MarkWest Energy Partners Reports Fourth Quarter And Full Year Financial Results

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 $127.2 million for the three months ended December 31, 2013, and $483.4 million for the year ended December 31, 2013. DCF for the three months and year ended December 31, 2013 represents distribution coverage of 94 percent and 99 percent, respectively. The fourth quarter distribution of $135.9 million, or $0.86 per common unit, was paid to unitholders on February 14, 2014. The fourth quarter 2013 distribution represents an increase of $0.01 per common unit or 1.2 percent over the third quarter 2013 distribution and an increase of $0.04 per common unit or 4.9 percent compared to the fourth quarter 2012 distribution. As a Master Limited Partnership, cash distributions to common unitholders are largely determined based on DCF. A reconciliation of DCF to net income, the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.

The Partnership reported Adjusted EBITDA of $155.5 million for the three months ended December 31, 2013 and $606.0 million for the year ended December 31, 2013, as compared to $138.0 million and $528.5 million for the three months and year ended December 31, 2012. The Partnership believes the presentation of Adjusted EBITDA provides useful information because it is commonly used by investors in Master Limited Partnerships to assess financial performance and operating results of ongoing business operations. A reconciliation of Adjusted EBITDA to net income, the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.

The Partnership reported (loss) income before provision for income tax for the three months and year ended December 31, 2013, of $(3.8) million and $53.1 million, respectively. (Loss) income before provision for income tax includes non-cash loss associated with the change in fair value of derivative instruments of $14.4 million and $15.6 million for the respective three months and year ended December 31, 2013, a gain of $0.8 million and $39.7 million related to the divestiture of gathering assets in the Marcellus Shale for the respective three months and year ended December 31, 2013, and a loss associated with the redemption of debt of $38.5 million for the year ended December 31, 2013. Excluding these items, income before provision for income tax for the three months and year ended December 31, 2013 would have been $9.8 million and $67.5 million, respectively.

“We are very pleased to close 2013 with the completion of major infrastructure projects that are critical to the development of the Marcellus and Utica Shales,” stated Frank Semple, Chairman, President and Chief Executive Officer. “Our producers’ ongoing success and expanding development plans continue to provide us with exceptional future growth opportunities. We are committed to delivering another year of strong financial results, operational excellence and best of class customer service in many of America’s most exciting resource plays.”

BUSINESS HIGHLIGHTS

Marcellus:
  • In November 2013, the Partnership announced an expansion of the Sherwood complex in Doddridge County, West Virginia to support Antero Resources Corporation’s (NYSE: AR) highly prospective rich-gas Marcellus Shale acreage. The Partnership will construct Sherwood V, a new 200 million cubic feet per day (MMcf/d) processing facility that is scheduled to begin operations in the third quarter of 2014.
  • In November 2013, the Partnership completed Majorsville V, a 200 MMcf/d processing plant at the Majorsville complex in Marshall County, West Virginia. Majorsville V supports growing rich-gas production from Chesapeake Energy Corporation (NYSE: CHK), and Statoil ASA (NYSE: STO) and increases the total processing capacity of the complex to 670 MMcf/d.
  • In November 2013, the Partnership completed Sherwood III, a 200 MMcf/d processing plant at the Sherwood complex. Sherwood III supports Antero Resources Corporation and increases the total processing capacity of the complex to 600 MMcf/d.
  • In December 2013, the Partnership completed Mobley III, a 200 MMcf/d processing plant at the Mobley complex in Wetzel County, West Virginia. Mobley III supports rapidly growing rich-gas production from EQT Corporation (NYSE: EQT) and Magnum Hunter Resources Corporation (NYSE: MHR) and increases the total processing capacity of the complex to 520 MMcf/d.
  • In December 2013, the Partnership completed the 38,000 barrels per day (Bbl/d) de-ethanization unit at the Majorsville complex. The new de-ethanizer doubles the Partnership’s total purity ethane production capacity in the Marcellus Shale to 76,000 Bbl/d and provides producers with the ability to consistently meet residue gas quality specifications and deliver downstream ethane pipeline commitments.
  • In December 2013, the Partnership completed the Liberty Ethane Pipeline. The Liberty Ethane Pipeline transports purity ethane produced at the Majorsville complex to the Houston complex in Washington County, Pennsylvania. Once delivered to the Houston complex, the purity ethane has direct access to multiple, major ethane takeaway projects including, Mariner West and ATEX, which began operations in December, and Mariner East, which is scheduled to come online for ethane service in 2015.
  • In February 2014, the Partnership announced the development of a 40,000 Bbl/d de-ethanization facility at the Mobley complex. The Mobley de-ethanizer will support purity ethane production for EQT Corporation, Magnum Hunter Resources Corporation and other producers. The new facility is scheduled to begin operations during the third quarter of 2015.

