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MarkWest Energy Partners Reports Second Quarter Financial Results and Increases Common Unit Distribution by 14.3 Percent
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DENVER--(BUSINESS WIRE)--Aug. 2, 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 $91.2 million for the three months ended June 30, 2012, and $200.4 million for the six months ended June 30, 2012. Distributable cash flow for the three months ended June 30, 2012, represents distribution coverage of 103 percent. The second quarter distribution of $88.6 million, or $0.80 per common unit, will be paid to unitholders on August 14, 2012. The second quarter 2012 distribution represents an increase of $0.01 per common unit, or 1.3 percent, over the first quarter 2012 distribution and an increase of $0.10 per common unit, or 14.3 percent, over the second 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 six months ended June 30, 2012, of $130.5 million and $263.5 million, respectively, as compared to $120.0 million and $216.2 million for the three and six months ended June 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 income before provision for income tax for the three and six months ended June 30, 2012, of $231.6 million and $252.4 million, respectively. Income before provision for income tax includes non-cash gain associated with the change in mark-to-market of derivative instruments of $193.7 million and $145.5 million for the three and six months ended June 30, 2012, respectively. Excluding these items, income before provision for income tax for the three and six months ended June 30, 2012, would have been $37.9 million and $106.9 million, respectively.

“Our mid-year results reflect the continued solid performance of our core assets despite the significant decrease in processing margins and natural gas liquids prices during the second quarter,” said Frank Semple, Chairman, President and Chief Executive Officer. “Our year-over-year processed volumes have increased by 18% as a result of our operational performance and ongoing growth projects located in some of the best resource plays in the United States. During the second quarter, we also improved our liquidity position and capital flexibility with a $300 million increase to our credit facility and an equity offering with net proceeds over $427 million. The combination of MarkWest’s high-quality assets, significant fee-based growth opportunities, and balance sheet strength supports our objective of providing long term sustainable top-quartile returns for our unitholders.”

BUSINESS HIGHLIGHTS

Business Development

  • Keystone Midstream Services Acquisition: In May 2012, the Partnership completed the acquisition of 100% of the ownership interests of Keystone Midstream Services, LLC (Keystone), for consideration of $509.6 million, adjusted for working capital. Keystone was owned by Stonehenge Energy Resources, LP, and affiliates of Rex Energy Corporation (Rex Energy), and Sumitomo Corporation (Sumitomo). Keystone’s existing assets are located in Butler County, Pennsylvania and include two cryogenic gas processing plants totaling 90 million cubic feet per day (MMcf/d) of capacity, a gas gathering system and associated field compression. Rex Energy and Sumitomo have dedicated approximately 900 square miles to the Partnership. The parties have jointly leased 68,400 highly prospective acres in Butler County. The Partnership will gather and process the rich gas and fractionate the natural gas liquids (NGLs) under long-term fee-based agreements.

    Pursuant to a letter agreement signed at the time of the Keystone acquisition, MarkWest Utica EMG, LLC (MarkWest Utica) is evaluating gathering, processing, and NGL fractionation opportunities for portions of Rex Energy’s Ohio Utica acreage.
  • Liberty: In May 2012, the Partnership announced additional major expansion projects to serve producer customers in the hydrocarbon-rich area of the Marcellus Shale in northern West Virginia and southwest Pennsylvania area, including another 400 MMcf/d expansion of its Majorsville processing complex which includes two, 200 MMcf/d processing plants that are expected to be completed in late 2013 and mid 2014 and are supported by long-term agreements with Chesapeake Energy. Considering the expansions announced in January and May 2012, the Partnership will have 1.1 billion cubic feet per day of cryogenic processing capacity at its Majorsville processing complex.

    In May 2012, the Partnership announced a long-term fee-based agreement with Antero Resources Appalachian Corporation (Antero) to install gathering facilities in support of Antero’s rapidly growing rich natural gas production in Doddridge and Harrison Counties in northern West Virginia. The new gathering system will have the capacity to initially deliver more than 300 MMcf/d of Antero’s rich gas to the Partnership’s Sherwood gas processing complex. The first phase of the gathering system will be completed in the third quarter of 2012 in conjunction with the completion of the 200 MMcf/d Sherwood I processing facility.

    In May 2012, the Partnership also announced that it is extending its existing NGL gathering pipeline from its Houston, Pennsylvania fractionation complex into Beaver, Butler and Lawrence Counties to gather NGLs from the Keystone processing facilities and other planned processing projects in Northwest Pennsylvania. The NGL pipeline expansion will allow Rex Energy and other producers to access all of the anticipated ethane pipeline projects.

