MarkWest Energy Partners Announces Major Expansion Projects and Reports Record Financial and Operational Results for Second Quarter 2014

  • Second quarter DCF of $161.7 million and increased quarterly distribution of 88 cents per common unit with 104 percent distribution coverage
  • Placed into service five major infrastructure projects, consisting of two processing plants with 320 MMcf/d of capacity in the Marcellus Shale, a 200 MMcf/d processing plant in the Utica Shale, 20,000 Bbl/d of ethane and heavier fractionation in the Marcellus Shale, and a 40,000 Bbl/d de-ethanization facility in the Utica Shale
  • Announced 7 major infrastructure projects adding 720 MMcf/d of processing capacity and 110,000 Bbl/d of fractionation capacity
  • 19 major processing and fractionation facilities under construction and maintains capital forecast of $2.0 to $2.3 billion in 2014 and approximately $2.0 billion in 2015
  • Achieved investment grade rating on the $1.3 billion Senior Secured Credit Facility
  • Increased fee-based net operating margin to 71 percent from 61 percent when compared to the second quarter of 2013
  • Narrowed 2014 DCF forecast to $630 to $670 million, which increases midpoint to $650 million
  • Achieved the number one ranking in the 2014 Oil & Natural Gas Midstream Services Customer Satisfaction Survey conducted by EnergyPoint Research. The Partnership has achieved the highest ranking for total customer satisfaction in four out of five surveys that EnergyPoint has conducted since 2006

DENVER--()--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 $161.7 million for the three months ended June 30, 2014, and $310.2 million for the six months ended June 30, 2014. DCF for the three months ended June 30, 2014 represents distribution coverage of 104 percent. The second quarter distribution of $155.8 million, or $0.88 per common unit, will be paid to unitholders on August 14, 2014. The second quarter 2014 distribution represents an increase of $0.01 per common unit or 1.2 percent over the first quarter 2014 distribution and an increase of $0.04 per common unit or 4.8 percent compared to the second quarter 2013 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, 2014, of $208.2 million and $395.8 million, respectively, compared to $155.7 million and $296.5 million for the respective three and six months ended June 30, 2013. 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, 2014 of $10.1 million and $38.6 million, respectively. Income before provision for income tax includes non-cash losses associated with the change in fair value of derivative instruments of $18.8 million and $7.0 million for the respective three and six months ended June 30, 2014. Excluding these items, income before provision for income tax for the three and six months ended June 30, 2014 would have been $28.9 million and $45.6 million, respectively.

“We are excited to announce major capacity expansions and record financial and operational performance for the second quarter of 2014,” stated Frank Semple, Chairman, President, and Chief Executive Officer. “The completion of five major infrastructure projects in the Marcellus and Utica Shales over the past three months has provided our producer customers the ability to continue expanding their rich-gas development programs. Due to their ongoing success, we expect overall system volumes to continue to rapidly expand and provide us with unique opportunities to significantly grow cash flow and achieve future distribution growth targets.”

BUSINESS HIGHLIGHTS

Marcellus:

  • In May, the Partnership announced that it will increase total processing capacity at the Mobley complex in Wetzel County, West Virginia to 920 million cubic feet per day (MMcf/d) with the construction of an additional 200 MMcf/d processing plant. The new plant is anchored by a long-term, fee-based contract with EQT Corporation (NYSE: EQT) and is expected to be in service by the second quarter of 2015. The Mobley complex currently consists of three plants with 520 MMcf/d of total processing capacity and during the fourth quarter of this year, the Partnership will begin operations of a fourth plant at the complex, increasing capacity to 720 MMcf/d. The Mobley complex supports growing Marcellus rich-gas production from EQT Corporation, Magnum Hunter Resources Corporation (NYSE: MHR), Stone Energy Corporation (NYSE: SGY), CONSOL Energy Inc. (NYSE: CNX), and Noble Energy, Inc. (NYSE: NBL).
  • In May, the Partnership commenced operations of a fifth 200 MMcf/d Majorsville processing plant at the Majorsville complex in Marshall County, West Virginia. The new plant is anchored by Range Resources Corporation (NYSE: RRC) (Range Resources) and has increased the total capacity of the Majorsville Complex to 870 MMcf/d.
  • In May, the Partnership completed the 120 MMcf/d Bluestone II processing plant in Butler County, Pennsylvania. The new plant is anchored by a long term, fee-based contract with Rex Energy Corporation (NASDAQ: REXX). In conjunction with new processing, the Partnership began operations of an additional 20,000 barrels per day (Bbl/d) of ethane and heavier fractionation infrastructure to support growing NGL production from the rich-gas areas of the northeast Marcellus Shale and Upper Devonian formation. To facilitate the production of ethane at the Bluestone complex, the Partnership has also completed a 32-mile purity ethane pipeline connecting to the Mariner West project.
  • Today, the Partnership is announcing that it will construct a seventh 200 MMcf/d processing plant at the Sherwood complex in Doddridge County, West Virginia, at the request of Antero Resources Corporation (NYSE: AR) (Antero Resources). The new plant is anchored by long-term, fee-based agreements and will expand total capacity at the Sherwood complex to 1.4 billion cubic feet per day (Bcf/d) by the third quarter of 2015. Later this month, the Partnership will begin operations of the Sherwood IV plant. Antero Resources is the anchor producer supporting the Sherwood complex and continues to develop its prolific rich-gas acreage position in northern West Virginia.
  • Today, the Partnership is announcing that it will construct a sixth processing complex in the Marcellus Shale. The new Hillman complex will be located in Washington County, Pennsylvania and will support Range Resources’ rapidly growing rich-gas production. The Hillman complex will initially consist of Hillman I, a 200 MMcf/d processing plant, and an associated de-ethanization facility. The Hillman complex is scheduled to become operational during the first quarter of 2016. Propane and heavier natural gas liquids recovered at the Hillman complex will be transported by a new pipeline to the Houston complex for fractionation.

Utica:

  • In June, the Partnership and The Energy & Minerals Group (EMG) announced an expansion of the Hopedale fractionation and marketing complex (Hopedale complex) in Harrison County, Ohio to support growing NGL production from the Marcellus and Utica Shales. The expansion will double the propane and heavier fractionation capacity at the Hopedale complex to 120,000 Bbl/d and is expected to be operational in the first quarter of 2015.
  • In June, Summit Midstream Partners, LLC (Summit), the privately held company that owns and controls the general partner of Summit Midstream Partners, LP (NYSE: SMLP), exercised the option it acquired from a subsidiary of Gulfport Energy Corporation (NASDAQ: GPOR) (Gulfport Energy) to purchase a 40% equity interest in two of the Partnership’s and EMG’s unconsolidated affiliates, Ohio Gathering Company, L.L.C. and Ohio Condensate Company, L.L.C., through a cash investment of approximately $324.7 million and $7.3 million, respectively, that was received in May 2014 and true-up payments of $16.5 million and $1.3 million, respectively, that were received in July 2014.
  • In July, MarkWest Utica EMG completed the 200 MMcf/d Seneca III processing plant in Noble County, Ohio. The new plant is anchored by Antero Resources under a long-term, fee-based contract and has expanded the total processing capacity of the Seneca complex to 600 MMcf/d. In order to support the continued growth of Antero Resources and other producers, the Partnership expects to complete a fourth 200 MMcf/d processing plant in the second quarter of 2015.
  • In July, MarkWest Utica EMG completed a 40,000 Bbl/d de-ethanization facility at the Cadiz complex in Harrison County, Ohio. This new fractionation facility will provide MarkWest Utica EMG’s producer customers with the ability to meet residue gas quality specifications and downstream ethane pipeline commitments. Purity ethane produced at the new Cadiz facility will be delivered to the ATEX pipeline.
  • Today, MarkWest Utica EMG is announcing the development of Cadiz III, a 200 MMcf/d processing plant at the Cadiz complex in Harrison County, Ohio. The new facility is expected to begin operations during the first quarter of 2015 and will increase total processing capacity of the Cadiz complex to 525 MMcf/d. The Cadiz complex currently consists of a 125 MMcf/d cryogenic processing plant and during September 2014, MarkWest Utica EMG will begin operations of the 200 MMcf/d Cadiz II plant to support rich-gas production from Gulfport Energy and other producers.