Utica:
  • In November 2013, MarkWest Utica EMG commenced operations at the Seneca complex in Noble County, Ohio. The Seneca complex currently consists of two cryogenic processing plants totaling 400 MMcf/d of capacity and is supported by long-term fee-based agreements with Antero Resources Corporation, Gulfport Energy Corporation (NASDAQ: GPOR), Rex Energy Corporation (NASDAQ: REXX), PDC Energy (NASDAQ: PDCE) and others.
  • In December 2013, the Partnership and The Energy & Minerals Group (EMG) executed definitive agreements with Gulfport Energy Corporation to provide condensate stabilization and logistics services in eastern Ohio. As part of these agreements, the Partnership and EMG formed Ohio Condensate Company, LLC, a new Joint Venture (JV) related to the development of industry-leading facilities and services to support the rapid growth of condensate production occurring in the Utica Shale. The JV will initially develop a 23,000 Bbl/d condensate stabilization facility in Harrison County, Ohio. The new facility is scheduled to commence operations in the third quarter of 2014 and will be co-located with condensate storage and logistics terminal, which will be constructed and operated by a subsidiary of Toledo International, Inc., Ohio-based Midwest Terminals.
  • In January 2014, MarkWest Utica EMG and the Partnership completed construction and commenced operations of the jointly-owned Hopedale fractionation and marketing complex (Hopedale complex) in Harrison County, Ohio. The Hopedale complex consists of a 60,000 Bbl/d propane and heavier purity products (C3+) fractionator, over 230,000 barrels of purity product storage, a 24-bay rail car loading facility with slots to accommodate 200 rail cars, and truck loading and off loading facilities. The Hopedale complex is connected by NGL pipeline to MarkWest Utica EMG’s Cadiz processing complex in Harrison County, Ohio, to the Seneca processing complex in Noble County, Ohio and to its extensive NGL gathering network in the Marcellus Shale.
  • In January 2014, the Partnership commenced operations of a NGL pipeline connecting the Hopedale fractionation and marketing complex to the Partnership’s industry-leading NGL infrastructure in the Marcellus Shale. By integrating two industry-leading midstream systems, the Partnership has expanded the fractionation capacity for its Marcellus producers.
  • Today, MarkWest Utica EMG is announcing the expansion of the Seneca complex with a new 200 MMcf/d processing plant. The plant is anchored by a new agreement with Antero Resources Corporation supporting its expanding Utica development plans. The Seneca IV plant is scheduled to commence operations in the first quarter of 2015 and will expand total processing capacity of the complex to 800 MMcf/d.

Southwest:
  • In February 2014, the Partnership announced the commencement of the 200 MMcf/d Buffalo Creek processing facility in Beckham County, Oklahoma, and associated gas gathering and compression assets in the Granite Wash. The new facility is supported by long-term fee-based agreements with Chesapeake Energy Corporation, which include a 130,000 acre dedication throughout the area. The completion of the Buffalo Creek plant increases the Partnership’s total processing capacity in the Anadarko Basin to 435 MMcf/d at two major complexes.

Capital Markets
  • During the fourth quarter of 2013, the Partnership offered 10.0 million units and received net proceeds of approximately $658.2 million under the $1 billion continuous offering program launched in the third quarter of 2013.

