Exhibit 99.1
MarkWest Energy Partners, L.P. | | Contact: | | Frank Semple, Chairman, President & CEO |
1515 Arapahoe Street | | | | Nancy Buese, Executive VP and CFO |
Tower 1, Suite 1600 | | | | Josh Hallenbeck, VP of Finance & Treasurer |
Denver, Colorado 80202 | | Phone: | | (866) 858-0482 |
| | E-mail: | | investorrelations@markwest.com |
MarkWest Energy Partners Reports Third Quarter Financial Results; Places into Service Three Major Facilities; Announces Additional Midstream Infrastructure Project in the Marcellus Shale
· Placed into service Seneca I, a 200 MMcf/d cryogenic processing facility in the Utica Shale and is the first of three major processing facilities expected to be operational at this complex within the next six months.
· Placed into service Majorsville V, a 200 MMcf/d cryogenic processing facility that increases the Partnership’s total processing capacity in the Marcellus Shale to over 1.8 Bcf/d.
· Executed agreements with Antero Resources to expand the Sherwood processing complex by 200 MMcf/d, bringing total capacity of the complex to 1 Bcf/d by the third quarter of 2014.
· MarkWest Utica EMG and Kinder Morgan Energy Partners announced a binding open season to solicit commitments for the NGL pipeline project from Mercer, PA to Mt. Belvieu, TX.
· The Partnership has 22 major processing and fractionation facilities under construction.
· Fee-based net operating margin increased from 53 percent to 62 percent when compared to the third quarter of 2012.
DENVER—November 12, 2013—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 $117.9 million for the three months ended September 30, 2013, and $356.1 million for the nine months ended September 30, 2013. DCF for the three months ended September 30, 2013 represents 92 percent coverage of the third quarter distribution of $127.9 million or $0.85 per common unit, which will be paid to unitholders on November 14, 2013. The third quarter 2013 distribution represents an increase of $0.01 per common unit or 1.2 percent over the second quarter 2013 distribution and an increase of $0.04 per common unit or 4.9 percent compared to the third 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 for the three and nine months ended September 30, 2013, of $153.9 million and $450.5 million, respectively, as compared to $115.5 million and $390.5 million for the three and nine months ended September 30, 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 and nine months ended September 30, 2013, of $(30.3) million and $56.9 million, respectively. (Loss) income
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before provision for income tax includes non-cash loss associated with the change in fair value of derivative instruments of $47.5 million and $1.2 million for the respective three and nine months ended September 30, 2013, a gain of $0.7 million and $38.9 million related to the divestiture of gathering assets in the Marcellus Shale for the respective three and nine months ended September 30, 2013, and a loss associated with the redemption of debt of $38.5 million for the nine months ended September 30, 2013. Excluding these items, income before provision for income tax for the three and nine months ended September 30, 2013 would have been $16.5 million and $57.7 million, respectively.
“Our results reflect the continued success of our producers’ as they rapidly develop their acreage positions in high-quality unconventional resource plays, as well as several short-term operational constraints that we have recently experienced in the Northeast,” said Frank Semple, Chairman, President and Chief Executive Officer. “Development of the Marcellus and Utica Shales continues to provide us with significant future growth opportunities for the expansion of critical midstream infrastructure. We are committed to providing our producers with exceptional customer service and unique solutions that will support their ongoing success.”
BUSINESS HIGHLIGHTS
Marcellus:
· In July 2013, the Partnership commenced operations of the Houston De-ethanizer, a 38,000 barrel per day (Bbl/d) fractionator that is producing purity ethane from Marcellus rich-gas production. The Houston De-ethanizer will initially support Mariner West, an ethane purity products pipeline project being developed by Sunoco Logistics Partners, L.P. (NYSE: SXL) (Sunoco), and in the future, will support the ATEX and Mariner East ethane takeaway projects.
· In August 2013, the Partnership announced the development of additional fractionation facilities to support producers’ growing rich-gas production in the Marcellus Shale. By the second quarter of 2014, the Partnership will install de-ethanization and de-propanization units totaling 20,000 Bbl/d of capacity at the Keystone complex in Butler County, Pennsylvania. In addition, the Partnership announced plans to install a 38,000 Bbl/d de-ethanization facility at the Sherwood complex in Doddridge County, West Virginia.
· In August 2013, the Partnership announced an expansion of the Mobley complex in Wetzel County, West Virginia to support EQT Corporation (NYSE: EQT) and other producers’ rich-gas development in the Marcellus Shale. The new 200 million cubic feet per day (MMcf/d) processing facility is currently scheduled to begin operations in the fourth quarter of 2014. Upon completion of this facility, the Mobley complex will have processing capacity of 720 MMcf/d.
· 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 MMcf/d processing facility that is scheduled to begin operations in the third quarter of 2014. Upon completion of this facility, the Sherwood complex will have processing capacity of 1 billion cubic feet per day (Bcf/d).
