percent. In addition, with our partner EMG, we have made enormous progress in the development of our full service integrated midstream platform to support the rapidly developing Utica Shale. In 2012 we invested almost $2 billion on strategic growth projects primarily in our Marcellus and Utica business units and in 2013 we expect to invest between $1.5 and $1.8 billion on additional capital projects, which are supported by long-term, largely fee-based contracts. Our diverse asset base and strategic position in some of the premier resource plays in the U.S. continues to provide us with significant growth opportunities. We are committed to provide our producer customers with fully-integrated midstream solutions and outstanding customer service.”

BUSINESS HIGHLIGHTS

Business Development

Liberty:

  • In October 2012, the Partnership commenced operations of the 200 million cubic feet per day (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 on-going development of midstream infrastructure in Doddridge County. The Partnership expects the Sherwood II and Sherwood III cryogenic processing plants, totaling 400 MMcf/d, to be operational in the second and third quarters of 2013, respectively.
  • 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 (NYSE: EQT) and is expected to be completed in the fourth quarter of 2013. Upon completion of the third facility, the Partnership’s total cryogenic processing capacity at Mobley will be 520 MMcf/d.
  • In December 2012, the Partnership commenced operations of the first Mobley processing facility. The 200 MMcf/d plant supports the development of rich-gas acreage in the Marcellus Shale by EQT Corporation, Magnum Hunter Resources Corporation (NYSE: MHR) and other producers.

Utica:

  • In November 2012, MarkWest Utica EMG, LLC (MarkWest Utica EMG) a joint venture between the Partnership and The Energy and Minerals Group (EMG), 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 EMG will construct two processing facilities totaling 400 MMcf/d at its Seneca complex. In addition to the Seneca processing complex, MarkWest Utica EMG will construct an NGL gathering system to the Cadiz processing complex and then on to the Hopedale fractionation and marketing complex in Harrison County, Ohio.
  • In November 2012, MarkWest Utica EMG completed its refrigeration facility at the Cadiz complex, which provides 60 MMcf/d of interim processing capacity to support rapidly expanding development of the Utica Shale. The completion of this facility is a significant milestone and is MarkWest Utica EMG’s first processing facility in the Utica Shale.
  • In February 2013, MarkWest Utica EMG announced the execution of definitive agreements with Rex Energy Corporation (NYSE: REXX) (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 June 1, 2013.
  • 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 allows EMG to increase its capital investment in 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.

Northeast:

  • In October 2012, the Partnership commenced operations of its 150 MMcf/d Langley cryogenic 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 652 MMcf/d and further expands the Partnership’s position as the largest natural gas processor in the Appalachian Basin.

Southwest:

  • In November 2012, the Partnership completed its 120 MMcf/d Carthage East cryogenic processing plant, to support producers’ gas development in the liquids-rich Haynesville Shale. This expansion increases the Partnership’s total processing capacity in East Texas to 400 MMcf/d.

Capital Markets

  • On November 7, 2012, the Partnership filed a prospectus supplement for an at-the-market equity program with a total value of up to $600 million. This program allows, but does not require, the Partnership to issue common units from time to time. Through the year ended December 31, 2012 the Partnership offered 0.13 million common units. The net proceeds of approximately $6.3 million were used to fund the Partnership’s capital expenditure program and for general partnership purposes.
  • On November 19, 2012, the Partnership completed an equity offering of 9.8 million common units. The net proceeds of approximately $437.2 million were used to partially fund the Partnership’s capital expenditure program and for general partnership purposes.
  • On January 10, 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 $986.9 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.

FINANCIAL RESULTS

Balance Sheet

  • At December 31, 2012, the Partnership had $313.0 million of cash and cash equivalents in wholly owned subsidiaries and $1.19 billion available for borrowing under its $1.2 billion revolving credit facility after consideration of $11.6 million of outstanding letters of credit.