FINANCIAL RESULTS

Balance Sheet

  • As of December 31, 2013, the Partnership had $80.0 million of cash and cash equivalents in wholly owned subsidiaries and $1.19 billion of remaining capacity under its $1.2 billion revolving credit facility after consideration of $11.3 million of outstanding letters of credit.

Operating Results
  • Operating income before items not allocated to segments for the three months ended December 31, 2013, was $185.1 million, an increase of $23.1 million when compared to segment operating income of $162.0 million over the same period in 2012. This increase was primarily attributable to higher processing volumes. Processed volumes continued to increase in the fourth quarter of 2013, growing approximately 51 percent when compared to the fourth quarter of 2012, primarily due to the Partnership’s Marcellus and Southwest segments. While the Partnership continued to increase its operating income and volumes, it experienced several operational constraints during the second half of 2013. Due to these considerations, operating income was approximately $12.0 million lower than expected for the three months ended December 31, 2013, and approximately $24.1 million for the year ended December 31, 2013. The operational constraints included increased costs related to the transportation of producer natural gas liquids in excess of our fractionation capacity to third party fractionation facilities, delays related to the completion of Sunoco Logistics Partners, L.P.’s (NYSE: SXL) Mariner West purity ethane pipeline and an NGL line break that took the Partnership’s Mobley complex offline and curtailed processing volumes at the Partnership’s Sherwood complex for approximately two months. As of January 2014, all operational constraints have been resolved.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 losses on commodity derivative instruments were $8.7 million in the fourth quarter of 2013 and $2.1 million in the fourth quarter of 2012.

Capital Expenditures
  • For the three months ended December 31, 2013, the Partnership’s portion of capital expenditures was $870.2 million.

2014 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

For 2014, the Partnership forecasts DCF in a range of $600 million to $690 million based on its current forecast of operational volumes and prices for crude oil, natural gas, natural gas liquids and derivative instruments currently outstanding. The Partnership has become less sensitive to changes in commodity prices as a result of fee-based margin increasing significantly. 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, 90 percent of these with direct product hedges. 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 $1.8 billion to $2.3 billion. Maintenance capital is forecasted at approximately $25 million.

CONFERENCE CALL

The Partnership will host a conference call on Thursday, February 27, 2014, at 12:00 p.m. Eastern Time to review its fourth quarter and full year 2013 financial results. Interested parties can participate in the call by dialing (800) 475-0218 (passcode “MarkWest”) approximately ten minutes prior to the scheduled start time. Prior to the conference call, the Partnership will post a fourth quarter earnings call presentation to its website. To access the conference call and 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) 448-4799 (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 December 31,   Twelve months ended December 31,
Statement of Operations Data 2013   2012 2013   2012
Revenue:
Revenue $ 467,372 $ 363,570 $ 1,687,085 $ 1,383,279
Derivative (loss) gain   (13,834 )   5,583     (24,638 )   56,535  
Total revenue   453,538     369,153     1,662,447     1,439,814  
 
Operating expenses:
Purchased product costs 191,577 143,673 691,165 530,328
Derivative loss (gain) related to purchased product costs 9,165 7,174 (1,737 ) (13,962 )
Facility expenses 91,220 57,422 291,069 206,861
Derivative loss related to facility expenses 69 235 2,869 1,371
Selling, general and administrative expenses 24,161 24,973 101,549 93,444
Depreciation 83,982 55,778 299,884 183,250
Amortization of intangible assets 16,719 15,040 64,644 53,320
Loss (gain) on sale or disposal of property, plant and equipment 1,995 3,271 (33,763 ) 6,254
Accretion of asset retirement obligations   155     137     824     672  
Total operating expenses   419,043     307,703     1,416,504     1,061,538  
 
