MarkWest Energy Partners Reports Record 2014 Fourth Quarter and Full-Year Financial Results

  • Reported record DCF of $201.0 million for the fourth quarter and $706.4 million for the full-year 2014, and record Adjusted EBITDA of $243.0 million for the fourth quarter and $874.3 million for the full-year 2014. Full-year 2014 DCF and Adjusted EBITDA increased by approximately 46 and 44 percent, respectively from the full-year 2013
  • Increased quarterly distribution to 90 cents per common unit while maintaining 120 percent distribution coverage
  • Reported record processed gas volumes of over 3.2 Bcf/d from the Marcellus and Utica during the fourth quarter, an increase of over 100 percent from the fourth quarter 2013
  • Reported record fractionated volumes from the Marcellus and Utica of over 200,000 Bbl/d of NGLs fractionated during the fourth quarter, an increase of over 100 percent from the fourth quarter 2013
  • Placed into service 720 MMcf/d of new processing capacity, with the addition of Sherwood V and Mobley IV in the Marcellus Shale; Cadiz II in the Utica Shale; and Carthage IV in East Texas
  • Commenced operations of a third 60,000 Bbl/d propane and heavier fractionation facility in Northeast United States
  • Processing capacity utilization was 80 percent for the fourth quarter of 2014
  • Revised 2015 capital forecast to a range of $1.5 billion to $1.9 billion, and 2016 forecast to approximately $1.5 billion to align with producers' current drilling programs
  • Revised 2015 DCF forecast to a range of $700 million to $800 million and Adjusted EBITDA forecast to a range of $925 million to $1,025 million
  • The Partnership forecasts distributions of approximately $3.70 for 2015, $3.97 for 2016 and an annual growth rate of 10% for 2017 to 2020

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 $201.0 million for the three months ended December 31, 2014, and $706.4 million for the year ended December 31, 2014. DCF for the three months and year ended December 31, 2014 represents distribution coverage of 120 percent and 112 percent respectively. The fourth quarter distribution of $168.1 million, or $0.90 per common unit, was paid to unitholders on February 13, 2015. The fourth quarter 2014 distribution represents an increase of $0.01 per common unit or 1.1 percent over the third quarter 2014 distribution and an increase of $0.04 per common unit or 4.7 percent compared to the fourth 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 months ended December 31, 2014, of $243.0 million and $874.3 million for the year ended December 31, 2014, as compared to $155.5 million and $606.0 million for the three months and year ended December 31, 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 months and year ended December 31, 2014 of $66.9 million and $202.5 million, respectively. Income before provision for income tax includes non-cash gains associated with the change in fair value of derivative instruments of $63.9 million and $82.1 million for the respective three months and twelve months ended December 31, 2014. Income before provision for income tax includes a non-cash impairment associated with our Northeast segment of $62.4 million for the three and twelve months ended December 31, 2014. Excluding these items, income before provision for income tax for the three months and year ended December 31, 2014 would have been $65.4 million and $182.8 million, respectively.

“2014 was an exceptional year of growth at MarkWest as we completed 16 major processing and fractionation projects and delivered record operational and financial performance,” stated Frank Semple, Chairman, President and Chief Executive Officer of MarkWest. “Given the recent decline in commodity prices we are working with our producer customers to optimize our midstream operations to support their revised capital plans. The majority of our capital expenditures are in the Marcellus where we are currently processing approximately 90 percent of all rich-gas production. These Northeast Shales continue to provide the best drilling economics in the U.S. and our producer customers continue to deliver strong execution and volume growth. We look forward to another year of operational excellence, best-of-class customer service and solid distribution growth for our unitholders."