Operating Results

  • Operating income before items not allocated to segments for the three months ended December 31, 2012, was $163.1 million, a decrease of $7.9 million when compared to segment operating income of $171.0 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 27 percent when compared to the fourth quarter of 2011, primarily due to the Partnership’s Liberty and Southwest segments. The Partnership has changed its segment reporting. The Javelina facility, which was previously reported separately in the Gulf Coast segment, is now included in the Southwest segment. In addition, operations in Ohio are now reported separately as the Utica segment.

    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 $2.1 million in the fourth quarter of 2012 and $20.0 million in the fourth quarter of 2011.

Capital Expenditures

  • For the three months and year ended December 31, 2012, the Partnership’s portion of capital expenditures was $532.5 million and $1,718.4 million, respectively. These expenditures do not include the Keystone purchase price of $507.3 million.

2013 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

For 2013, the Partnership is maintaining its DCF forecast 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. 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 has been narrowed to a range of $1.5 billion to $1.8 billion.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Thursday, February 28, 2013, at 12:00 p.m. Eastern Time to review its fourth quarter and full year 2012 financial results. Interested parties can participate in the call by dialing (800) 475-0218 (passcode “MarkWest”) approximately ten minutes prior to the scheduled start time. To access the webcast, please visit the Investor Relations section of the Partnership’s website at www.markwest.com. A replay of the conference call will be available on the MarkWest website or by dialing (800) 388-9075 (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. 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
(in thousands, except per unit data)
 
Three months ended December 31, Twelve months ended December 31,
Statement of Operations Data 2012 2011 2012 2011
Revenue:
Revenue $ 365,927 $ 424,802 $ 1,395,231 $ 1,534,434
Derivative gain (loss)   5,583     (90,889 )   56,535     (29,035 )
Total revenue   371,510     333,913     1,451,766     1,505,399  
 
Operating expenses:
Purchased product costs 143,673 184,877 530,328 682,370
Derivative loss (gain) related to purchased product costs 7,174 35,094 (13,962 ) 52,960
Facility expenses 57,714 49,240 208,385 173,598
Derivative loss (gain) related to facility expenses 235 (3,609 ) 1,371 (6,480 )
Selling, general and administrative expenses 25,091 20,775 94,116 81,229
Depreciation 57,350 39,674 189,549 149,954
Amortization of intangible assets 15,040 10,985 53,320 43,617
Loss on disposal of property, plant and equipment 3,271 4,178 6,254 8,797
Accretion of asset retirement obligations   137     256     677     1,190  
Total operating expenses   309,685     341,470     1,070,038     1,187,235  
 
Income (loss) from operations 61,825 (7,557 ) 381,728 318,164
 
Other income (expense):
(Loss) earnings from unconsolidated affiliates (89 ) 167 699 (1,095 )
Interest income 124 208 419 422
Interest expense (33,336 ) (30,595 ) (120,191 ) (113,631 )
Amortization of deferred financing costs and discount (a component of interest expense) (1,658 ) (1,241 ) (5,601 ) (5,114 )
Loss on redemption of debt - (35,535 ) - (78,996 )
Miscellaneous (expense) income, net   (1 )   17     62     144  
Income (loss) before provision for income tax 26,865 (74,536 ) 257,116 119,894
 
Provision for income tax (benefit) expense:
Current (4,568 ) 9,474 (2,366 ) 17,578
Deferred   1,298     (22,267 )   40,694     (3,929 )
Total provision for income tax   (3,270 )   (12,793 )   38,328     13,649  
 
Net income (loss) 30,135 (61,743 ) 218,788 106,245
 
Net loss (income) attributable to non-controlling interest 1,679 (12,342 ) 1,614 (45,550 )
       
Net income (loss) attributable to the Partnership $ 31,814   $ (74,085 ) $ 220,402   $ 60,695  
 
Net income (loss) attributable to the Partnership's common unitholders per common unit:
Basic $ 0.26   $ (0.87 ) $ 1.98   $ 0.75  
Diluted $ 0.22   $ (0.87 ) $ 1.69   $ 0.75  