Southwest:

  • In April, the Partnership’s Centrahoma Joint Venture (Centrahoma) commenced operations of the Stonewall processing facility, a 120 MMcf/d plant in the Woodford Shale in Southwest Oklahoma. The completion of the Stonewall plant increases Centrahoma’s total processing capacity to 220 MMcf/d.
  • Today, the Partnership is announcing that it will construct a fourth processing plant at its Carthage facilities in Panola County, Texas to support growing rich-gas production from the Haynesville Shale and Cotton Valley formation. The new plant will have an initial capacity of 120 MMcf/d and is scheduled to begin operations in the first quarter of 2015. Once completed, total processing capacity at the Partnership’s East Texas operations will increase to 520 MMcf/d.

Capital Markets

  • Year-to-date, the Partnership has issued 15.1 million new units and received net proceeds of approximately $976.9 million.
  • Achieved investment grade rating by Standard & Poor’s on the Partnership’s Senior Secured Credit Facility.

FINANCIAL RESULTS

Balance Sheet

  • As of June 30, 2014, the Partnership had $74.0 million of cash and cash equivalents in wholly owned subsidiaries and $847.5 million of remaining capacity under its $1.3 billion Senior Secured Credit Facility after consideration of $11.3 million of outstanding letters of credit and $441.2 million of outstanding borrowings.

Operating Results

  • Operating income before items not allocated to segments for the three months ended June 30, 2014, was $220.1 million, an increase of $42.6 million when compared to $177.5 million over the same period in 2013. This increase was primarily attributable to higher processing volumes. Processed volumes continued to increase in the second quarter of 2014, growing approximately 53 percent when compared to the second quarter of 2013, primarily due to the Partnership’s Marcellus and Utica segments.

    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 (losses) gains on commodity derivative instruments. Realized (losses) gains on commodity derivative instruments were ($1.9) million in the second quarter of 2014 and $2.0 million in the second quarter of 2013.

Capital Expenditures

  • For the three months ended June 30, 2014, the Partnership’s portion of capital expenditures was $608.1 million.

ADJUSTED EBITDA, DCF AND CAPITAL EXPENDITURE FORECAST

The Partnership forecasts its 2014 Adjusted EBITDA in a range of $810 million to $870 million and has narrowed its 2014 DCF forecast to a range of $630 million to $670 million based on its current forecast. The Partnership has become less sensitive to changes in commodity prices as a result of significant increases in fee-based income. An updated sensitivity analysis for forecasted 2014 DCF based on changes in composite NGL prices and changes in volume assumptions is provided within the tables of this press release.

The Partnership’s portion of growth capital expenditures for 2014 is forecasted in a range of $2.0 billion to $2.3 billion and for 2015 is forecasted at approximately $2.0 billion. Maintenance capital for 2014 is forecasted at approximately $25 million.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Thursday, August 7, 2014, at 12:00 p.m. Eastern Time to review its second quarter 2014 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 and associated second quarter 2014 earnings call presentation, 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 Partnership’s website or by dialing (800) 839-1248 (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, 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   2014     2013     2014     2013  
Revenue:
Revenue $ 525,119 $ 395,421 $ 1,041,562 $ 768,879
Derivative (loss) gain   (6,753 )   19,699     (10,720 )   19,514  
Total revenue   518,366     415,120     1,030,842     788,393  
 
Operating expenses:
Purchased product costs 215,824 155,359 427,388 307,916
Derivative loss (gain) related to purchased product costs 11,964 (20,432 ) 4,166 (31,136 )
Facility expenses 83,545 62,797 167,250 122,307
Derivative loss related to facility expenses 2,045 800 1,777 468
Selling, general and administrative expenses 27,701 25,499 62,991 50,741
Depreciation 104,078 71,562 206,007 139,579
Amortization of intangible assets 15,965 17,092 31,943 31,922
Loss (gain) on sale or disposal of property, plant and equipment 1,450 (37,736 ) 1,357 (37,598 )
Accretion of asset retirement obligations   168     157     336     509  
Total operating expenses   462,740     275,098     903,215     584,708  
 
Income from operations 55,626 140,022 127,627 203,685
 
Other (expense) income:
Equity in (loss) earnings from unconsolidated affiliates (721 ) 430 (471 ) 665
Interest income 10 62 19 211
Interest expense (43,391 ) (36,955 ) (84,375 ) (75,291 )
Amortization of deferred financing costs and debt discount (a component of interest expense) (1,449 ) (1,784 ) (4,273 ) (3,614 )
Loss on redemption of debt - - - (38,455 )
Miscellaneous income, net   33     6     43     6  
Income before provision for income tax 10,108 101,781 38,570 87,207
 