    In July 2012, the Partnership announced a new long-term, fee-based agreement with XTO Energy (XTO) to transport, fractionate and market NGLs from their 125 MMcf/d processing plant located in Butler County, Pennsylvania, which is expected to be operational in late 2012. NGLs will initially be transported by truck from XTO’s plant to the Houston fractionation complex. By the end of 2013, an extension of the Partnership’s NGL gathering pipeline is expected to be complete and will connect the Keystone processing facilities to the XTO facility.

    In late June, the Partnership began delivering propane to Sunoco Inc.’s (Sunoco) Marcus Hook facility located outside Philadelphia, Pennsylvania. Propane is currently being transported by truck from the Houston fractionation complex to Marcus Hook, with rail deliveries expected to be added in the next several months. In addition, the Partnership is purchasing propane produced at Sunoco’s local-area facilities and the combined stream is being loaded onto ships for marketing by the Partnership to international customers. The delivery of propane from the northeast U.S. to global markets is critical to ensure northeast propane markets remain in balance and that northeast propane continues to achieve premium pricing. This milestone is part of the Partnership’s ongoing commitment to provide multiple marketing options that will maximize the value of its producer customers’ NGLs.
  • Utica: In June 2012, MarkWest Utica announced the completion of definitive agreements with Gulfport Energy Corporation to provide gathering, processing, fractionation, and marketing services primarily in Harrison, Guernsey, Belmont and Noble counties of Ohio in the liquids-rich window of the Utica Shale. MarkWest Utica expects the first phase to be operational beginning in the third quarter of 2012. It is anticipated MarkWest Utica will have approximately 60 miles of gas gathering pipelines and associated compression to move Gulfport volumes by the end of 2012 and up to 140 miles of gathering pipelines by the first quarter of 2014. MarkWest Utica anticipates refrigeration processing capacity of 105 MMcf/d by the end of 2012 and 125 MMcf/d of cryogenic processing capacity in early 2013, increasing to 325 MMcf/d of total cryogenic processing capacity by the end of 2013. The NGLs from these processing plants, as well as from our Marcellus operations, will ultimately be fractionated at the previously announced 100,000 Bbl/d Harrison County fractionation complex.

Capital Markets

  • On May 14, 2012, the Partnership completed a common unit equity offering of 8.0 million common units. The net proceeds of approximately $427.2 million were used to partially fund the acquisition of Keystone Midstream.
  • On June 29, 2012, the Partnership executed an amendment to its senior secured revolving credit facility, which increased total borrowing capacity by $300.0 million to $1.2 billion and extended the maturity by one year to September 2017.

FINANCIAL RESULTS

Balance Sheet

  • At June 30, 2012, the Partnership had $121.7 million of cash and cash equivalents in wholly owned subsidiaries and $959.8 million available for borrowing under its $1.2 billion revolving credit facility after consideration of aggregate borrowings of $217.9 million and $22.3 million of outstanding letters of credit.

Operating Results

  • Operating income before items not allocated to segments for the three months ended June 30, 2012, was $146.3 million, a decrease of $1.5 million when compared to segment operating income of $147.8 million in the same period in 2011. This decrease is primarily attributable to lower commodity prices compared to the prior year quarter. Processed volumes remain strong, growing almost 20% when compared to the second quarter of 2011, primarily due to the Partnership’s Southwest and Liberty 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 $5.0 million in the second quarter of 2012 compared to realized losses of $17.7 million in the second quarter of 2011.

Capital Expenditures

  • For the three and six months ended June 30, 2012, the Partnership’s portion of capital expenditures was $327.9 million and $582.2 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 $400 million to $440 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 119 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 2012 DCF is provided within the tables of this press release.