· In November 2013, the Partnership announced the completion of Majorsville V, a new 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
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(NYSE: CHK), and Statoil ASA (NYSE: STO) and increases the total processing capacity of the complex to 670 MMcf/d.
Utica:
· In August 2013, MarkWest Utica EMG announced plans to install a 38,000 (Bbl/d) de-ethanization facility at the Seneca complex in Noble County, Ohio.
· In August 2013, MarkWest Utica EMG announced plans to form a Joint Venture (JV) with Kinder Morgan Energy Partners, LP (NYSE: KMP) (Kinder Morgan) to pursue three critical new projects to support producers in the Utica and Marcellus Shales. The JV would develop a processing complex in Tuscarawas County, Ohio with an initial capacity of 200 MMcf/d and a 150,000 Bbl/d NGL pipeline to transport ethane and heavier natural gas liquids to JV fractionation facilities in Mt. Belvieu. In November 2013, MarkWest Utica EMG and Kinder Morgan announced a binding open season to solicit commitments for the NGL pipeline project.
· In November 2013, MarkWest Utica EMG announced it commenced operations of Seneca I, a 200 MMcf/d cryogenic processing facility in Noble County, Ohio. Seneca I 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.
Southwest:
· In August 2013, the Partnership announced the connection of gathering assets acquired from a wholly owned subsidiary of Chesapeake Energy to the Partnership’s existing Anadarko Basin gathering system. Connecting these gathering systems has allowed the Partnership to begin processing approximately 50 MMcf/d of additional rich-gas production at its Arapaho processing complex.
Capital Markets
· During the third quarter of 2013, the Partnership offered 10.4 million units and received net proceeds of approximately $691.5 million.
· During the third quarter of 2013, the Partnership completed the $600 million and $400 million continuous offering programs launched in the fourth quarter of 2012 and third quarter of 2013, respectively. In addition, during the third quarter of 2013, the Partnership launched a $1 billion continuous offering program under which the Partnership has issued 0.9 million units and received $59.5 million of net proceeds as of the end of the third quarter of 2013.
FINANCIAL RESULTS
Balance Sheet
· As of September 30, 2013, the Partnership had $326.6 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.
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Operating Results
· Operating income before items not allocated to segments for the three months ended September 30, 2013, was $181.9 million, an increase of $37.9 million when compared to segment operating income of $144.0 million over the same period in 2012. This increase was primarily attributable to higher processing volumes. Processed volumes continued to increase in the third quarter of 2013, growing approximately 57 percent when compared to the third 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 third quarter of 2013. Due to these considerations, operating income was lower than expected by approximately $14 million.
· The Partnership’s producer customers’ highly successful drilling programs throughout the Marcellus and Utica have resulted in a dramatic increase in natural gas liquids (NGLs) production. As a result, liquids production throughout the region has surpassed the capacity of the Partnership’s 60,000 Bbl/d Houston fractionator in Washington County, Pennsylvania and its 24,000 Bbl/d Siloam fractionator in South Shore, Kentucky. In January 2014, the Partnership and MarkWest Utica EMG, a joint venture between the Partnership and the Energy & Minerals Group, expect to commence operations of the Hopedale fractionation and marketing complex in Harrison County, Ohio. The complex will be connected via an NGL pipeline to the Partnership’s Marcellus infrastructure and will alleviate the current constraints associated with the production of purity products. However, in the interim the Partnership has made arrangements for continued fractionation services for its producer customer’s excess volumes through third-party facilities. As part of these arrangements, the Partnership has incurred, and until the end of the year, will continue to incur additional transportation costs and realize lower fractionation income.
· In July, the Partnership placed into operation its first large-scale de-ethanization facility in the Northeast capable of producing purity ethane. Since startup, the facility has provided line-fill for Mariner West, an ethane purity products pipeline project being developed by Sunoco, which will deliver Marcellus purity ethane to Sarnia, Ontario, Canada. Delays of the Sunoco project have occurred, and as a result, the Partnership has realized lower income during this period. The Mariner West pipeline is expected to become operational during the fourth quarter of 2013. Together with the completion of the ATEX pipeline project and Mariner East project, the Partnership anticipates growing utilization of its de-ethanization facilities.
· A landslide in August impacted a portion of the Partnership’s NGL pipeline in a remote area of Wetzel County, West Virginia causing a line break. As a result of this incident, the Mobley complex was offline for approximately two months as necessary repairs and remediation were completed. During this period the Partnership’s Sherwood complex in Doddridge County, West Virginia also experienced partially curtailed processing volumes; however, NGLs produced at the Sherwood complex were delivered by truck for fractionation. During mid-October, the Partnership safely resumed operations of the pipeline and the Mobley and Sherwood complexes have returned to full operation.