Provision for income tax (benefit) expense:
Current (19 ) (2,745 ) 326 (8,159 )
Deferred   (2,921 )   19,028     9,280     30,999  
Total provision for income tax   (2,940 )   16,283     9,606     22,840  
 
Net income 13,048 85,498 28,964 64,367
 
Net (income) loss attributable to non-controlling interest   (4,071 )   (1,799 )   (7,495 )   3,874  
 
Net income attributable to the Partnership's unitholders $ 8,977   $ 83,699   $ 21,469   $ 68,241  
 
Net income attributable to the Partnership's common unitholders per common unit:
Basic $ 0.05   $ 0.63   $ 0.13   $ 0.52  
Diluted $ 0.05   $ 0.55   $ 0.12   $ 0.45  
 
Weighted average number of outstanding common units:
Basic   164,613     131,227     161,727     129,928  
Diluted   181,237     151,866     178,378     150,580  
 
Cash Flow Data
Net cash flow provided by (used in):
Operating activities $ 244,450 $ 93,838 $ 356,823 $ 177,596
Investing activities $ (429,684 ) $ (825,660 ) $ (1,005,158 ) $ (1,435,021 )
Financing activities $ 361,165 $ 434,867 $ 862,442 $ 1,266,223
 
Other Financial Data
Distributable cash flow $ 161,734 $ 128,391 $ 310,180 $ 238,216
Adjusted EBITDA $ 208,231 $ 155,741 $ 395,798 $ 296,542
 
 
Balance Sheet Data June 30, 2014 December 31, 2013
Total assets $ 10,183,390 $ 9,396,423
Total debt $ 3,464,637 $ 3,023,071
Total equity $ 5,401,550 $ 4,798,133
 
MarkWest Energy Partners, L.P.
Operating Statistics
       
Three months ended June 30, Six months ended June 30,
2014 2013 2014 2013
Marcellus
Gathering system throughput (Mcf/d) (1) 599,500 544,000 600,500 526,700
Natural gas processed (Mcf/d) 1,823,200 1,033,700 1,732,500 931,400
 
C2 (purity ethane) produced (Bbl/d) 45,900 - 47,400 -
C3+ fractionated (Bbl/d) (2) 82,200 48,900 76,200 43,000
Total NGLs fractionated (Bbl/d) 128,100 48,900 123,600 43,000
 
Utica
Gathering system throughput (Mcf/d) 188,700 46,300 184,700 27,800
Natural gas processed (Mcf/d) (3) 293,800 46,300 272,700 27,200
C3+ fractionated (Bbl/d) (2) 13,500 - 12,900 -
 
Northeast
Natural gas processed (Mcf/d) 281,500 296,400 268,600 299,500
NGLs fractionated (Bbl/d) (4) 17,500 18,100 17,500 17,600
 
Keep-whole sales (gallons, in thousands) 24,800 27,100 57,000 64,500
Percent-of-proceeds sales (gallons, in thousands) 29,900 32,200 56,000 67,100
Total NGL sales (gallons, in thousands) (5) 54,700 59,300 113,000 131,600
 
Crude oil transported for a fee (Bbl/d) 10,600 9,700 10,200 10,000
 
Southwest
East Texas gathering systems throughput (Mcf/d) 549,500 521,700 522,800 510,500
East Texas natural gas processed (Mcf/d) 398,500 377,600 383,400 358,600
East Texas NGL sales (gallons, in thousands) (6) 109,500 86,200 203,400 158,400
 
Western Oklahoma gathering system throughput (Mcf/d) (7) 348,200 220,000 322,700 211,400
Western Oklahoma natural gas processed (Mcf/d) 296,300 189,900

269,800

188,100
Western Oklahoma NGL sales (gallons, in thousands) (8) 56,900 42,900 111,300 97,700
 
Southeast Oklahoma gathering system throughput (Mcf/d) 414,500 473,300 398,200 467,300
Southeast Oklahoma natural gas processed (Mcf/d) (9) 186,600 160,400 167,000 155,800
Southeast Oklahoma NGL sales (gallons, in thousands) 29,200 54,000 50,200 93,300
 
Other Southwest gathering system throughput (Mcf/d) (10) 48,900 39,900 47,900 30,300
 
Gulf Coast refinery off-gas processed (Mcf/d) 112,000 117,700 111,300 106,600
Gulf Coast liquids fractionated (Bbl/d) (11) 21,000 22,100 20,200 19,700
Gulf Coast NGL sales (gallons, in thousands) (11) 80,300 84,600 153,300 149,700
 