 

Weighted average number of outstanding common units:
Basic   122,079     85,431     109,979     78,466  
Diluted   142,720     85,431     130,648     78,619  
 
Cash Flow Data
Net cash flow provided by (used in):
Operating activities $ 106,995 $ 83,449 $ 496,713 $ 414,698
Investing activities $ (726,281 ) $ (188,867 ) $ (2,472,352 ) $ (776,553 )
Financing activities $ 552,121 $ 63,257 $ 2,206,522 $ 411,421
 
Other Financial Data
Distributable cash flow $ 111,774 $ 88,405 $ 416,423 $ 332,796
Adjusted EBITDA $ 135,079 $ 147,235 $ 528,168 $ 515,258
 
 
Balance Sheet Data December 31, 2012 December 31, 2011
Working capital $ (82,587 ) $ 4,234
Total assets 6,835,716 4,070,425
Total debt 2,523,051 1,846,062
Total equity 3,215,591 1,502,067
 
 
MarkWest Energy Partners, L.P.
Operating Statistics
       
Three months ended December 31, Twelve months ended December 31,
2012 2011 2012 2011
Southwest
East Texas gathering systems throughput (Mcf/d) 477,600 423,100 450,000 423,600
East Texas natural gas processed (Mcf/d) 302,000 235,100 270,800 228,300
East Texas NGL sales (gallons, in thousands) 76,500 63,500 275,800 238,700
 
Western Oklahoma gathering system throughput (Mcf/d) (1) 200,800 277,500 235,600 237,900
Western Oklahoma natural gas processed (Mcf/d) 193,800 231,700 206,500 175,500
Western Oklahoma NGL sales (gallons, in thousands) 44,500 66,100 214,400 177,200
 
Southeast Oklahoma gathering system throughput (Mcf/d) 463,100 524,800 487,900 511,900
Southeast Oklahoma natural gas processed (Mcf/d) (2) 137,000 104,200 121,800 103,400
Southeast Oklahoma NGL sales (gallons, in thousands) 42,400 33,000 163,300 125,100
Arkoma Connector Pipeline throughput (Mcf/d) 253,700 346,000 305,900 307,300
 
Other Southwest gathering system throughput (Mcf/d) (3) 22,300 25,100 24,300 29,900
 
Gulf Coast refinery off-gas processed (Mcf/d) 113,600 113,700 118,400 113,300
Gulf Coast liquids fractionated (Bbl/d) 21,000 20,800 22,500 21,200
Gulf Coast NGL sales (gallons excluding hydrogen, in thousands) 81,000 80,200 345,300 325,700
 
Northeast (4)
Natural gas processed (Mcf/d) 313,700 320,300 320,500 305,900
NGLs fractionated (Bbl/d) (5) 19,500 17,200 17,500 20,300
 
Keep-whole sales (gallons, in thousands) 35,100 31,100 131,600 113,800
Percent-of-proceeds sales (gallons, in thousands) 36,200 34,700 139,700 130,300
Total NGL sales (gallons, in thousands) (6) 71,300 65,800 271,300 244,100
 
Crude oil transported for a fee (Bbl/d) 9,900 9,700 9,300 10,300
 
Liberty
Natural gas processed (Mcf/d) 696,000 374,800 496,400 323,900
Gathering system throughput (Mcf/d) 587,600 295,600 425,000 245,700
NGLs fractionated (Bbl/d) (7) 31,100 19,200 24,900 11,800
NGL sales (gallons, in thousands) (8) 129,400 77,700 393,600 241,200
 
Utica (9)
Natural gas processed (Mcf/d) 5,000 N/A 4,200 N/A
Gathering system throughput (Mcf/d) 6,400 N/A 5,000 N/A
 
(1)   Includes natural gas gathered in Western Oklahoma and from the Granite Wash formation in the Texas Panhandle. It is considered 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) Excludes lateral pipelines where revenue is not based on throughput.
(4) Includes throughput from the Kenova, Cobb, Boldman and Langley processing plants. We acquired the Langley processing plant in February 2011. The volumes reported are the average daily rates for the days of operation.
(5)

Amount includes 1,400 and 200 barrels per day fractionated on behalf of Liberty for the three months ended December 31, 2012 and 2011, respectively, and 400 and 3,900 barrels per day fractionated for the twelve months ended December 31, 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 temporary periods of capacity constraint.