The Partnership has changed the Liberty segment name. Starting with the third quarter of 2013 financial and operating results, the Liberty segment will now be reported as the Marcellus segment. 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.
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· Operating income before items not allocated to segments does not include losses on commodity derivative instruments. Realized losses on commodity derivative instruments were $5.3 million in the third quarter of 2013 and $8.4 million in the third quarter of 2012.
Capital Expenditures
· For the three months ended September 30, 2013, the Partnership’s portion of capital expenditures was $650.5 million.
2013 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST
For 2013, the Partnership forecasts DCF in a range of $475 million to $485 million based on its current forecast of operational volumes, expected impact of short-term operational constraints and prices for crude oil, natural gas, natural gas liquids and derivative instruments currently outstanding.
The Partnership’s portion of growth capital expenditures for 2013 has increased to a range of $2.0 billion to $2.3 billion primarily due to the addition of announced expansion projects and an acceleration of spending on other projects in the Marcellus and Utica segments. These expenditures do not include the Granite Wash Acquisition or the divestiture of the high-pressure gathering system in the Marcellus Shale during the second quarter 2013. Maintenance capital is forecasted at approximately $20 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. A commodity price sensitivity analysis for forecasted 2014 DCF 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 and webcast on Wednesday, November 13, 2013, at 12:00 p.m. Eastern Time to review its third quarter 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. To access the webcast, please visit the Investor Relations section of the Partnership’s website at www.markwest.com. A replay of the conference call will be available on the MarkWest website or by dialing (800) 926-7934 (no passcode required).
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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
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believes that the expectations reflected in the forward-looking statements are reasonable, MarkWest can give no assurance that such expectations will prove to be correct. The forward-looking statements involve risks and uncertainties that affect operations, financial performance, and other factors as discussed in filings with the Securities and Exchange Commission (SEC). Among the factors that could cause results to differ materially are those risks discussed in the periodic reports filed with the SEC, including MarkWest’s Annual Report on Form 10-K for the year ended December 31, 2012 and our Quarterly Report on Form 10-Q for the quarter ended September 30, 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.
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MarkWest Energy Partners, L.P.
Financial Statistics
(unaudited, in thousands, except per unit data)
| | Three months ended September 30, | | Nine months ended September 30, | |
| | 2013 | | 2012 | | 2013 | | 2012 | |
Statement of Operations Data | | | | | | | | | |
Revenue: | | | | | | | | | |
Revenue | | $ | 450,834 | | $ | 316,976 | | $ | 1,219,713 | | $ | 1,019,709 | |
Derivative (loss) gain | | (30,318 | ) | (36,400 | ) | (10,804 | ) | 50,952 | |
Total revenue | | 420,516 | | 280,576 | | 1,208,909 | | 1,070,661 | |
| | | | | | | | | |
Operating expenses: | | | | | | | | | |
Purchased product costs | | 191,672 | | 119,369 | | 499,588 | | 386,655 | |
Derivative loss (gain) related to purchased product costs | | 20,234 | | 11,643 | | (10,902 | ) | (21,136 | ) |
Facility expenses | | 77,542 | | 52,883 | | 199,849 | | 149,438 | |
Derivative loss related to facility expenses | | 2,332 | | 4,028 | | 2,800 | | 1,136 | |
Selling, general and administrative expenses | | 26,647 | | 21,723 | | 77,388 | | 68,471 | |
Depreciation | | 76,323 | | 46,554 | | 215,902 | | 127,472 | |
Amortization of intangible assets | | 16,003 | | 14,988 | | 47,925 | | 38,280 | |
Loss (gain) on sale or disposal of property, plant and equipment | | 1,840 | | 655 | | (35,758 | ) | 2,983 | |
Accretion of asset retirement obligations | | 160 | | 140 | | 669 | | 536 | |