(1)   The 2013 volumes exclude Sherwood gathering for comparability as this system was sold to Summit in June 2013.
(2)

The Marcellus segment includes both the Houston Fractionation Facility and Marcellus’ portion utilized of the jointly owned Hopedale Fractionation Facility. Hopedale is currently jointly owned 60% and 40% by MarkWest Liberty Midstream and MarkWest Utica EMG, respectively. The Utica segment includes only the portion it utilized of the jointly owned Hopedale Fractionation Facility. Operations began in January 2014. The volumes reported for 2014 are the average daily rate for the days of operation.

(3) Utica operations began in August 2013.
(4) Includes NGLs fractionated for Utica and Marcellus segments.
(5) Represents sales at the Siloam fractionator. The total sales exclude approximately 8,757,000 gallons and 6,611,000 gallons sold by the Northeast on behalf of Marcellus for the three months ended June 30, 2014 and 2013, respectively. The total sales exclude approximately 22,010,000 gallons and 6,818,000 gallons sold by the Northeast on behalf of Marcellus for the six months ended June 30, 2014 and 2013, respectively.
(6) Excludes zero and 318,000 gallons processed in conjunction with take in kind contracts for the respective three and six months ended June 30, 2014 and 3,989,000 and 12,351,000 gallons processed in conjunction with take in kind contracts for the respective three and six months ended June 30, 2013.
(7) 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.
(8) Excludes 41,969,000 and 53,685,000 gallons processed in conjunction with take in kind contracts for the respective three and six months ended June 30, 2014.
(9)

The natural gas processing in Southeast Oklahoma is outsourced to our joint venture Centrahoma or other third-party processors.

(10) Excludes lateral pipelines where revenue is not based on throughput.
(11) Excludes Hydrogen volumes.
 
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, 2014 Marcellus Utica Northeast Southwest Eliminations (1) Total
Segment revenue $ 183,734 $ 30,826 $ 43,777 $ 271,140 $ (900 ) $ 528,577
 
Operating expenses:
Purchased product costs 39,710 7,353 15,169 153,628 - 215,860
Facility expenses   33,755     12,174     8,509   34,354   (900 )   87,892
Total operating expenses before items not allocated to segments 73,465 19,527 23,678 187,982 (900 ) 303,752
 
Portion of operating income attributable to non-controlling interests   -     4,687     -   6   -     4,693
Operating income before items not allocated to segments $ 110,269   $ 6,612   $ 20,099 $ 83,152 $ -   $ 220,132
 
 
Three months ended June 30, 2013 Marcellus 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  
 
(1) Amounts represent revenues and expenses associated with the Northeast segment fractionation completed on behalf of the Marcellus segment, which occurs when NGL volumes in the Marcellus exceed its fractionation capacity.
 

Three months ended June 30,

  2014     2013  
 
Operating income before items not allocated to segments $ 220,132 $ 177,472
Portion of operating income (loss) attributable to non-controlling interests 4,184 (1,090 )
Derivative (loss) gain not allocated to segments (20,762 ) 39,331
Revenue adjustment for unconsolidated affiliate (3,833 ) -
Revenue deferral adjustment and other 375 (1,437 )
Compensation expense included in facility expenses not allocated to segments (903 ) (368 )
Facility expense and purchase product cost adjustments for unconsolidated affiliate 2,598 -
Portion of operating loss attributable to non-controlling interests of an unconsolidated affiliate 509 -
Facility expenses adjustments 2,688 2,688
Selling, general and administrative expenses (27,701 ) (25,499 )
Depreciation (104,078 ) (71,562 )
Amortization of intangible assets (15,965 ) (17,092 )
(Loss) gain on disposal of property, plant and equipment (1,450 ) 37,736
Accretion of asset retirement obligations   (168 )   (157 )
Income from operations 55,626 140,022

Other (expense) income:

Equity in (loss) earnings from unconsolidated affiliates

(721 ) 430
Interest income 10 62
Interest expense (43,391 ) (36,955 )

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

(1,449 ) (1,784 )
Miscellaneous income, net   33     6  
Income before provision for income tax $ 10,108   $ 101,781  
 