(6) Represents sales at the Siloam fractionator. The total sales exclude approximately 5,500,000 and 600,000 gallons, sold by the Northeast on behalf of Liberty for three months ended December 31, 2012 and 2011, respectively, and 6,500,000 and 59,200,000 gallons sold for the twelve months ended December 31, 2012 and 2011, respectively. These volumes are included as part of NGLs sold at Liberty.
(7) Amount includes all NGLs that were produced at the Liberty processing facilities and fractionated into purity products at our Liberty fractionation facility. Through August 2011, only propane was recovered at our Liberty facilities. In September 2011, Liberty’s fractionation facility commenced operations and Liberty now has full fractionation capabilities.
(8) 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 at the Siloam facilities on behalf of Liberty.
(9) Utica operations began in August 2012. The volumes reported are the average daily rate for the days of operation.
 
 
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Operating Income before Items not Allocated to Segments
(in thousands)
         
Three months ended December 31, 2012 Southwest Northeast Liberty Utica Total
Revenue $ 204,370 $ 56,862 $ 106,106 $ 426 $ 367,764
 
Operating expenses:
Purchased product costs 99,765 18,740 25,168 - 143,673
Facility expenses   30,195     6,529     21,281   2,377     60,382
Total operating expenses before items not allocated to segments 129,960 25,269 46,449 2,377 204,055
 

Portion of operating income (loss) attributable to non-controlling interests

  1,211     -     -   (619 )   592
Operating income (loss) before items not allocated to segments $ 73,199   $ 31,593   $ 59,657 $ (1,332 ) $ 163,117
 
 
Three months ended December 31, 2011 Southwest Northeast Liberty Utica Total
Revenue $ 279,329 $ 67,197 $ 80,807 $ - $ 427,333
 
Operating expenses:
Purchased product costs 133,660 19,085 32,132 - 184,877
Facility expenses   32,042     7,724     12,038   -     51,804
Total operating expenses before items not allocated to segments 165,702 26,809 44,170 - 236,681
 
Portion of operating income attributable to non-controlling interests   1,686     -     17,949   -     19,635
Operating income before items not allocated to segments $ 111,941   $ 40,388   $ 18,688   N/A   $ 171,017
 
 
Three months ended December 31,
2012 2011
 
Operating income before items not allocated to segments $ 163,117 $ 171,017
Portion of operating income attributable to non-controlling interests 592 19,635
Derivative loss not allocated to segments (1,826 ) (122,374 )
Revenue deferral adjustment (1,837 ) (2,531 )
Compensation expense included in facility expenses not allocated to segments (196 ) (290 )
Facility expenses adjustments 2,864 2,854
Selling, general and administrative expenses (25,091 ) (20,775 )
Depreciation (57,350 ) (39,674 )
Amortization of intangible assets (15,040 ) (10,985 )
Loss on disposal of property, plant and equipment (3,271 ) (4,178 )
Accretion of asset retirement obligations   (137 )   (256 )
Income (loss) from operations 61,825 (7,557 )
Other income (expense):
(Loss) earnings from unconsolidated affiliate (89 ) 167
Interest income 124 208
Interest expense (33,336 ) (30,595 )
Amortization of deferred financing costs and discount (a component of interest expense) (1,658 ) (1,241 )
Loss on redemption of debt - (35,535 )
Miscellaneous (expense) income, net   (1 )   17  
Income (loss) before provision for income tax $ 26,865   $ (74,536 )
 
 
 
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Operating Income before Items not Allocated to Segments
(in thousands)
 