BUSINESS HIGHLIGHTS

Marcellus:

  • In November, the Partnership announced the completion of Sherwood V, a 200 million cubic feet per day (MMcf/d) processing plant at the Sherwood complex in Doddridge County, West Virginia. Sherwood V supports growing rich-gas production from Antero Resources Corporation (NYSE: AR) (Antero Resources) and has increased total processing capacity of the Sherwood complex to 1 billion cubic feet per day (Bcf/d). For the fourth quarter of 2014 the Sherwood complex operated at 84 percent utilization.
  • In November, the Partnership announced the completion of definitive agreements with PennEnergy Resources, LLC (PennEnergy Resources) to provide processing, fractionation and NGL marketing services in the Marcellus Shale. PennEnergy Resources is a growing producer operating in Beaver, Butler, and Armstrong counties of Pennsylvania and will be supported at the Partnership’s Keystone complex.
  • In December, the Partnership commenced operations of the 200 MMcf/d Mobley IV plant in Wetzel County, West Virginia. The new plant is supported by a long-term, fee-based contract with EQT Corporation (NYSE: EQT) and has increased total processing capacity of the Mobley Complex to 720 MMcf/d. For the fourth quarter of 2014 the Mobley complex operated at 98 percent utilization.
  • Today, the Partnership is announcing the development of Majorsville VII, a 200 MMcf/d processing plant at the Majorsville complex in Marshall County, West Virginia. The new facility is scheduled to begin operations during the first quarter of 2016 and will support Southwestern Energy Company (NYSE: SWN) (Southwestern) and Statoil ASA (NYSE: STO) (Statoil). Southwestern assumed the processing and fractionation agreements held by Chesapeake Energy Corporation (NYSE: CHK) and a portion of the agreements held by Statoil upon completion of its recent acquisition of 440,000 net acres in southwest Pennsylvania and West Virginia. Once completed, Majorsville VII will increase total capacity at the Majorsville complex approximately 1.3 Bcf/d.

Utica:

  • In November, MarkWest Utica EMG, a joint venture between the Partnership and The Energy & Minerals Group (EMG), commenced operations of the 200 MMcf/d Cadiz II plant to support rich-gas production from Gulfport Energy Corporation (NASDAQ: GPOR). MarkWest Utica EMG also announced the development of Cadiz IV, a 200 MMcf/d processing plant to support American Energy – Utica, LLC (AEU), an affiliate of American Energy Partners, LP. The new facility is scheduled to begin operations in the first quarter of 2016 and will increase MarkWest Utica EMG’s total processing capacity in Ohio to over 1.5 Bcf/d.
  • In November, the Partnership and MarkWest Utica EMG announced the development of a third fractionation facility at the Hopedale complex in Harrison County, Ohio. The new 60,000 barrels per day (Bbl/d) fractionator is scheduled to begin operations in the first quarter of 2016 and will increase total fractionation capacity for propane and heavier natural gas liquids to 283,000 Bbl/d in the Marcellus and Utica Shales.
  • In December, the Partnership and MarkWest Utica EMG commenced operations of a second fractionation facility at the Hopedale complex. The new facility doubled propane and heavier NGL fractionation capacity to 120,000 Bbl/d and jointly supports producers’ growing natural gas liquids (NGLs) production from the Marcellus and Utica Shales. For the fourth quarter of 2014 the C3+ fractionation capacity in the Marcellus and Utica operated at 102 percent utilization.
  • Today, Ohio Condensate Company, L.L.C., an entity owned by MarkWest Utica EMG Condensate, L.L.C. (MarkWest Utica EMG Condensate) and Summit Midstream Partners, LLC, is announcing the commencement of its condensate stabilization facility in Harrison County, Ohio. MarkWest Utica EMG Condensate is owned by the Partnership and EMG. The new facility consists of 23,000 Bbl/d of condensate stabilization capacity and is fully integrated with a storage and logistics terminal that is operated by a third-party and serves the facility exclusively.