           
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, 2014 Marcellus Utica Northeast Southwest Eliminations (1) Total
Segment revenue $ 358,893 $ 54,592 $ 105,030 $ 530,470 $ (2,471 ) $ 1,046,514
 
Operating expenses:
Purchased product costs 74,000 11,488 35,624 306,312 - 427,424
Facility expenses   69,228     24,026     15,623   66,876   (2,471 )   173,282
Total operating expenses before items not allocated to segments 143,228 35,514 51,247 373,188 (2,471 ) 600,706
 
Portion of operating income attributable to non-controlling interests   -     7,823     -   5   -     7,828
Operating income before items not allocated to segments $ 215,665   $ 11,255   $ 53,783 $ 157,277 $ -   $ 437,980
 
 
Six months ended June 30, 2013 Marcellus 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  
 
(1) Amounts represent revenues and expenses associated with the Northeast segment fractionation completed on behalf of the Marcellus segment, which occurs when NGL volumes in the Marcellus exceed its fractionation capacity.
 
Six months ended June 30,
  2014     2013  
 
Operating income before items not allocated to segments $ 437,980 $ 339,200
Portion of operating income (loss) attributable to non-controlling interests 7,319 (2,365 )
Derivative (loss) gain not allocated to segments (16,663 ) 50,182
Revenue adjustment for unconsolidated affiliate (3,833 ) -
Revenue deferral adjustment and other (1,119 ) (2,801 )
Compensation expense included in facility expenses not allocated to segments (1,906 ) (754 )
Facility expense and purchase product cost adjustments for unconsolidated affiliate 2,598 -
Portion of operating loss attributable to non-controlling interests of an unconsolidated affiliate 509 -
Facility expenses adjustments 5,376 5,376
Selling, general and administrative expenses (62,991 ) (50,741 )
Depreciation (206,007 ) (139,579 )
Amortization of intangible assets (31,943 ) (31,922 )
(Loss) gain on disposal of property, plant and equipment (1,357 ) 37,598
Accretion of asset retirement obligations   (336 )   (509 )
Income from operations 127,627 203,685

Other (expense) income:

Equity in (loss) earnings from unconsolidated affiliates

(471 ) 665
Interest income 19 211
Interest expense (84,375 ) (75,291 )

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

(4,273 ) (3,614 )
Loss on redemption of debt - (38,455 )
Miscellaneous income, net   43     6  
Income before provision for income tax $ 38,570   $ 87,207  
 

 

       
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,
  2014     2013     2014     2013  
 
Net income $ 13,048 $ 85,498 $ 28,964 $ 64,367
Depreciation, amortization and other non-cash operating expenses 120,361 88,889 239,311 172,166
Loss (gain) on sale or disposal of property, plant and equipment 1,450 (34,689 ) 1,357 (34,551 )
Loss on redemption of debt, net of tax benefit - - - 36,178
Amortization of deferred financing costs and debt discount 1,449 1,784 4,273 3,614

Equity in loss (earnings) from unconsolidated affiliates

721 (430 ) 471 (665 )
Distributions from unconsolidated affiliates 2,541 1,962 3,910 2,728
Non-cash compensation expense 1,835 1,157 5,802 3,541
Unrealized loss (gain) on derivative instruments 18,844 (37,287 ) 7,024 (46,320 )
Deferred income tax (benefit) expense (2,921 ) 19,028 9,280 30,999
Cash adjustment for non-controlling interest of consolidated subsidiaries (3,178 ) 1,720 (5,296 ) 3,489
Revenue deferral adjustment 1,722 1,645 3,813 3,410
Other (1) 12,867 3,318 21,022 5,355
Maintenance capital expenditures (2)   (7,005 )   (4,204 )   (9,751 )   (6,095 )
Distributable cash flow $ 161,734   $ 128,391   $ 310,180   $ 238,216  
 
Maintenance capital expenditures (2) $ 7,005 $ 4,204 $ 9,751 $ 6,095
Growth capital expenditures of consolidated subsidiaries 681,198 799,322 1,265,572 1,428,989
Growth capital expenditures of unconsolidated subsidiaries (3)   40,013       -     40,013     -  
Total capital expenditures 728,216 803,526 1,315,336 1,435,084
Acquisitions, net of cash acquired   -     225,210     -     225,210  
Total capital expenditures and acquisitions 728,216 1,028,736 1,315,336 1,660,294
Joint venture partner contributions  

(120,106

)   (360,499 )  