The Partnership’s portion of growth capital expenditures for 2012 remains unchanged and is forecasted in a range of $1.1 billion to $1.5 billion. This range excludes the Keystone purchase price of $509.6 million. Maintenance capital for 2012 is forecasted at approximately $20 million.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Friday, August 3, 2012, at 12:00 p.m. Eastern Time to review its second 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) 463-4105 (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, it can give no assurance that such expectations will prove to be correct. The forward-looking statements involve risks and uncertainties that affect MarkWest’s operations, financial performance, and other factors as discussed in its filings with the Securities and Exchange Commission. 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 Report on Form 10-Q for the quarter ended March 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
(unaudited, in thousands, except per unit data)
             
Three months ended June 30, Six months ended June 30,
Statement of Operations Data 2012 2011   2012   2011  
Revenue:
Revenue $ 309,986 $ 359,849 $ 709,167 $ 708,749
Derivative gain (loss)   136,067     40,590     87,352     (45,089 )
Total revenue   446,053     400,439     796,519     663,660  
 
Operating expenses:
Purchased product costs 112,731 154,580 267,286 308,209
Derivative (gain) loss related to purchased product costs (51,579 ) (254 ) (32,779 ) 19,140
Facility expenses 48,538 40,698 97,378 80,122
Derivative (gain) loss related to facility expenses (1,146 ) 2,927 (2,892 ) (84 )
Selling, general and administrative expenses 21,879 18,580 47,103 40,292
Depreciation 42,918 37,201 84,063 71,565
Amortization of intangible assets 12,307 10,830 23,292 21,647
Loss on disposal of property, plant and equipment 1,342 2,373 2,328 4,472
Accretion of asset retirement obligations   161     290     399     377  
Total operating expenses   187,151     267,225     486,178     545,740  
 
Income from operations 258,902 133,214 310,341 117,920
 
Other income (expense):
Income (loss) from unconsolidated affiliates 551 (216 ) 542 (755 )
Interest income 159 63 231 152
Interest expense (26,762 ) (27,874 ) (56,234 ) (56,137 )
Amortization of deferred financing costs and discount (a component of interest expense) (1,245 ) (1,443 ) (2,515 ) (2,871 )
Loss on redemption of debt - - - (43,328 )
Miscellaneous income, net   4     169     62     131  
Income before provision for income tax 231,609 103,913 252,427 15,112
 
Provision for income tax expense (benefit):
Current 4,809 4,089 20,150 4,145
Deferred   39,664     10,619     28,868     (3,567 )
Total provision for income tax   44,473     14,708     49,018     578  
 
Net income 187,136 89,205 203,409 14,534
 
Net income attributable to non-controlling interest (228 ) (10,708 ) (481 ) (20,066 )
       
Net income (loss) attributable to the Partnership $ 186,908   $ 78,497   $ 202,928   $ (5,532 )
 
Net income (loss) attributable to the Partnership's common unitholders per common unit:
Basic $ 1.74   $ 1.03   $ 1.98   $ (0.09 )
Diluted $ 1.47   $ 1.03   $ 1.66   $ (0.09 )
 
Weighted average number of outstanding common units:
Basic   106,825     75,160     101,833     74,847  
Diluted   127,468     75,266     122,531     74,847  
 
Cash Flow Data
Net cash flow provided by (used in):
Operating activities $ 48,524 $ 91,045 $ 256,437 $ 206,364
Investing activities $ (834,529 ) $ (120,428 ) $ (1,087,498 ) $ (462,049 )
Financing activities $ 560,833 $ 51,266 $ 839,507 $ 283,270
 
Other Financial Data
Distributable cash flow $ 91,183 $ 82,944 $ 200,360 $ 159,080
Adjusted EBITDA $ 130,533 $ 120,004 $ 263,475 $ 216,191
 
Balance Sheet Data June 30, 2012 December 31, 2011
Working capital $ (114,875 ) $ 4,234
Total assets 5,134,598 4,070,425
Total debt 1,997,985 1,846,062
Total equity 2,362,431 1,502,067
 
             
MarkWest Energy Partners, L.P.
Operating Statistics
 
Three months ended June 30, Six months ended June 30,
2012 2011 2012 2011
Southwest
East Texas gathering systems throughput (Mcf/d) 440,400 428,300 425,200 427,000
East Texas natural gas processed (Mcf/d) 268,300 229,000 255,400 224,100
East Texas NGL sales (gallons, in thousands) 68,000 59,500 131,400 116,200
 
Western Oklahoma gathering system throughput (Mcf/d) (1) 252,200 223,900 257,100 215,700
Western Oklahoma natural gas processed (Mcf/d) 218,900 159,500 211,400 158,300
Western Oklahoma NGL sales (gallons, in thousands) 61,700 35,100 119,000 74,100
 