Total operating expenses | | 412,753 | | 271,983 | | 997,461 | | 753,835 | |
| | | | | | | | | |
Income from operations | | 7,763 | | 8,593 | | 211,448 | | 316,826 | |
| | | | | | | | | |
Other income (expense): | | | | | | | | | |
Equity in earnings from unconsolidated affiliates | | 896 | | 706 | | 1,561 | | 2,254 | |
Interest income | | 27 | | 64 | | 238 | | 295 | |
Interest expense | | (38,889 | ) | (30,621 | ) | (114,180 | ) | (86,855 | ) |
Amortization of deferred financing costs and discount (a component of interest expense) | | (1,584 | ) | (1,428 | ) | (5,198 | ) | (3,943 | ) |
Loss on redemption of debt | | — | | — | | (38,455 | ) | — | |
Miscellaneous income, net | | 1,504 | | 1 | | 1,510 | | 63 | |
(Loss) income before provision for income tax | | (30,283 | ) | (22,685 | ) | 56,924 | | 228,640 | |
| | | | | | | | | |
Provision for income tax (benefit) expense: | | | | | | | | | |
Current | | (2,344 | ) | (17,948 | ) | (10,503 | ) | 2,202 | |
Deferred | | (7,912 | ) | 10,528 | | 23,087 | | 39,396 | |
Total provision for income tax | | (10,256 | ) | (7,420 | ) | 12,584 | | 41,598 | |
| | | | | | | | | |
Net (loss) income | | (20,027 | ) | (15,265 | ) | 44,340 | | 187,042 | |
| | | | | | | | | |
Net (loss) income attributable to non-controlling interest | | (3,577 | ) | 925 | | 297 | | 1,546 | |
| | | | | | | | | |
Net (loss) income attributable to the Partnership’s unitholders | | $ | (23,604 | ) | $ | (14,340 | ) | $ | 44,637 | | $ | 188,588 | |
| | | | | | | | | |
Net (loss) income attributable to the Partnership’s common unitholders per common unit: | | | | | | | | | |
Basic | | $ | (0.17 | ) | $ | (0.13 | ) | $ | 0.32 | | $ | 1.77 | |
Diluted | | $ | (0.17 | ) | $ | (0.13 | ) | $ | 0.29 | | $ | 1.49 | |
| | | | | | | | | |
Weighted average number of outstanding common units: | | | | | | | | | |
Basic | | 142,352 | | 113,994 | | 134,115 | | 105,916 | |
Diluted | | 142,352 | | 113,994 | | 153,455 | | 126,595 | |
| | | | | | | | | |
Cash Flow Data | | | | | | | | | |
Net cash flow provided by (used in): | | | | | | | | | |
Operating activities | | $ | 153,063 | | $ | 132,163 | | $ | 330,659 | | $ | 385,784 | |
Investing activities | | $ | (751,286 | ) | $ | (658,635 | ) | $ | (2,186,307 | ) | $ | (1,745,749 | ) |
Financing activities | | $ | 571,822 | | $ | 816,452 | | $ | 1,838,045 | | $ | 1,657,986 | |
| | | | | | | | | |
Other Financial Data | | | | | | | | | |
Distributable cash flow | | $ | 117,897 | | $ | 104,289 | | $ | 356,113 | | $ | 304,950 | |
Adjusted EBITDA | | $ | 153,936 | | $ | 115,531 | | $ | 450,477 | | $ | 390,515 | |
| | September 30, 2013 | | December 31, 2012 | |
Balance Sheet Data | | | | | | | |
Working capital | | $ | (263,896 | ) | $ | (84,512 | ) |
Total assets | | 8,917,716 | | 6,728,362 | |
Total debt | | 3,022,887 | | 2,523,051 | |
Total equity | | 4,150,443 | | 3,111,398 | |
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MarkWest Energy Partners, L.P.
Operating Statistics
| | Three months ended September 30, | | Nine months ended September 30, | |
| | 2013 | | 2012 | | 2013 | | 2012 | |
Marcellus | | | | | | | | | |
Gathering system throughput (Mcf/d) (1) | | 563,200 | | 444,700 | | 617,200 | | 373,700 | |
Natural gas processed (Mcf/d) | | 1,137,400 | | 479,400 | | 1,000,900 | | 424,300 | |
NGLs fractionated (Bbl/d) | | 48,200 | | 22,300 | | 44,500 | | 20,700 | |
NGL sales (gallons, in thousands) (2) | | 229,900 | | 90,800 | | 536,100 | | 264,200 | |
| | | | | | | | | |
Utica (3) | | | | | | | | | |
Gathering system throughput (Mcf/d) | | 85,100 | | N/A | | 47,100 | | N/A | |
Natural gas processed (Mcf/d) | | 131,100 | | N/A | | 62,200 | | N/A | |
| | | | | | | | | |
Northeast | | | | | | | | | |
Natural gas processed (Mcf/d) | | 297,800 | | 318,500 | | 298,900 | | 322,800 | |
NGLs fractionated (Bbl/d) | | 21,500 | | 16,500 | | 18,900 | | 16,800 | |
| | | | | | | | | |
Keep-whole sales (gallons, in thousands) | | 28,200 | | 23,200 | | 92,600 | | 96,500 | |
Percent-of-proceeds sales (gallons, in thousands) | | 34,700 | | 33,700 | | 101,800 | | 103,500 | |
Total NGL sales (gallons, in thousands) (4) | | 62,900 | | 56,900 | | 194,400 | | 200,000 | |
| | | | | | | | | |
Crude oil transported for a fee (Bbl/d) | | 9,400 | | 8,700 | | 9,800 | | 9,100 | |
| | | | | | | | | |
Southwest | | | | | | | | | |
East Texas gathering systems throughput (Mcf/d) | | 494,300 | | 471,200 | | 505,000 | | 440,700 | |