(120,106

)   (625,819 )
Total capital expenditures and acquisitions, net $

608,110

  $ 668,237   $

1,195,230

  $ 1,034,475  
 
Distributable cash flow $ 161,734 $ 128,391 $ 310,180 $ 238,216
Maintenance capital expenditures (2) 7,005 4,204 9,751 6,095
Changes in receivables, inventories and other assets (35,710 ) (68,767 ) (42,763 ) (67,501 )
Changes in accounts payable, accrued liabilities and other long-term liabilities 120,755 37,601 95,041 10,053
Cash adjustment for non-controlling interest of consolidated subsidiaries 3,178 (1,720 ) 5,296 (3,489 )
Other   (12,512 )   (5,871 )   (20,682 )   (5,778 )
Net cash provided by operating activities $ 244,450   $ 93,838   $ 356,823   $ 177,596  
 

(1)

 

Other includes amounts related to capitalized interest associated with joint venture capital expenditures and fees earned related to development of joint venture capital projects.

(2)

Net of joint venture partner contributions.

(3)

Growth capital expenditures for Ohio Gathering, L.L.C.

 
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,
  2014     2013     2014   2013  
 
Net income $ 13,048 $ 85,498 $ 28,964 $ 64,367
Non-cash compensation expense 1,835 1,157 5,802 3,541
Unrealized loss (gain) on derivative instruments 18,844 (37,287 ) 7,024 (46,320 )
Interest expense (1) 42,765 36,610 84,483 74,632
Depreciation, amortization and other non-cash operating expenses 120,361 88,889 239,311 172,166
Loss (gain) on sale or disposal of property, plant and equipment 1,450 (37,736 ) 1,357 (37,598 )
Loss on redemption of debt - - - 38,455

Provision for income tax (benefit) expense

(2,940 ) 16,283 9,606 22,840
Adjustment for cash flow from unconsolidated affiliates 3,262 1,532 4,381 2,063
Other (2)   9,606     795     14,870   2,396  
Adjusted EBITDA $ 208,231   $ 155,741   $ 395,798 $ 296,542  
 

(1)

 

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

(2)

For the three and six months ended June 30, 2014, Other includes amounts related to capitalized interest associated with joint venture capital expenditures and fees earned related to development of joint venture capital projects.

 

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

The Partnership periodically estimates the effect on DCF resulting from changes in its volume forecast and NGL prices. The Partnership has become less sensitive to changes in commodity prices as a result of significant increases in fee-based income. For the full year 2014, the Partnership estimates that net operating margin will be over 70 percent fee-based. In addition, the Partnership has hedged approximately 60 percent of its forecasted 2014 NGL exposure on a volumetric basis, over 90 percent of these with direct product hedges.

The analysis further assumes derivative instruments outstanding as of August 6, 2014, and production volumes estimated through December 31, 2014. The range of stated hypothetical changes in commodity prices considers current and historic market performance.

Estimated Range of 2014 DCF

                     
Volume Forecast (1)
            Low Case     Base Case     High Case

NGL $/Gal
(2) (3)

$1.05 $ 635     $ 659     $ 680
$1.00 $ 631     $ 654     $ 676
$0.95 $ 627     $ 650     $ 671
$0.90 $ 623     $ 646     $ 667
    $0.85     $ 619     $ 641     $ 662
       
(1)   Volume Forecast is increased/decreased by 10% in the Marcellus and Utica segments for the High and Low Cases.
(2) The composition is based on the Partnership’s projected barrel of approximately: Ethane: 35%, Propane: 35%, Iso-Butane: 6%, Normal Butane: 12%, Natural Gasoline: 12%.
(3) Composite NGL prices are based on the Partnership’s average forecasted price.

The table is based on current information, expectations, and beliefs concerning future developments and their potential effects, and does not consider actions the Partnership’s management may take to mitigate exposure to changes. Further, the table does not consider the effects that such hypothetical adverse changes may have on overall economic activity. Historical volumes, prices and correlations do not guarantee future results.

Although the Partnership believes the expectations reflected in this analysis are reasonable, the Partnership 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, market conditions and constraints, production, NGL composition, infrastructure availability, market participants, and ratios between product 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 the Partnership’s periodic reports filed with the SEC, specifically those under the heading “Risk Factors.”

Contacts

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

Release Summary

MarkWest Energy Partners, L.P. Earnings Release

Contacts

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