Southwest:

  • In December, the Partnership commenced operations of a fourth processing plant at its Carthage complex in Panola County, Texas. The new plant has an initial capacity of 120 MMcf/d and supports growing rich-gas production from Anadarko Petroleum Corporation (NYSE: APC) (Anadarko) and other producers operating in the Haynesville Shale and Cotton Valley formation. With the completion of the new facility, the Partnership now operates 520 MMcf/d of highly utilized processing capacity in East Texas. For the fourth quarter of 2014 the East Texas complex operated at 100 percent utilization.
  • In February, the Partnership, together with Enterprise Products Partners L.P. (NYSE:EPD) (Enterprise), Anadarko and DCP Midstream Partners, LP (NYSE: DPM) (DCP Midstream) announced the formation of a joint venture under which Enterprise will assign a 45 percent ownership interest in its wholly owned Panola Pipeline Company, LLC. The interest will be evenly divided among the Partnership, Anadarko’s affiliate, WGR Asset Holding Company LLC, and DCP Midstream. The Panola Pipeline, which transports NGLs, originates in Carthage, Texas and extends 181 miles to Mont Belvieu, Texas. Enterprise recently announced plans to install 60 miles of new pipeline, as well as pumps and other associated equipment as part of an expansion project designed to increase capacity by 50,000 Bbl/d. The incremental capacity is expected to be available in the first quarter of 2016.
  • Today, the Partnership is announcing the execution of a definitive agreement with Newfield Exploration (NYSE: NFX) (Newfield) to support the development of resources in the Cana-Woodford. Under terms of the agreements, the Partnership will provide gathering and processing services for associated gas from Newfield’s STACK acreage, from the Woodford and Meramec Shales located in Kingfisher, Blaine and Canadian counties, Oklahoma. As part of the agreement, the Partnership is constructing a low- and high-pressure gas gathering system within Newfield’s area of operation, as well as a 60-mile trunk line to the Partnership’s Arapaho processing plant in Custer County, OK.

Capital Markets

  • During the fourth quarter of 2014, the Partnership issued 8.5 million new units and received net proceeds of approximately $584 million.
  • In November, the Partnership completed a public offering of $500 million of 4.875% senior unsecured notes priced at par due in 2024.

FINANCIAL RESULTS

Balance Sheet

  • As of December 31, 2014, the Partnership had $35.4 million of cash and cash equivalents in wholly owned subsidiaries and $1.2 billion of remaining capacity under its $1.3 billion Senior Secured Credit Facility after consideration of $11.3 million of outstanding letters of credit and $97.6 million of outstanding borrowings.

Operating Results

  • Operating income before items not allocated to segments for the three months ended December 31, 2014, was $240.5 million, an increase of $55.4 million when compared to $185.1 million over the same period in 2013. This increase was primarily attributable to higher processing volumes. Processed volumes continued to increase in the fourth quarter of 2014, growing approximately 70 percent when compared to the fourth 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 on commodity derivative instruments. Realized gains (losses) on commodity derivative instruments were $23.8 million in the fourth quarter of 2014 and ($8.7) million in the fourth quarter of 2013.

Capital Expenditures

  • For the three months ended December 31, 2014, the Partnership’s portion of capital expenditures was $637.4 million.

2015 ADJUSTED EBITDA, DCF, DISTRIBUTION GROWTH AND CAPITAL EXPENDITURE FORECAST

For 2015, the Partnership forecasts Adjusted EBITDA in a range of $925 million to $1,025 million and DCF in a range of $700 million to $800 million based on its current forecast of operational volumes and prices for natural gas liquids, crude oil, natural gas, and derivative instruments currently outstanding. A sensitivity analysis for forecasted 2015 DCF based on changes in composite NGL prices and changes in volume assumptions is provided within the tables of this press release.

The Partnership forecasts distributions of approximately $3.70 for 2015, $3.97 for 2016 and an annual growth rate of 10% for 2017 to 2020. The annualized distribution coverage ratio during the entire period is expected to be 1.0 times to 1.2 times.

The Partnership’s portion of growth capital expenditures for 2015 has been reduced and is forecasted in a range of $1.5 billion to $1.9 billion. The mid-point of the new 2015 capital forecast is a $350 million reduction from the previous forecast’s mid-point. Maintenance capital for 2015 is forecasted at approximately $30 million. 2016’s capital expenditure forecast has been decreased by $500 million to $1.5 billion.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Wednesday, February 25, 2015, at 12:00 p.m. Eastern Time to review its fourth 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 fourth 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 (866) 501-7042 (no passcode required).