East Texas natural gas processed (Mcf/d) | | 345,400 | | 270,200 | | 354,200 | | 260,400 | |
East Texas NGL sales (gallons, in thousands) (5) | | 78,500 | | 67,800 | | 249,300 | | 199,300 | |
| | | | | | | | | |
Western Oklahoma gathering system throughput (Mcf/d) (6) | | 262,000 | | 227,900 | | 228,400 | | 247,300 | |
Western Oklahoma natural gas processed (Mcf/d) | | 218,500 | | 209,600 | | 198,400 | | 210,800 | |
Western Oklahoma NGL sales (gallons, in thousands) | | 64,400 | | 50,900 | | 162,200 | | 169,900 | |
| | | | | | | | | |
Southeast Oklahoma gathering system throughput (Mcf/d) | | 444,200 | | 484,400 | | 459,500 | | 496,200 | |
Southeast Oklahoma natural gas processed (Mcf/d) (7) | | 156,700 | | 128,600 | | 156,100 | | 116,700 | |
Southeast Oklahoma NGL sales (gallons, in thousands) | | 44,000 | | 46,700 | | 137,300 | | 121,000 | |
| | | | | | | | | |
Other Southwest gathering system throughput (Mcf/d) (8) | | 33,000 | | 23,600 | | 31,200 | | 25,000 | |
| | | | | | | | | |
Gulf Coast refinery off-gas processed (Mcf/d) | | 117,100 | | 123,800 | | 110,100 | | 120,000 | |
Gulf Coast liquids fractionated (Bbl/d) | | 21,400 | | 23,800 | | 20,300 | | 23,000 | |
Gulf Coast NGL sales (gallons excluding hydrogen, in thousands) | | 82,800 | | 92,100 | | 232,500 | | 264,400 | |
(1) Gathered volumes reflect the first full quarter following the sale of the Sherwood gathering assets in the 2nd quarter of 2013.
(2) Includes sale of all purity products fractionated at the Marcellus facilities and the sale of all unfractionated NGLs.
(3) Utica operations began in August 2012.
(4) Represents sales at the Siloam fractionator. The total sales exclude approximately 21,000,000 gallons, 595,000 gallons, 27,900,000 gallons, and 975,000 gallons sold by the Northeast on behalf of Marcellus for the three months and nine months ended September 30, 2013 and 2012, respectively. These volumes are included as part of NGLs sold at Marcellus.
(5) Includes approximately 1,390,000 gallons and 13,700,000 gallons processed in conjunction with take in kind contracts for the three and nine months ended September 30, 2013, respectively.
(6) 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.
(7) The natural gas processing in Southeast Oklahoma is outsourced to Centrahoma or other third-party processors.
(8) Excludes lateral pipelines where revenue is not based on throughput.
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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)
| | Marcellus | | Utica | | Northeast | | Southwest | | Total | |
Three months ended September 30, 2013 | | | | | | | | | | | | | | | | |
Segment revenue | | $ | 147,290 | | $ | 8,373 | | $ | 48,829 | | $ | 247,885 | | $ | 452,377 | |
| | | | | | | | | | | |
Operating expenses: | | | | | | | | | | | |
Purchased product costs | | 36,995 | | — | | 15,330 | | 139,347 | | 191,672 | |
Facility expenses | | 29,621 | | 9,858 | | 7,359 | | 32,559 | | 79,397 | |
Total operating expenses before items not allocated to segments | | 66,616 | | 9,858 | | 22,689 | | 171,906 | | 271,069 | |
| | | | | | | | | | | |
Portion of operating (loss) income attributable to non-controlling interests | | — | | (599 | ) | — | | 40 | | (559 | ) |
Operating income (loss) before items not allocated to segments | | $ | 80,674 | | $ | (886 | ) | $ | 26,140 | | $ | 75,939 | | $ | 181,867 | |
| | Marcellus | | Utica | | Northeast | | Southwest | | Total | |
Three months ended September 30, 2012 | | | | | | | | | | | |
Segment revenue | | $ | 78,707 | | $ | 145 | | $ | 39,987 | | $ | 199,394 | | $ | 318,233 | |
| | | | | | | | | | | |
Operating expenses: | | | | | | | | | | | |
Purchased product costs | | 16,203 | | — | | 11,054 | | 92,112 | | 119,369 | |
Facility expenses | | 18,933 | | 1,308 | | 6,267 | | 28,870 | | 55,378 | |
Total operating expenses before items not allocated to segments | | 35,136 | | 1,308 | | 17,321 | | 120,982 | | 174,747 | |
| | | | | | | | | | | |
Portion of operating (loss) income attributable to non-controlling interests | | — | | (627 | ) | — | | 67 | | (560 | ) |
Operating income (loss) before items not allocated to segments | | $ | 43,571 | | $ | (536 | ) | $ | 22,666 | | $ | 78,345 | | $ | 144,046 | |
| | Three months ended September 30, | |
| | 2013 | | 2012 | |
| | | | | |
Operating income before items not allocated to segments | | $ | 181,867 | | $ | 144,046 | |