Southeast Oklahoma gathering system throughput (Mcf/d) 503,300 511,700 502,200 504,900
Southeast Oklahoma natural gas processed (Mcf/d) (2) 119,600 110,200 110,700 102,000
Southeast Oklahoma NGL sales (gallons, in thousands) 41,300 32,100 74,300 61,500
Arkoma Connector Pipeline throughput (Mcf/d) 331,200 298,400 329,900 292,100
 
Other Southwest gathering system throughput (Mcf/d) 26,700 31,600 25,600 32,300
 
Northeast
Natural gas processed (Mcf/d) (3) 328,200 319,600 324,900 312,500
NGLs fractionated (Bbl/d) (4) 17,200 22,700 16,900 22,500
 
Keep-whole sales (gallons, in thousands) 23,700 21,100 73,300 60,900
Percent-of-proceeds sales (gallons, in thousands) 36,800 33,100 69,800 64,000
Total NGL sales (gallons, in thousands) (5) 60,500 54,200 143,100 124,900
 
Crude oil transported for a fee (Bbl/d) 8,300 11,500 9,400 10,800
 
Liberty
Natural gas processed (Mcf/d) 400,600 298,200 396,400 276,500
Gathering system throughput (Mcf/d) 367,400 232,000 337,800 214,000
NGLs fractionated (Bbl/d) (6) 19,800 8,400 19,900 7,700
NGL sales (gallons, in thousands) (7) 75,900 50,700 173,400 102,400
 
Gulf Coast
Refinery off-gas processed (Mcf/d) 115,800 114,600 118,000 108,700
Liquids fractionated (Bbl/d) 21,700 21,900 22,500 20,600
NGL sales (gallons excluding hydrogen, in thousands) 83,000 83,600 172,300 156,300
 
(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 six months ended June 30, 2011 are the average daily rates for the days of operation.
 
(4) Amount includes zero barrels per day and 5,500 barrels per day fractionated on behalf of Liberty for the three and six months ended June 30, 2012 and 2011, respectively. Beginning in the fourth quarter of 2011, Siloam no longer fractionated NGLs on behalf of Liberty due to the operation of Liberty’s fractionation facility that began in September 2011.
 
(5) Represents sales from the Siloam facilities. The total sales exclude approximately zero gallons and 20,900,000 gallons sold by the Northeast on behalf of Liberty for the three months ended June 30, 2012 and 2011, respectively and zero gallons and 41,500,000 gallons sold for the six months ended June 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 June 30, 2012 Southwest Northeast Liberty Gulf Coast Total
Revenue $ 189,162 $ 42,051 $ 59,477 $ 20,997 $ 311,687
 
Operating expenses:
Purchased product costs 91,792 12,921 8,018 - 112,731
Facility expenses   23,034   4,932   13,647     9,607   51,220
Total operating expenses before items not allocated to segments 114,826 17,853 21,665 9,607 163,951
 
Portion of operating income attributable to non-controlling interests   1,590   -   (113 )   -   1,477
Operating income before items not allocated to segments $ 72,746 $ 24,198 $ 37,925   $ 11,390 $ 146,259
 
 
Three months ended June 30, 2011 Southwest Northeast Liberty Gulf Coast Total
Revenue $ 235,575 $ 53,676 $ 48,337 $ 24,683 $ 362,271
 
Operating expenses:
Purchased product costs 128,988 15,702 9,890 - 154,580
Facility expenses   20,855   6,929   7,269     8,312   43,365
Total operating expenses before items not allocated to segments 149,843 22,631 17,159 8,312 197,945
 
Portion of operating income attributable to non-controlling interests   1,346   -   15,182     -   16,528
Operating income before items not allocated to segments $ 84,386 $ 31,045 $ 15,996   $ 16,371 $ 147,798
 
Three months ended June 30,
2012     2011
 
Operating income before items not allocated to segments $ 146,259 $ 147,798
Portion of operating income attributable to non-controlling interests 1,477 16,528
Derivative gain not allocated to segments 188,792 37,917
Revenue deferral adjustment (1,701 ) (2,422 )
Compensation expense included in facility expenses not allocated to segments (184 ) (188 )
Facility expenses adjustments 2,866 2,855
Selling, general and administrative expenses (21,879 ) (18,580 )
Depreciation (42,918 ) (37,201 )
Amortization of intangible assets (12,307 ) (10,830 )
Loss on disposal of property, plant and equipment (1,342 ) (2,373 )
Accretion of asset retirement obligations   (161 )   (290 )
Income from operations 258,902 133,214
Other income (expense):
Earnings (loss) from unconsolidated affiliate 551 (216 )
Interest income 159 63
Interest expense (26,762 ) (27,874 )