MarkWest Energy Partners, L.P. is a master limited partnership that owns and operates midstream services related businesses. We have a leading presence in many natural gas resource plays including the Marcellus Shale, Utica Shale, Huron/Berea Shale, Haynesville Shale, Woodford Shale and Granite Wash formation where we provide midstream services for producer customers.

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, 2014. 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 December 31, Twelve months ended December 31,
Statement of Operations Data   2014     2013     2014     2013  
 
Revenue:
Product sales $ 219,893 $ 292,920 $ 1,198,642 $ 1,093,711
Service revenue 279,310 174,452 937,380 593,374
Derivative gain (loss)   39,042     (13,834 )   40,151     (24,638 )
Total revenue   538,245     453,538     2,176,173     1,662,447  
 
Operating expenses:
Purchased product costs 158,239 191,577 832,428 691,165
Derivative (gain) loss related to purchased product costs (48,994 ) 9,165 (58,392 ) (1,737 )
Facility expenses 92,533 91,220 343,362 291,069
Derivative loss related to facility expenses 372 69 3,277 2,869
Selling, general and administrative expenses 34,648 24,161 126,499 101,549
Depreciation 111,676 83,982 422,755 299,884
Amortization of intangible assets 16,637 16,719 64,893 64,644
Loss (gain) on disposal of property, plant and equipment 525 1,995 1,116 (33,763 )
Accretion of asset retirement obligations 66 155 570 824
Impairment of goodwill   62,445     -     62,445     -  
Total operating expenses   428,147     419,043     1,798,953     1,416,504  
 
Income from operations 110,098 34,495 377,220 245,943
 
Other (expense) income:
(Loss) earnings from unconsolidated affiliates (2,451 ) (139 ) (4,477 ) 1,422
Interest expense (42,549 ) (37,671 ) (166,372 ) (151,851 )
Amortization of deferred financing costs and debt discount (a component of interest expense) (1,547 ) (1,528 ) (7,289 ) (6,726 )
Loss on redemption of debt - - - (38,455 )
Miscellaneous income, net   3,323     1,033     3,440     2,781  
Income (loss) before provision for income tax 66,874 (3,810 ) 202,522 53,114
 
Provision for income tax expense (benefit):
Current 253 (705 ) 618 (11,208 )
Deferred   21,330     790     41,601     23,877  
Total provision for income tax   21,583     85     42,219     12,669  
 
Net income (loss) 45,291 (3,895 ) 160,303 40,445
 
Net (income) loss attributable to non-controlling interest   (10,313 )   (2,665 )   (26,422 )   (2,368 )
 
Net income (loss) attributable to the Partnership's unitholders $ 34,978   $ (6,560 ) $ 133,881   $ 38,077  
 
Net income (loss) attributable to the Partnership's common unitholders per common unit:
Basic $ 0.19   $ (0.05 ) $ 0.77   $ 0.26  
Diluted $ 0.18   $ (0.05 ) $ 0.72   $ 0.24  
 
Weighted average number of outstanding common units:
Basic   183,522     151,153     171,009     138,409  
Diluted   196,167     151,153     185,650     160,443  
 
Cash Flow Data
Net cash flow provided by (used in):
Operating activities $ 172,319 $ 104,991 $ 668,399 $ 435,650
Investing activities $ (655,051 ) $ (876,255 ) $ (2,270,096 ) $ (3,062,562 )
Financing activities $ 493,583 $ 528,416 $ 1,625,279 $ 2,366,461
 
Other Financial Data
Distributable cash flow $ 200,978 $ 127,242 $ 706,380 $ 483,355
Adjusted EBITDA $ 242,970 $ 155,512 $ 874,286 $ 605,989
 
 
Balance Sheet Data December 31, 2014 December 31, 2013
Total assets $ 10,980,778 $ 9,396,423
Total debt $ 3,621,404 $ 3,023,071
Total equity $ 6,193,239 $ 4,798,133
 