Portion of operating loss attributable to non-controlling interests | | (559 | ) | (560 | ) |
Derivative loss not allocated to segments | | (52,884 | ) | (52,071 | ) |
Revenue deferral adjustment and other | | (1,543 | ) | (1,257 | ) |
Compensation expense included in facility expenses not allocated to segments | | (833 | ) | (193 | ) |
Facility expenses adjustments | | 2,688 | | 2,688 | |
Selling, general and administrative expenses | | (26,647 | ) | (21,723 | ) |
Depreciation | | (76,323 | ) | (46,554 | ) |
Amortization of intangible assets | | (16,003 | ) | (14,988 | ) |
Loss on disposal of property, plant and equipment | | (1,840 | ) | (655 | ) |
Accretion of asset retirement obligations | | (160 | ) | (140 | ) |
Income from operations | | 7,763 | | 8,593 | |
Other income (expense): | | | | | |
Earnings from unconsolidated affiliates | | 896 | | 706 | |
Interest income | | 27 | | 64 | |
Interest expense | | (38,889 | ) | (30,621 | ) |
Amortization of deferred financing costs and discount (a component of interest expense) | | (1,584 | ) | (1,428 | ) |
Miscellaneous income, net | | 1,504 | | 1 | |
Income before provision for income tax | | $ | (30,283 | ) | $ | (22,685 | ) |
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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)
| | Marcellus | | Utica | | Northeast | | Southwest | | Total | |
Nine months ended September 30, 2013 | | | | | | | | | | | |
Segment revenue | | $ | 375,844 | | $ | 12,590 | | $ | 151,530 | | $ | 684,093 | | $ | 1,224,057 | |
| | | | | | | | | | | |
Operating expenses: | | | | | | | | | | | |
Purchased product costs | | 72,781 | | — | | 50,118 | | 376,689 | | 499,588 | |
Facility expenses | | 74,529 | | 20,232 | | 20,538 | | 91,027 | | 206,326 | |
Total operating expenses before items not allocated to segments | | 147,310 | | 20,232 | | 70,656 | | 467,716 | | 705,914 | |
| | | | | | | | | | | |
Portion of operating (loss) income attributable to non-controlling interests | | — | | (3,081 | ) | — | | 157 | | (2,924 | ) |
Operating income (loss) before items not allocated to segments | | $ | 228,534 | | $ | (4,561 | ) | $ | 80,874 | | $ | 216,220 | | $ | 521,067 | |
| | Marcellus | | Utica | | Northeast | | Southwest | | Total | |
Nine months ended September 30, 2012 | | | | | | | | | | | |
Segment revenue | | $ | 213,761 | | $ | 145 | | $ | 168,956 | | $ | 641,321 | | $ | 1,024,183 | |
| | | | | | | | | | | |
Operating expenses: | | | | | | | | | | | |
Purchased product costs | | 48,856 | | — | | 49,662 | | 288,137 | | 386,655 | |
Facility expenses | | 44,544 | | 1,591 | | 17,577 | | 92,964 | | 156,676 | |
Total operating expenses before items not allocated to segments | | 93,400 | | 1,591 | | 67,239 | | 381,101 | | 543,331 | |
| | | | | | | | | | | |
Portion of operating (loss) income attributable to non-controlling interests | | — | | (740 | ) | — | | 98 | | (642 | ) |
Operating income (loss) before items not allocated to segments | | $ | 120,361 | | $ | (706 | ) | $ | 101,717 | | $ | 260,122 | | $ | 481,494 | |
| | Nine months ended September 30, | |
| | 2013 | | 2012 | |
| | | | | |
Operating income before items not allocated to segments | | $ | 521,067 | | $ | 481,494 | |
Portion of operating loss attributable to non-controlling interests | | (2,924 | ) | (642 | ) |
Derivative (loss) gain not allocated to segments | | (2,702 | ) | 70,952 | |
Revenue deferral adjustment and other | | (4,344 | ) | (4,474 | ) |
Compensation expense included in facility expenses not allocated to segments | | (1,587 | ) | (826 | ) |
Facility expenses adjustments | | 8,064 | | 8,064 | |
Selling, general and administrative expenses | | (77,388 | ) | (68,471 | ) |
Depreciation | | (215,902 | ) | (127,472 | ) |
Amortization of intangible assets | | (47,925 | ) | (38,280 | ) |
Gain (loss) on disposal of property, plant and equipment | | 35,758 | | (2,983 | ) |
Accretion of asset retirement obligations | | (669 | ) | (536 | ) |
Income from operations | | 211,448 | | 316,826 | |
Other income (expense): | | | | | |
Earnings from unconsolidated affiliates | | 1,561 | | 2,254 | |
Interest income | | 238 | | 295 | |
Interest expense | | (114,180 | ) | (86,855 | ) |
Amortization of deferred financing costs and discount (a component of interest expense) | | (5,198 | ) | (3,943 | ) |
Loss on redemption of debt | | (38,455 | ) | — | |
Miscellaneous income, net | | 1,510 | | 63 | |