Income from operations 34,495 61,450 245,943 378,276
 
Other (expense) income:
(Loss) earnings from unconsolidated affiliates (139 ) 74 1,422 2,328
Interest income 24 124 262 419
Interest expense (37,671 ) (33,336 ) (151,851 ) (120,191 )
Amortization of deferred financing costs and discount (a component of interest expense) (1,528 ) (1,658 ) (6,726 ) (5,601 )
Loss on redemption of debt - - (38,455 ) -
Miscellaneous income (expense), net   1,009     (1 )   2,519     62  
(Loss) income before provision for income tax (3,810 ) 26,653 53,114 255,293
 
Provision for income tax (benefit) expense:
Current (705 ) (4,568 ) (11,208 ) (2,366 )
Deferred   790     1,298     23,877     40,694  
Total provision for income tax   85     (3,270 )   12,669     38,328  
 
Net (loss) income (3,895 ) 29,923 40,445 216,965
 
Net (loss) income attributable to non-controlling interest (2,665 ) 1,891 (2,368 ) 3,437
       
Net (loss) income attributable to the Partnership's unitholders $ (6,560 ) $ 31,814   $ 38,077   $ 220,402  
 
Net (loss) income attributable to the Partnership's common unitholders per common unit:
Basic $ (0.05 ) $ 0.26   $ 0.26   $ 1.98  
Diluted $ (0.05 ) $ 0.22   $ 0.24   $ 1.69  
 
Weighted average number of outstanding common units:
Basic   151,153     122,079     138,409     109,979  
Diluted   151,153     142,720     160,443     130,648  
 
Cash Flow Data
Net cash flow provided by (used in):
Operating activities $ 104,991 $ 106,229 $ 435,650 $ 492,013
Investing activities $ (876,255 ) $ (726,339 ) $ (3,062,562 ) $ (2,472,088 )
Financing activities $ 528,416 $ 553,513 $ 2,366,461 $ 2,211,499
 
Other Financial Data
Distributable cash flow $ 127,242 $ 111,774 $ 483,355 $ 417,086
Adjusted EBITDA $ 155,320 $ 137,952 $ 605,797 $ 528,467
 
 
Balance Sheet Data December 31, 2013 December 31, 2012
Working capital $ (353,273 ) $ (84,512 )
Total assets $ 9,396,423 $ 6,728,362
Total debt $ 3,023,071 $ 2,523,051
Total equity $ 4,798,133 $ 3,111,398
 
 
MarkWest Energy Partners, L.P.
Operating Statistics
 
    Three months ended December 31,   Twelve months ended December 31,
2013   2012 2013   2012
Marcellus
Gathering system throughput (Mcf/d) (1) 580,700 587,600 549,500 425,000
Natural gas processed (Mcf/d) 1,401,700 696,000 1,101,900 496,400
NGLs fractionated (Bbl/d) (2) 56,700 31,100 47,600 24,900
NGL sales (gallons, in thousands) (3) 284,300 129,400 820,400 393,600
 
Utica (4)
Gathering system throughput (Mcf/d) 107,800 6,400 62,400 5,000
Natural gas processed (Mcf/d) 166,200 5,000 88,400 4,200
 
Northeast (5)
Natural gas processed (Mcf/d) 287,500 313,700 296,100 320,500
NGLs fractionated (Bbl/d) (6) 23,900 18,900 20,200 17,300
 
Keep-whole sales (gallons, in thousands) 24,900 35,100 117,500 131,600
Percent-of-proceeds sales (gallons, in thousands) 32,600 36,200 134,300 139,700
Total NGL sales (gallons, in thousands) (7) 57,500 71,300 251,800 271,300
 
Crude oil transported for a fee (Bbl/d) 9,500 9,900 9,700 9,300
 
Southwest
East Texas gathering systems throughput (Mcf/d) 501,100 477,600 504,000 450,000
East Texas natural gas processed (Mcf/d) 357,700 302,000 355,100 270,800
East Texas NGL sales (gallons, in thousands) (8) 85,100 76,500 334,400 275,800
 