 
MarkWest Energy Partners, L.P.
Operating Statistics
             
Three months ended December 31, Twelve months ended December 31,
2014 2013 2014 2013
Marcellus
Gathering systems throughput (Mcf/d) (1) 769,000 580,700 668,600 549,500
Natural gas processed (Mcf/d) 2,556,400 1,401,700 2,063,900 1,101,900
 
C2 (purity ethane) produced (Bbl/d) (2) 62,500 200 54,400 100
C3+ NGLs fractionated (Bbl/d) (3) 116,500 56,700 93,000 47,600
Total NGLs fractionated (Bbl/d) 179,000 56,900 147,400 47,700
 
Utica (4)
Gathering systems throughput (Mcf/d) 460,000 107,800 288,800 62,400
Natural gas processed (Mcf/d) 652,200 166,200 415,500 88,400
C3+ NGLs fractionated (Bbl/d) (3) 24,900 - 18,500 -
 
Northeast
Natural gas processed (Mcf/d) 284,900 287,500 279,800 296,100
NGLs fractionated (Bbl/d) (5) 22,600 23,900 19,500 20,200
 
Keep-whole NGL sales (gallons, in thousands) 24,800 24,900 112,200 117,500
Percent-of-proceeds NGL sales (gallons, in thousands) 31,500 32,600 119,700 134,300

Total NGL sales (gallons, in thousands) (6)

56,300 57,500 231,900 251,800
 
Crude oil transported for a fee (Bbl/d) 9,000 9,500 9,700 9,700
 
Southwest
East Texas gathering systems throughput (Mcf/d) 554,000 501,100 548,100 504,000
East Texas natural gas processed (Mcf/d) (7) 431,300 357,700 419,100 355,100
East Texas NGL sales (gallons, in thousands) (8) 108,400 84,400 431,400 320,000
 
Western Oklahoma gathering systems throughput (Mcf/d) (9) 350,600 268,800 338,800 238,600
Western Oklahoma natural gas processed (Mcf/d) (10) 299,700 215,000 284,600 202,600
Western Oklahoma NGL sales (gallons, in thousands) (8) 53,500 77,000 219,300 239,200
 
Southeast Oklahoma gathering systems throughput (Mcf/d) 397,800 405,100 397,600 443,700
Southeast Oklahoma natural gas processed (Mcf/d) (11) 182,900 146,700 173,500 153,800
Southeast Oklahoma NGL sales (gallons, in thousands) 29,700 22,300 108,400 159,600
 
Other Southwest gathering systems throughput (Mcf/d) (12) 45,900 46,500 48,300 35,000
 
Gulf Coast refinery off-gas processed (Mcf/d) 116,400 83,400 114,100 103,400
Gulf Coast liquids fractionated (Bbl/d) (13) 21,100 14,600 20,800 18,800
Gulf Coast NGL sales (gallons, in thousands) (13) 81,500 56,300 318,500 288,800
 
 
(1) The 2013 volumes exclude Sherwood gathering as this system was sold to Summit in June 2013.
(2) The Keystone ethane fractionation facility began operations in June 2014. The volumes reported for 2014 are the average daily rate for the days of operation.
(3) Hopedale is jointly owned by MarkWest Liberty Midstream and MarkWest Utica EMG. Each segment includes its respective portion of the capacity utilized of the jointly owned Hopedale Fractionation Facility. Operations began in January 2014 and December 2014. The volumes reported for 2014 are the average daily rate for the days of operation.
(4) Utica operations began in August 2012.
(5) Includes NGLs fractionated for Utica and Marcellus segments.
(6) Represents sales at the Siloam fractionator. The total sales exclude approximately 28,127,000 gallons and 31,847,000 gallons sold by the Northeast on behalf of Marcellus and Utica for the three months ended December 31, 2014 and 2013, respectively. The total sales exclude approximately 68,392,000 gallons and 59,713,000 gallons sold by the Northeast on behalf of Marcellus and Utica for the year ended December 31, 2014 and 2013, respectively.
(7) Includes certain amounts in 2014 in excess of East Texas’ operating capacity that were processed by third-parties.
(8) Excludes gallons processed in conjunction with take in kind contracts for the three and twelve months ended December 31, 2014 and December 31, 2013, respectively, as shown below.
 