Income before provision for income tax | | $ | 56,924 | | $ | 228,640 | |
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Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Distributable Cash Flow
(unaudited, in thousands)
| | Three months ended September 30, | | Nine months ended September 30, | |
| | 2013 | | 2012 | | 2013 | | 2012 | |
| | | | | | | | | |
Net income | | $ | (20,027 | ) | $ | (15,265 | ) | $ | 44,340 | | $ | 187,042 | |
Depreciation, amortization and other non-cash operating expenses | | 92,564 | | 61,761 | | 264,730 | | 166,522 | |
Loss (gain) on sale and or disposal of assets, net of tax benefit | | 1,840 | | 655 | | (32,711 | ) | 2,983 | |
Loss on redemption of debt, net of tax benefit | | — | | — | | 36,178 | | — | |
Amortization of deferred financing costs and discount | | 1,584 | | 1,428 | | 5,198 | | 3,943 | |
Non-cash earnings from unconsolidated affiliates | | (896 | ) | (706 | ) | (1,561 | ) | (2,254 | ) |
Distributions from unconsolidated affiliates | | 2,224 | | 2,058 | | 4,952 | | 6,624 | |
Non-cash compensation expense | | 1,924 | | 981 | | 5,464 | | 6,271 | |
Non-cash derivative activity | | 47,542 | | 43,712 | | 1,222 | | (101,815 | ) |
Provision for income tax - deferred | | (7,912 | ) | 10,528 | | 23,087 | | 39,396 | |
Cash adjustment for non-controlling interest of consolidated subsidiaries | | 1,183 | | 787 | | 4,672 | | 1,391 | |
Revenue deferral adjustment | | 1,754 | | 1,635 | | 5,164 | | 5,604 | |
Other | | 2,887 | | 549 | | 7,753 | | 3,067 | |
Maintenance capital expenditures, net of joint venture partner contributions | | (6,770 | ) | (3,834 | ) | (12,375 | ) | (13,824 | ) |
Distributable cash flow | | $ | 117,897 | | $ | 104,289 | | $ | 356,113 | | $ | 304,950 | |
| | | | | | | | | |
Maintenance capital expenditures | | $ | 6,770 | | $ | 3,834 | | $ | 12,375 | | $ | 13,824 | |
Growth capital expenditures | | 734,865 | | 654,891 | | 2,164,344 | | 1,225,881 | |
Total capital expenditures | | 741,635 | | 658,725 | | 2,176,719 | | 1,239,705 | |
Acquisitions, net of cash acquired | | — | | — | | 225,210 | | 506,797 | |
Total capital expenditures and acquisitions | | 741,635 | | 658,725 | | 2,401,929 | | 1,746,502 | |
Joint venture partner contributions | | (91,163 | ) | (55,000 | ) | (716,982 | ) | (55,000 | ) |
Total capital expenditures and acquisitions, net | | $ | 650,472 | | $ | 603,725 | | $ | 1,684,947 | | $ | 1,691,502 | |
| | | | | | | | | |
Distributable cash flow | | $ | 117,897 | | $ | 104,289 | | $ | 356,113 | | $ | 304,950 | |
Maintenance capital expenditures, net of joint venture partner contributions | | 6,770 | | 3,834 | | 12,375 | | 13,824 | |
Changes in receivables and other assets | | (6,969 | ) | (85,658 | ) | (74,470 | ) | 26,296 | |
Changes in accounts payable, accrued liabilities and other long-term liabilities | | 38,504 | | 110,658 | | 48,557 | | 45,468 | |
Cash adjustment for non-controlling interest of consolidated subsidiaries | | (1,183 | ) | (787 | ) | (4,672 | ) | (1,391 | ) |
Other | | (1,956 | ) | (173 | ) | (7,244 | ) | (3,363 | ) |
Net cash provided by operating activities | | $ | 153,063 | | $ | 132,163 | | $ | 330,659 | | $ | 385,784 | |
11
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Adjusted EBITDA
(unaudited, in thousands)
| | Three months ended September 30, | | Nine months ended September 30, | |
| | 2013 | | 2012 | | 2013 | | 2012 | |
| | | | | | | | | |
Net income | | $ | (20,027 | ) | $ | (15,265 | ) | $ | 44,340 | | $ | 187,042 | |
Non-cash compensation expense | | 1,924 | | 981 | | 5,464 | | 6,271 | |
Non-cash derivative activity | | 47,542 | | 43,712 | | 1,222 | | (101,815 | ) |
Interest expense (1) | | 38,356 | | 29,882 | | 112,988 | | 84,260 | |
Depreciation, amortization and other non-cash operating expenses | | 92,564 | | 61,761 | | 264,730 | | 166,522 | |
Loss (gain) on sale and or disposal of assets | | 1,840 | | 655 | | (35,758 | ) | 2,983 | |
Loss on redemption of debt | | — | | — | | 38,455 | | — | |
Provision for income tax | | (10,256 | ) | (7,420 | ) | 12,584 | | 41,598 | |
Adjustment for cash flow from unconsolidated affiliate | | 1,328 | | 1,352 | | 3,391 | | 4,370 | |
Other | | 665 | | (127 | ) | 3,061 | | (716 | ) |
Adjusted EBITDA | | $ | 153,936 | | $ | 115,531 | | $ | 450,477 | | $ | 390,515 | |
(1) Includes amortization of deferred financing costs and discount, and excludes interest expense related to the Steam Methane Reformer.