Western Oklahoma gathering system throughput (Mcf/d) (9) 268,800 200,800 238,600 235,600
Western Oklahoma natural gas processed (Mcf/d) 215,000 193,800 202,600 206,500
Western Oklahoma NGL sales (gallons, in thousands) 77,000 44,500 239,200 214,400
 
Southeast Oklahoma gathering system throughput (Mcf/d) 405,100 463,100 443,700 487,900
Southeast Oklahoma natural gas processed (Mcf/d) (10) 146,700 137,000 153,800 121,800
Southeast Oklahoma NGL sales (gallons, in thousands) 22,300 42,400 159,600 163,300
 
Other Southwest gathering system throughput (Mcf/d) (11) 46,500 22,300 35,000 24,300
 
Gulf Coast refinery off-gas processed (Mcf/d) 83,400 113,600 103,400 118,400
Gulf Coast liquids fractionated (Bbl/d) 14,600 21,000 18,800 22,500
Gulf Coast NGL sales (gallons excluding hydrogen, in thousands) 56,300 81,000 288,800 345,300
 
(1) The 2013 volumes exclude Sherwood gathering as this system was sold to Summit Midstream in June 2013.
(2) Amount includes all NGLs that were produced at the Marcellus processing facilities and fractionated into purity products at our Marcellus fractionation facility. Excludes 7,300 and 0 barrels per day of ethane fractionated for the three months ended December 31, 2013 and 2012, respectively, and 300 and 0 barrels per day of ethane fractionated for the twelve months ended December 31, 2013 and 2012, respectively.
(3) Includes sale of all purity products fractionated at the Marcellus facilities and sale of all unfractionated NGLs. Also includes the sale of purity products fractionated and sold at the Siloam facilities on behalf of Marcellus customers.
(4) Utica operations began in August 2012. The volumes reported for 2012 are the average daily rate for the days of operation.
(5) Includes throughput from the Kenova, Cobb, Boldman and Langley processing plants.
(6) Amount includes 8,200 and 1,400 barrels per day fractionated for the three months ended December 31, 2013 and 2012, respectively, and 5,200 and 400 barrels per day fractionated on behalf of Marcellus for the twelve months ended December 31, 2013 and 2012, respectively.
(7) Represents sales at the Siloam fractionator. The total sales exclude approximately 31,800,000 and 5,500,000 gallons sold by the Northeast on behalf of Marcellus for the three months ended December 31, 2013 and 2012, respectively, and approximately 59,700,000 and 6,500,000 gallons sold for the twelve months ended December 31, 2013 and 2012, respectively. These volumes are included as part of NGLs sold at Marcellus.
(8) Includes approximately 14,420,000 gallons produced in conjunction with take in kind contracts for the year ended December 31, 2013.
(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 natural gas processing in Southeast Oklahoma is outsourced to Centrahoma or other third party processors.
(11) Excludes lateral pipelines where revenue is not based on throughput.
 
 

MarkWest Energy Partners, L.P.

Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Operating Income before Items not Allocated to Segments
(unaudited, in thousands)
                   
Three months ended December 31, 2013 Marcellus Utica Northeast Southwest Total
Segment revenue $ 151,229 $ 13,852 $ 52,796 $ 251,333 $ 469,210
 
Operating expenses:
Purchased product costs 27,481 - 15,074 149,022 191,577
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
 
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  
 
 
Three months ended December 31, 2012 Marcellus Utica Northeast Southwest Total
Segment revenue $ 106,106 $ 426 $ 56,862 $ 201,637 $ 365,031
 
Operating expenses:
Purchased product costs 25,168 - 18,740 99,765 143,673
Facility expenses   21,281     2,377     6,529   29,727     59,914  
Total operating expenses before items not allocated to segments 46,449 2,377 25,269 129,492 203,587
 
Portion of operating (loss) income attributable to non-controlling interests   -     (619 )   -   78     (541 )
Operating income (loss) before items not allocated to segments $ 59,657   $ (1,332 ) $ 31,593 $ 72,067   $ 161,985  
 
 