Three months ended December 31, Twelve months ended December 31,

Gallons processed in conjunction with
take in kind contracts

2014   2013 2014   2013
East Texas - 680,000 318,000 14,423,000
Western Oklahoma 34,309,000 - 122,310,000 -
 
(9) 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.
(10) The Buffalo Creek plant began operations in February 2014.
(11) The natural gas processing in Southeast Oklahoma is outsourced to Centrahoma or other third party processors.
(12) Excludes lateral pipelines where revenue is not based on throughput.
(13) 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 December 31, 2014 Marcellus Utica Northeast Southwest Eliminations (1) Total
Segment revenue $ 202,371 $ 50,863 $ 37,327 $ 227,890 $ (2,406 ) $ 516,045
 
Operating expenses:
Segment purchased product costs 15,931 1,262 12,371 128,788 - 158,352
Segment facility expenses   46,499     16,048     6,836   33,217     (2,406 )   100,194
Total operating expenses before items not allocated to segments 62,430 17,310 19,207 162,005 (2,406 ) 258,546
 
Segment portion of operating income attributable to non-controlling interests   -     16,983     -   1     -     16,984
Operating income before items not allocated to segments $ 139,941   $ 16,570   $ 18,120 $ 65,884   $ -   $ 240,515
 
 
Three months ended December 31, 2013 Marcellus Utica Northeast Southwest Total
Segment revenue $ 151,229 $ 13,852 $ 52,796 $ 251,333 $ 469,210
 
Operating expenses:
Segment purchased product costs 27,481 - 15,074 149,022 191,577
Segment facility expenses   34,252     14,849     7,887   36,085     93,073  
Total operating expenses before items not allocated to segments 61,733 14,849 22,961 185,107 284,650
 
Segment portion of operating loss attributable to non-controlling interests   -     (418 )   -   (136 )   (554 )
Operating income (loss) before items not allocated to segments $ 89,496   $ (579 ) $ 29,835 $ 66,362   $ 185,114  
 
(1) Amounts represent revenues and expenses associated with the Northeast segment fractionation completed on behalf of the Marcellus segment.
 

Three months ended December 31,

  2014     2013  
 
Operating income before items not allocated to segments 240,515 185,114
Portion of operating income (loss) attributable to non-controlling interests 8,041 (554 )
Derivative gain (loss) not allocated to segments 87,664 (23,068 )
Revenue adjustment for unconsolidated affiliate (22,150 ) -
Revenue deferral adjustment and other 103 (1,838 )
Compensation expense included in facility expenses not allocated to segments (1,225 ) (834 )
Facility expense and purchase product cost adjustments for unconsolidated affiliate 11,517 -
Portion of operating loss attributable to non-controlling interests of an unconsolidated affiliate 8,943 -
Facility expenses adjustments 2,687 2,687
Selling, general and administrative expenses (34,648 ) (24,161 )
Depreciation (111,676 ) (83,982 )
Amortization of intangible assets (16,637 ) (16,719 )
Loss on disposal of property, plant and equipment (525 ) (1,995 )
Accretion of asset retirement obligations (66 ) (155 )
Impairment of goodwill   (62,445 ) -  
Income from operations 110,098 34,495
Other (expense) income:
Loss from unconsolidated affiliates (2,451 ) (139 )
Interest expense (42,549 ) (37,671 )
Amortization of deferred financing costs and debt discount (a component of interest expense) (1,547 ) (1,528 )
Miscellaneous income, net   3,323     1,033  

Income (loss) before provision for income tax

$ 66,874   $ (3,810 )
 
 
 
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)
 
Twelve months ended December 31, 2014 Marcellus Utica Northeast Southwest Eliminations (1) Total
Segment revenue $ 791,505 $ 152,975 $ 194,477 $ 1,035,026 $ (6,175 ) $ 2,167,808
 