Twelve months ended December 31, 2012 Southwest Northeast Liberty Utica Total
Revenue $ 856,416 $ 225,818 $ 319,867 $ 571 $ 1,402,672
 
Operating expenses:
Purchased product costs 387,902 68,402 74,024 - 530,328
Facility expenses   124,921     24,106     65,825   3,968     218,820
Total operating expenses before items not allocated to segments 512,823 92,508 139,849 3,968 749,148
 

Portion of operating income (loss) attributable to non-controlling interests

  5,790     -     -   (1,359 )   4,431
Operating income (loss) before items not allocated to segments $ 337,803   $ 133,310   $ 180,018 $ (2,038 ) $ 649,093
 
 
Twelve months ended December 31, 2011 Southwest Northeast Liberty Utica Total
Revenue $ 1,031,986 $ 268,884 $ 248,949 $ - $ 1,549,819
 
Operating expenses:
Purchased product costs 506,911 91,612 83,847 - 682,370
Facility expenses   121,197     27,126     34,913   -     183,236
Total operating expenses before items not allocated to segments 628,108 118,738 118,760 - 865,606
 
Portion of operating income attributable to non-controlling interests   5,431     -     63,731   -     69,162
Operating income before items not allocated to segments $ 398,447   $ 150,146   $ 66,458   N/A   $ 615,051
 
 
Twelve months ended December 31,
2012 2011
 
Operating income before items not allocated to segments $ 649,093 $ 615,051
Portion of operating income attributable to non-controlling interests 4,431 69,162

Derivative gain (loss) not allocated to segments

69,126 (75,515 )
Revenue deferral adjustment (7,441 ) (15,385 )
Compensation expense included in facility expenses not allocated to segments (1,022 ) (1,781 )
Facility expenses adjustments 11,457 11,419
Selling, general and administrative expenses (94,116 ) (81,229 )
Depreciation (189,549 ) (149,954 )
Amortization of intangible assets (53,320 ) (43,617 )
Loss on disposal of property, plant and equipment (6,254 ) (8,797 )
Accretion of asset retirement obligations   (677 )   (1,190 )
Income from operations 381,728 318,164
Other income (expense):
Earnings (loss) from unconsolidated affiliate 699 (1,095 )
Interest income 419 422
Interest expense (120,191 ) (113,631 )
Amortization of deferred financing costs and discount (a component of interest expense) (5,601 ) (5,114 )
Loss on redemption of debt - (78,996 )
Miscellaneous income, net   62     144  
Income before provision for income tax $ 257,116   $ 119,894  
 
       
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Distributable Cash Flow
(in thousands)
 
Three months ended December 31, Twelve months ended December 31,
2012 2011 2012 2011
 
Net income (loss) $ 30,135 $ (61,743 ) $ 218,788 $ 106,245
Depreciation, amortization, impairment, and other non-cash operating expenses 75,876 55,171 250,112 203,870
Loss on redemption of debt, net of tax benefit - 32,446 - 72,064
Amortization of deferred financing costs and discount 1,658 1,241 5,601 5,114
Non-cash loss (earnings) from unconsolidated affiliate 89 (167 ) (699 ) 1,095
Distributions from unconsolidated affiliate

400

(560 )

2,600

(260 )
Non-cash compensation expense 1,977 (308 ) 8,247 3,399
Non-cash derivative activity (312 ) 102,391 (102,127 ) (290 )
Provision for income tax - deferred 1,298 (22,267 ) 40,694 (3,929 )
Cash adjustment for non-controlling interest of consolidated subsidiaries (67 ) (18,185 ) (2,580 ) (64,470 )
Revenue deferral adjustment 1,837 2,531 7,441 15,385
Other

(314

) 4,634

3,648

9,171
Maintenance capital expenditures, net of joint venture partner contributions   (803 )   (6,779 )   (15,302 )   (14,598 )
Distributable cash flow $ 111,774   $ 88,405   $ 416,423   $ 332,796  
 