Three months ended December 31,
2013 2012
 
Operating income before items not allocated to segments $ 185,114 $ 161,985
Portion of operating loss attributable to non-controlling interests (554 ) (541 )
Derivative loss not allocated to segments (23,068 ) (1,826 )
Revenue deferral adjustment and other (1,838 ) (1,461 )
Compensation expense included in facility expenses not allocated to segments (834 ) (196 )
Facility expenses adjustments 2,687 2,687
Selling, general and administrative expenses (24,161 ) (24,973 )
Depreciation (83,982 ) (55,778 )
Amortization of intangible assets (16,719 ) (15,040 )
Loss on disposal of property, plant and equipment (1,995 ) (3,271 )
Accretion of asset retirement obligations   (155 )   (136 )
Income from operations 34,495 61,450
Other (expense) income:
(Loss) earnings from unconsolidated affiliates (139 ) 74
Interest income 24 124
Interest expense (37,671 ) (33,336 )
Amortization of deferred financing costs and discount (a component of interest expense) (1,528 ) (1,658 )
Miscellaneous income (expense), net   1,009     (1 )
(Loss) income before provision for income tax $ (3,810 ) $ 26,653  
 
                   
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, 2013 Marcellus Utica Northeast Southwest Total
Segment revenue $ 527,073 $ 26,442 $ 204,326 $ 935,426 $ 1,693,267
 
Operating expenses:
Purchased product costs 100,262 - 65,192 525,711 691,165
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
 
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  
 
 
Twelve months ended December 31, 2012 Marcellus Utica Northeast Southwest Total
Segment revenue $ 319,867 $ 571 $ 225,818 $ 842,958 $ 1,389,214
 
Operating expenses:
Purchased product costs 74,024 - 68,402 387,902 530,328
Facility expenses   65,825     3,968     24,106   122,691   216,590  
Total operating expenses before items not allocated to segments 139,849 3,968 92,508 510,593 746,918
 
Portion of operating (loss) income attributable to non-controlling interests   -     (1,359 )   -   176   (1,183 )
Operating income (loss) before items not allocated to segments $ 180,018   $ (2,038 ) $ 133,310 $ 332,189 $ 643,479  
 
 

Twelve months ended December 31,
2013 2012
 
Operating income before items not allocated to segments $ 706,181 $ 643,479
Portion of operating loss attributable to non-controlling interests (3,478 ) (1,183 )
Derivative (loss) gain not allocated to segments (25,770 ) 69,126
Revenue deferral adjustment and other (6,182 ) (5,935 )
Compensation expense included in facility expenses not allocated to segments (2,421 ) (1,022 )
Facility expenses adjustments 10,751 10,751
Selling, general and administrative expenses (101,549 ) (93,444 )
Depreciation (299,884 ) (183,250 )
Amortization of intangible assets (64,644 ) (53,320 )
Gain (loss) on disposal of property, plant and equipment 33,763 (6,254 )
Accretion of asset retirement obligations   (824 )     (672 )
Income from operations 245,943 378,276
Other income (expense):
Earnings from unconsolidated affiliates 1,422 2,328
Interest income 262 419
Interest expense (151,851 ) (120,191 )
Amortization of deferred financing costs and discount (a component of interest expense) (6,726 ) (5,601 )
Loss on redemption of debt (38,455 ) -
Miscellaneous income, net   2,519     62  
Income before provision for income tax $ 53,114   $ 255,293  
 
 
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,
2013   2012 2013   2012

 

 

 