Operating expenses:
Segment purchased product costs 147,500 23,773 66,345 595,064 - 832,682
Segment facility expenses   151,898     54,224     31,974   132,360     (6,175 )   364,281
Total operating expenses before items not allocated to segments 299,398 77,997 98,319 727,424 (6,175 ) 1,196,963
 
Segment portion of operating income attributable to non-controlling interests   -     35,422     -   11     -     35,433
Operating income before items not allocated to segments $ 492,107   $ 39,556   $ 96,158 $ 307,591   $ -   $ 935,412
 
 
Twelve months ended December 31, 2013 Marcellus Utica Northeast Southwest Total
Segment revenue $ 527,073 $ 26,442 $ 204,326 $ 935,426 $ 1,693,267
 
Operating expenses:
Segment purchased product costs 100,262 - 65,192 525,711 691,165
Segment facility expenses   108,781     35,081     28,425   127,112     299,399  
Total operating expenses before items not allocated to segments 209,043 35,081 93,617 652,823 990,564
 
Segment portion of operating (loss) income attributable to non-controlling interests   -     (3,499 )   -   21     (3,478 )
Operating income (loss) before items not allocated to segments $ 318,030   $ (5,140 ) $ 110,709 $ 282,582   $ 706,181  
 
(1) Amounts represent revenues and expenses associated with the Northeast segment fractionation completed on behalf of the Marcellus segment.
 

Twelve months ended December 31,

  2014     2013  
 
Operating income before items not allocated to segments $ 935,412 $ 706,181
Portion of operating income (loss) attributable to non-controlling interests 21,425 (3,478 )
Derivative gain (loss) not allocated to segments 95,266 (25,770 )
Revenue adjustment for unconsolidated affiliate (41,446 ) -
Revenue deferral adjustment and other 4,455 (6,182 )
Compensation expense included in facility expenses not allocated to segments (3,932 ) (2,421 )
Facility expense and purchase product cost adjustments for unconsolidated affiliate 19,559 -
Portion of operating loss attributable to non-controlling interests of an unconsolidated affiliate 14,008 -
Facility expenses adjustments 10,751 10,751
Selling, general and administrative expenses (126,499 ) (101,549 )
Depreciation (422,755 ) (299,884 )
Amortization of intangible assets (64,893 ) (64,644 )
(Loss) gain on disposal of property, plant and equipment (1,116 ) 33,763
Accretion of asset retirement obligations (570 ) (824 )
Impairment of goodwill   (62,445 )   -  

Income from operations

377,220 245,943
Other (expense) income:
(Loss) earnings from unconsolidated affiliates (4,477 ) 1,422
Interest expense (166,372 ) (151,851 )
Amortization of deferred financing costs and debt discount (a component of interest expense) (7,289 ) (6,726 )
Loss on redemption of debt - (38,455 )
Miscellaneous income, net   3,440     2,781  
Income before provision for income tax $ 202,522   $ 53,114  
 
           
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Distributable Cash Flow
(unaudited, in thousands)
 
Three months ended December 31, Twelve months ended December 31,
  2014     2013     2014     2013  
 
Net income (loss) $ 45,291 $ (3,895 ) $ 160,303 $ 40,445
Depreciation, amortization and other non-cash operating expenses 128,457 100,934 489,399 365,664
Loss (gain) on sale or disposal of property, plant and equipment 525 2,051 1,116 (30,660 )
Loss on redemption of debt, net of tax benefit - - - 36,178
Amortization of deferred financing costs and debt discount 1,547 1,528 7,289 6,726
Loss (earnings) from unconsolidated affiliates 2,451 139 4,477 (1,422 )
Distributions from unconsolidated affiliates 5,273 1,418 12,459 6,370
Non-cash compensation expense 2,836 2,358 10,284 7,822
Unrealized (gain) loss on derivative instruments (63,905 ) 14,380 (82,067 ) 15,602
Deferred income tax expense (benefit) 21,330 790 41,601 23,877
Cash adjustment for non-controlling interest of consolidated subsidiaries (7,243 ) 1,449 (17,869 ) 6,121
Revenue deferral adjustment 1,450 2,049 6,983 7,213
Impairment expense 62,445 - 62,445 -
Other (1) 4,577 9,851 29,080 18,404
Maintenance capital expenditures (2)   (4,056 )   (5,810 )   (19,120 )   (18,985 )
Distributable cash flow $ 200,978   $ 127,242   $ 706,380   $ 483,355  
 