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MarkWest Energy Partners, L.P.
Distributable Cash Flow Sensitivity Analysis
(unaudited, in millions)
MarkWest periodically estimates the effect on DCF resulting from its commodity risk management program, changes in crude oil and natural gas prices, and the ratio of NGL prices to crude oil. The table below reflects MarkWest’s estimate of the range of DCF for 2014 and forecasted crude oil and natural gas prices for 2014. The analysis assumes various combinations of crude oil and natural gas prices as well as three NGL-to-crude oil ratio scenarios, including:
a. NGL-to-crude oil ratio at 50% for 2014.
b. NGL-to-crude oil ratio at 40% for 2014.
c. NGL-to-crude oil ratio at 30% for 2014.
The analysis further assumes derivative instruments outstanding as of November 5, 2013, 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
Crude Oil Price | | NGL-to-Crude | | Natural Gas Price (Henry Hub) | |
(WTI) | | Oil ratio (1) | | $3.00 | | $3.50 | | $4.00 | | $4.50 | |
$ | 110 | | 50% of WTI | | $ | 740 | | $ | 737 | | $ | 733 | | $ | 730 | |
| 40% of WTI | | $ | 684 | | $ | 681 | | $ | 677 | | $ | 674 | |
| 30% of WTI | | $ | 634 | | $ | 630 | | $ | 627 | | $ | 623 | |
$ | 100 | | 50% of WTI | | $ | 710 | | $ | 706 | | $ | 703 | | $ | 699 | |
| 40% of WTI | | $ | 661 | | $ | 658 | | $ | 654 | | $ | 650 | |
| 30% of WTI | | $ | 609 | | $ | 605 | | $ | 602 | | $ | 598 | |
$ | 90 | | 50% of WTI | | $ | 678 | | $ | 675 | | $ | 671 | | $ | 668 | |
| 40% of WTI | | $ | 644 | | $ | 641 | | $ | 637 | | $ | 634 | |
| 30% of WTI | | $ | 589 | | $ | 585 | | $ | 582 | | $ | 578 | |
$ | 80 | | 50% of WTI | | $ | 649 | | $ | 645 | | $ | 642 | | $ | 638 | |
| 40% of WTI | | $ | 613 | | $ | 609 | | $ | 606 | | $ | 602 | |
| 30% of WTI | | $ | 572 | | $ | 569 | | $ | 565 | | $ | 560 | |
(1) The composition is based on MarkWest’s average projected barrel of approximately: Ethane: 35%, Propane: 35%, Iso-Butane: 6%, Normal Butane: 12%, Natural Gasoline: 12%.
The table is based on current information, expectations, and beliefs concerning future developments and their potential effects, and does not consider actions MarkWest management may take to mitigate exposure to changes. Nor does the table consider the effects that such hypothetical adverse changes may have on overall economic activity. Historical prices and ratios of NGL-to-crude oil do not guarantee future results.
Although MarkWest believes the expectations reflected in this analysis are reasonable, MarkWest can give no assurance that such expectations will prove to be correct and readers are cautioned that projected performance, results, or distributions may not be achieved. Actual changes in market prices, and the ratio between crude oil and NGL prices, may differ from the assumptions utilized in the analysis. Actual results, performance, distributions, volumes, events, or transactions could vary significantly from those expressed, considered, or implied in this analysis. All results, performance, distributions, volumes, events, or transactions are subject to a number of uncertainties and risks. Those uncertainties and risks may not be factored into or accounted for in this analysis. Readers are urged to carefully review and consider the cautionary statements and disclosures made in MarkWest’s periodic reports filed with the SEC, specifically those under the heading “Risk Factors.”
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