Amortization of deferred financing costs and discount (a component of
interest expense)

(1,245 ) (1,443 )
Miscellaneous income, net   4     169  
Income before provision for income tax $ 231,609   $ 103,913  
 
                 
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, 2012 Southwest Northeast Liberty Gulf Coast Total
Revenue $ 403,887 $ 128,969 $ 135,054 $ 45,226 $ 713,136
 
Operating expenses:
Purchased product costs 196,025 38,608 32,653 - 267,286
Facility expenses   46,026     11,310     25,894       19,245     102,475
Total operating expenses before items not allocated to segments 242,051 49,918 58,547 19,245 369,761
 
Portion of operating income attributable to non-controlling interests   3,036   -   (113 )   -   2,923
Operating income before items not allocated to segments $ 158,800 $ 79,051 $ 76,620   $ 25,981 $ 340,452
 
 
Six months ended June 30, 2011 Southwest Northeast Liberty Gulf Coast Total
Revenue $ 437,349 $ 145,767 $ 89,556 $ 46,442 $ 719,114
 
Operating expenses:
Purchased product costs 232,184 56,580 19,445 - 308,209
Facility expenses   41,012   12,523   13,767     17,302   84,604
Total operating expenses before items not allocated to segments 273,196 69,103 33,212 17,302 392,813
 
Portion of operating income attributable to non-controlling interests   2,518   -   27,559     -   30,077
Operating income before items not allocated to segments $ 161,635 $ 76,664 $ 28,785   $ 29,140 $ 296,224
 
     
Six months ended June 30,
2012 2011
 
Operating income before items not allocated to segments $ 340,452 $ 296,224
Portion of operating income attributable to non-controlling interests 2,923 30,077
Derivative gain (loss) not allocated to segments 123,023 (64,145 )
Revenue deferral adjustment (3,969 ) (10,365 )
Compensation expense included in facility expenses not allocated to segments (633 ) (1,228 )
Facility expenses adjustments 5,730 5,710
Selling, general and administrative expenses (47,103 ) (40,292 )
Depreciation (84,063 ) (71,565 )
Amortization of intangible assets (23,292 ) (21,647 )
Loss on disposal of property, plant and equipment (2,328 ) (4,472 )
Accretion of asset retirement obligations   (399 )     (377 )
Income from operations 310,341 117,920
Other income (expense):
Earnings (loss) from unconsolidated affiliate 542 (755 )
Interest income 231 152
Interest expense (56,234 ) (56,137 )

Amortization of deferred financing costs and discount (a component of
interest expense)

(2,515 ) (2,871 )
Loss on redemption of debt - (43,328 )
Miscellaneous income, net   62     131  
Income before provision for income tax $ 252,427   $ 15,112  
           
MarkWest Energy Partners, L.P.
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,
2012 2011 2012 2011

 

 

 

Net income $ 187,136 $ 89,205 $ 203,409

 

$ 14,534
Depreciation, amortization, impairment, and other non-cash operating expenses 56,806 50,772 110,238

 

98,217
Loss on redemption of debt, net of tax benefit - - -

 

39,499
Amortization of deferred financing costs and discount 1,245 1,443 2,515

 

2,871
Non-cash (earnings) loss from unconsolidated affiliate (551 ) 216 (542 )

 

755
Distributions from unconsolidated affiliate 800 300 1,700

 

300
Non-cash compensation expense 2,579 1,134 5,289 2,712
Non-cash derivative activity (193,744 ) (55,663 ) (145,527 ) 24,121
Provision for income tax - deferred 39,664 10,619 28,868

 

(3,567 )
Cash adjustment for non-controlling interest of consolidated subsidiaries (1,006 ) (15,536 ) (2,023 ) (28,058 )
Revenue deferral adjustment 1,701 2,422 3,969 10,365
Other 581 1,496 2,789 3,203
Maintenance capital expenditures, net of joint venture partner contributions   (4,028 )   (3,464 )   (10,324 )   (5,872 )
Distributable cash flow $ 91,183   $ 82,944   $ 200,360   $ 159,080  
 
Maintenance capital expenditures $ 4,028 $ 3,892 $ 10,324 $ 6,398
Growth capital expenditures   323,912     116,572     571,879     227,718  
Total capital expenditures 327,940 120,464 582,203