Maintenance capital expenditures (2) $ 4,056 $ 5,810 $ 19,120 $ 18,985
Growth capital expenditures of consolidated subsidiaries 593,759 864,427 2,350,595 3,027,971
Growth capital expenditures of unconsolidated subsidiary (3)   120,934       -     309,112     -  
Total capital expenditures 718,749 870,237 2,678,827 3,046,956
Acquisitions, net of cash acquired   -     (2,322 )   -     222,888  
Total capital expenditures and acquisitions 718,749 867,915 2,678,827 3,269,844
Joint venture partner contributions   (81,328 )   -     (474,437 )   (716,982 )
Total capital expenditures and acquisitions, net $ 637,421   $ 867,915   $ 2,204,390   $ 2,552,862  
 
Distributable cash flow $ 200,978 $ 127,242 $ 706,380 $ 483,355
Maintenance capital expenditures (2) 4,056 5,810 19,120 18,985
Changes in receivables, inventories and other assets 37,212 (59,131 ) (27,801 ) (133,601 )
Changes in accounts payable, accrued liabilities and other long-term liabilities (73,279 ) 42,458 (19,783 ) 91,015
Cash adjustment for non-controlling interest of consolidated subsidiaries 7,243 (1,449 ) 17,869 (6,121 )
Other   (3,891 )   (9,939 )   (27,386 )   (17,983 )
Net cash provided by operating activities $ 172,319   $ 104,991   $ 668,399   $ 435,650  
 
(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 December 31, Twelve months ended December 31,
2014 2013 2014 2013
 
Net income (loss) 45,291 (3,895) 160,303 40,445
Non-cash compensation expense 2,836 2,358 10,284 7,822
Unrealized (gain) loss on derivative instruments (63,905) 14,380 (82,067) 15,602
Interest expense (1) 42,050 37,096 165,389 150,084
Depreciation, amortization and other non-cash operating expenses 128,457 100,934 489,399 365,664
Loss (gain) on disposal of property, plant and equipment 525 1,995 1,116 (33,763)
Loss on redemption of debt - - - 38,455
Provision for income tax expense 21,583 85 42,219 12,669
Adjustment for cash flow from unconsolidated affiliates 7,724 1,557 16,936 4,948
Impairment expense 62,445 - 62,445 -
Other (2) (4,036) 1,002 8,262 4,063
Adjusted EBITDA $ 242,970 $ 155,512 $ 874,286 $ 605,989
 
(1) Includes amortization of deferred financing costs and debt discount, and excludes interest expense related to the Steam Methane Reformer.
(2) For the three months and year ended December 31, 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 2015, the Partnership estimates that net operating margin will be approximately 89 percent fee-based.

The analysis further assumes derivative instruments outstanding as of February 20, 2015, and production volumes estimated through December 31, 2015.

       

Estimated Range of 2015 DCF

 
Volume Forecast (1)
            Low Case     Base Case     High Case
NGL
$/Gallon
(2)(3)
$0.70     $ 751     $ 780     $ 800
$0.65     $ 740     $ 769     $ 789
$0.60     $ 729     $ 758     $ 778
$0.55     $ 719     $ 747     $ 766
$0.50     $ 708     $ 736     $ 755
    $0.45     $ 696     $ 724     $ 743
       
(1)   Volume Forecast is increased/decreased by 5% in the Marcellus and Utica segments for the High and Low Cases.
(2) The composition is based on the Partnership’s projected NGL 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, 866-858-0482
Chairman, President & CEO
or
Nancy Buese, 866-858-0482
Executive VP and CFO
or
Josh Hallenbeck, 866-858-0482
VP of Finance & Treasurer
investorrelations@markwest.com

Release Summary

MarkWest Energy Partners Q4 earnings release.

Contacts

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