Maintenance capital expenditures $ 803 $ 7,490 $ 15,302 $ 16,067
Growth capital expenditures   709,758     183,865     1,936,125     535,214  
Total capital expenditures 710,561 191,355 1,951,427 551,281
Acquisitions, net of cash acquired   -     -     506,797     230,728  
Total capital expenditures and acquisitions 710,561 191,355 2,458,224 782,009
Joint venture partner contributions   (178,018 )   (61,115 )   (233,018 )   (129,616 )
Total capital expenditures and acquisitions, net $ 532,543   $ 130,240   $ 2,225,206   $ 652,393  
 
Distributable cash flow $ 111,774 $ 88,405 $ 416,423 $ 332,796
Maintenance capital expenditures, net 803 6,779 15,302 14,598
Changes in receivables and other assets (1,540 ) (32,268 ) 25,406 (65,523 )
Changes in accounts payable, accrued liabilities and other long-term liabilities (3,645 ) 466 41,723 69,838
Derivative instrument premium payments, net of amortization - 1,155 - 4,436
Cash adjustment for non-controlling interest of consolidated subsidiaries 67 18,185 2,580 64,470
Other   (464 )   727     (4,721 )   (5,917 )
Net cash provided by operating activities $ 106,995   $ 83,449   $ 496,713   $ 414,698  
 
       

MarkWest Energy Partners, L.P.

Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Adjusted EBITDA (1)
(in thousands)
 
Three months ended December 31, Twelve months ended December 31,
2012 2011 2012 2011
 
Net income (loss) $ 30,135 $ (61,743 ) $ 218,788 $ 106,245
Non-cash compensation expense 1,977 (308 ) 8,247 3,399
Non-cash derivative activity (312 ) 102,391 (102,127 ) (290 )
Interest expense (2) 32,838 29,634 117,098 109,869
Depreciation, amortization, impairment, and other non-cash operating expenses 75,876 55,171 250,112 203,870
Loss on redemption of debt - 35,535 - 78,996
Provision for income tax (3,270 ) (12,793 ) 38,328 13,649
Adjustment for cash flow from unconsolidated affiliate

489

(167 )

1,901

1,395
Other  

(2,654

)   (485 )  

(4,179

)   (1,875 )
Adjusted EBITDA $ 135,079   $ 147,235   $ 528,168   $ 515,258  
 

(1)

 

The Partnership has changed its calculation of adjusted EBITDA and removed the line "Adjustment related to non-guarantor of consolidated subsidiaries".

(2)

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 February 27, 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

NGL-to-Crude oil

               
(WTI)    

ratio (1)

   

$2.50

    $3.00     $3.50     $4.00     $4.50

 

55% of WTI     $ 614     $ 610     $ 606     $ 602     $ 599

$110

45% of WTI     $ 538     $ 534     $ 530     $ 527     $ 523
      35% of WTI     $ 466     $ 463     $ 459     $ 455     $ 451

 

55% of WTI     $ 583     $ 579     $ 575     $ 571     $ 568

$100

45% of WTI     $

515

    $ 512     $ 508     $ 504     $ 500
      35% of WTI     $ 450     $ 446     $ 442     $ 439     $ 435

 

55% of WTI     $ 549     $ 545     $ 542     $ 538     $ 534

$90

45% of WTI     $ 491     $ 487     $ 483     $ 479     $ 475
      35% of WTI     $ 431     $ 427     $ 424     $ 420     $ 416

 

55% of WTI     $ 526     $ 522     $ 518     $ 514     $ 510

$80

45% of WTI     $ 473     $ 470     $ 466     $ 462     $ 458
      35% of WTI     $ 421     $ 417     $ 413     $ 408     $ 404

 

55% of WTI     $ 507     $ 503     $ 499     $ 495     $ 491

$70

45% of WTI     $ 461     $ 457     $ 453     $ 449     $ 445
      35% of WTI     $ 414     $ 410     $ 405     $ 400     $ 395
 
(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.”

Contacts

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

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Contacts

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