 
Net (loss) income $ (3,895 ) $ 29,923 $ 40,445 $ 216,965
Depreciation, amortization and other non-cash operating expenses 100,934 71,032 365,664 237,554
Loss (gain) on sale and or disposal of assets, net of tax 2,051 3,271 (30,660 ) 6,254
Loss on redemption of debt, net of tax benefit - - 36,178 -
Amortization of deferred financing costs and discount 1,528 1,658 6,726 5,601
Non-cash loss (earnings) from unconsolidated affiliates 139 (74 ) (1,422 ) (2,328 )
Distributions from unconsolidated affiliates 1,418 1,792 6,370 8,416
Non-cash compensation expense 2,358 1,977 7,822 8,247
Non-cash derivative activity 14,380 (312 ) 15,602 (102,127 )
Provision for income tax - deferred 790 1,298 23,877 40,694
Cash adjustment for non-controlling interest of consolidated subsidiaries 1,449 908 6,121 2,299
Revenue deferral adjustment 2,049 1,837 7,213 7,441
Other 9,666 (58 ) 17,419 3,372
Maintenance capital expenditures (1)   (5,625 )   (1,478 )   (18,000 )   (15,302 )
Distributable cash flow $ 127,242   $ 111,774   $ 483,355   $ 417,086  

 

 

 

 

 
Maintenance capital expenditures (1) $ 5,625 $ 1,478 $ 18,000 $ 15,302
Growth capital expenditures   864,612     709,141     3,028,956     1,935,022  
Total capital expenditures 870,237 710,619 3,046,956 1,950,324
Acquisitions, net of cash acquired (2)   (2,322 )   -     222,888     506,797  
Total capital expenditures and acquisitions 867,915 710,619 3,269,844 2,457,121
Joint venture partner contributions   -     (178,018 )   (716,982 )   (233,018 )
Total capital expenditures and acquisitions, net $ 867,915   $ 532,601   $ 2,552,862   $ 2,224,103  
 
Distributable cash flow $ 127,242 $ 111,774 $ 483,355 $ 417,086
Maintenance capital expenditures (1) 5,625 1,478 18,000 15,302
Changes in receivables and other assets (59,131 ) (1,655 ) (133,601 ) 24,641
Changes in accounts payable, accrued liabilities and other long-term liabilities 42,458 (3,740 ) 91,015 41,728
Cash adjustment for non-controlling interest of consolidated subsidiaries (1,449 ) (908 ) (6,121 ) (2,299 )
Other   (9,754 )   (720 )   (16,998 )   (4,445 )
Net cash provided by operating activities $ 104,991   $ 106,229   $ 435,650   $ 492,013  
 
 

(1)

Net of joint venture partner contributions and proceeds from trade-in of property plant and equipment.

(2)

On May 29, 2012, the Partnership acquired natural gas gathering and processing assets from Keystone, during the three months ended December 2013, we received $2.3 million related to a working capital adjustment.
 
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,
2013 2012 2013 2012
 
Net (loss) income $ (3,895 ) $ 29,923 $ 40,445 $ 216,965
Non-cash compensation expense 2,358 1,977 7,822 8,247
Non-cash derivative activity 14,380 (312 ) 15,602 (102,127 )
Interest expense (1) 37,096 32,838 150,084 117,098
Depreciation, amortization and other non-cash operating expenses 100,934 71,032 365,664 237,554
Loss (gain) on sale and or disposal of assets 1,995 3,271 (33,763 ) 6,254
Loss on redemption of debt - - 38,455 -
Provision for income tax 85 (3,270 ) 12,669 38,328
Adjustment for cash flow from unconsolidated affiliates 1,557 1,718 4,948 6,088
Other   1,002     775     4,063     60  
Adjusted EBITDA $ 155,512   $ 137,952   $ 605,989   $ 528,467  

(1)
 

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

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

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 because fee-based margin has increased significantly. 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, 90 percent of these with direct product hedges.

The analysis further assumes derivative instruments outstanding as of February 26, 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 (3)
            Low Case     Base Case     High Case

NGL $/Gal(1) (2)
$1.05 $ 610     $ 662     $ 720
$1.00 $ 601     $ 652     $ 709
$0.95 $ 591     $ 642     $ 698
$0.90 $ 583     $ 633     $ 690
    $0.85     $ 574     $ 624     $ 681
 
(1)   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%.
(2) Composite NGL prices is based on the Partnership’s average price.
(3) Volume Forecast is increased/decreased by 10% in the Marcellus and Utica segments for the High and Low Cases.
 

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. Nor does the table 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."

Copyright Business Wire 2010