 

234,116
Acquisitions   506,797     -     506,797     230,728  
Total capital expenditures and acquisitions 834,737 120,464 1,089,000 464,844
Joint venture partner contributions   -    

(18,850

)   -     (54,027 )
Total capital expenditures and acquisitions, net $ 834,737   $ 101,614   $ 1,089,000   $ 410,817  
 
Distributable cash flow $ 91,183 $ 82,944 $ 200,360 $ 159,080
Maintenance capital expenditures, net 4,028 3,464 10,324 5,872
Changes in receivables and other assets 54,727 (35,268 ) 112,382 (15,399 )
Changes in accounts payable, accrued liabilities and other long-term liabilities (100,435 ) 25,865 (65,191 ) 30,967
Derivative instrument premium payments, net of amortization - 1,099

 

- 2,144
Cash adjustment for non-controlling interest of consolidated subsidiaries 1,006 15,536

 

2,023 28,058
Other   (1,985 )   (2,595 )  

(3,461

)   (4,358 )
Net cash provided by operating activities $ 48,524   $ 91,045   $ 256,437   $ 206,364  
 
             
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,
2012 2011 2012 2011
 
Net income $ 187,136 $ 89,205 $ 203,409 $ 14,534
Non-cash compensation expense 2,579 1,134 5,289 2,712
Non-cash derivative activity (193,744 ) (55,663 ) (145,527 ) 24,121
Interest expense (1) 25,826 27,092 54,378 54,548
Depreciation, amortization, impairment, and other non-cash operating expenses 56,806 50,772 110,238 98,217
Loss on redemption of debt - - - 43,328
Provision for income tax 44,473 14,708 49,018 578
Adjustment for cash flow from unconsolidated affiliate 249 516 1,158 1,055
Adjustment related to non-guarantor, consolidated subsidiaries (2) 7,716 (7,416 ) (13,483 ) (22,106 )
Other   (508 )   (344 )   (1,005 )   (796 )
Adjusted EBITDA $ 130,533   $ 120,004   $ 263,475   $ 216,191  
 
(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 correlation of NGL prices to crude oil. The table below reflects MarkWest’s estimate of the range of DCF for 2012 given actual results through June 30, 2012, and forecasted crude oil and natural gas prices for the remainder of 2012. The analysis assumes various combinations of crude oil prices and the ratio of crude oil to gas based on three NGL correlation scenarios, including:

a. The three-year NGL correlation to crude for the remainder of 2012.
b. One standard deviation above the three-year NGL correlation to crude for the remainder of 2012.
c. One standard deviation below the three-year NGL correlation to crude for the remainder of 2012.
 

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

Estimated Range of 2012 DCF

                                                 
                  Natural Gas Price (Henry Hub)  
 

Crude Oil Price
(WTI)

      Three-year NGL Correlation to Crude       $ 2.00       $ 2.50       $ 3.00       $ 3.50       $ 4.00  

One standard deviation above

      $ 536       $ 534       $ 532       $ 530       $ 528  
$110 Three-year NGL correlation to crude       $ 491       $ 489       $ 487       $ 485       $ 483  
       

One standard deviation below

      $ 449       $ 447       $ 445       $ 443       $ 441  

One standard deviation above

      $ 536       $ 534       $ 532       $ 530       $ 528  
$100 Three-year NGL correlation to crude       $ 478       $ 476       $ 474       $ 472       $ 470  
       

One standard deviation below

      $ 449       $ 447       $ 445       $ 443       $ 441  

One standard deviation above

      $ 499       $ 497       $ 495       $ 493       $ 491  
$90 Three-year NGL correlation to crude       $ 464       $ 462       $ 460       $ 458       $ 456  
       

One standard deviation below

      $ 429       $ 427       $ 425       $ 424       $ 422  

One standard deviation above

      $ 482       $ 480       $ 478       $ 476       $ 474  
$80 Three-year NGL correlation to crude       $ 452       $ 450       $ 448       $ 446       $ 444  
       

One standard deviation below

      $ 421       $ 419       $ 417       $ 416       $ 413  

One standard deviation above

      $ 468       $ 466       $ 464       $ 462       $ 460  
$70 Three-year NGL correlation to crude       $ 441       $ 439       $ 437       $ 435       $ 433  
       

One standard deviation below

      $ 413       $ 412       $ 410       $ 408       $ 406  
                       

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 correlations 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 correlation 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