DENVER--(BUSINESS WIRE)--MarkWest Energy Partners, L.P. (NYSE: MWE) (the Partnership) today reported record quarterly cash available for distribution to common unitholders, or distributable cash flow (DCF), of $69.1 million for the three months ended December 31, 2010, and $241.1 million for the year ended December 31, 2010. DCF for the three months and year ended December 31, 2010, represents 142 percent and 130 percent coverage, respectively, of the cash distributions declared for those periods. As a Master Limited Partnership, cash distributions to common unitholders are largely determined based on DCF. A reconciliation of DCF to net income (loss), the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.
The Partnership reported Adjusted EBITDA of $88.2 million for the three months ended December 31, 2010, and $333.1 million for the year ended December 31, 2010. MarkWest 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 (loss), the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.
The Partnership reported income (loss) before provision for income tax for the three months and year ended December 31, 2010, of $(50.2) million and of $34.3 million, respectively. Income (loss) before provision for income tax for the three months and year ended December 31, 2010, includes $(75.3) million and $(60.5) million, respectively, of non-cash costs associated with the change in mark-to-market of derivative instruments and loss associated with the redemption of debt. Excluding these non-cash items, income (loss) before provision for income tax for the three months and year ended December 31, 2010, would have been $25.1 million and $94.8 million, respectively.
“We are very pleased with our execution and performance over the past year, which resulted in strong growth in distributable cash flow and the continued expansion of our midstream operations in the Northeast, Southwest, and Liberty business units,” said Frank Semple, Chairman, President and Chief Executive Officer. “We have also raised more than $1 billion in capital since the beginning of 2010 to fund our recent acquisitions and to support our organic growth projects in the some of the best resource plays in the United States. Our inventory of high-quality projects, coupled with our strong balance sheet and distribution coverage ratio, puts us in a great position to continue to provide top-quartile total returns for our unitholders.”
BUSINESS HIGHLIGHTS
Capital Markets
- On November 2, 2010, the Partnership completed a public offering of $500 million aggregate principal amount of 6.75% senior unsecured notes due 2020. The Partnership used the net proceeds from the offering to redeem its outstanding $375 million aggregate principal amount of 6.875% senior notes due 2014, to repay borrowings under its revolving credit facility, and to provide working capital for general Partnership purposes.
- On January 14, 2011, the Partnership completed a common unit equity offering of 3.45 million common units. The net proceeds of approximately $138 million were used primarily to fund a portion of the costs associated with the recently completed acquisition of EQT Corporation’s Langley, Kentucky natural gas processing complex and the partially completed Ranger natural gas liquids (NGL) pipeline.
- On February 24, 2011, the Partnership completed a public offering of $300 million aggregate principal amount of its 6.5% senior unsecured notes due 2021 resulting in net proceeds of $296.0 million. The Partnership used $294.4 million of the net proceeds from the offering to purchase 99% of its outstanding $275 million 8.5% senior notes due 2016, including accrued interest, pursuant to a tender offer for any and all of such outstanding notes. On February 9, 2011, the Partnership commenced a tender offer for up to $125 million aggregate principal amount of its outstanding 8.75% senior notes due 2018. On February 23, 2011, the tender offer amount was increased to $170 million and as of such date, holders of the senior notes due 2018 had tendered approximately $165.5 million in aggregate principal amount of the outstanding 8.75% senior notes due 2018 for repurchase at various bid prices. The tender offer for the senior notes due 2018 expires on March 9, 2011.
Business Development
- On February 1, 2011, the Partnership completed the acquisition of EQT’s Langley processing complex and Ranger NGL pipeline for approximately $230 million. The Langley complex includes a 100 million cubic feet per day (MMcf/d) cryogenic processing plant, a 75 MMcf/d refrigeration processing plant, and approximately 28,000 horsepower of compression. The Partnership will complete the Ranger pipeline to allow NGLs recovered at the Langley processing complex to be delivered via pipeline to the Partnership’s Siloam fractionation, storage, and marketing complex in South Shore, Kentucky. The Partnership will also install a new 60 MMcf/d cryogenic processing plant to expand the Langley cryogenic processing capacity. The Ranger pipeline and the new processing plant are expected to be online by mid 2012.
In conjunction with the acquisition, the Partnership executed a long-term agreement with EQT to provide processing services for EQT’s Kentucky Huron/Berea shale gas and to extend its existing agreement with EQT to provide NGL transportation, fractionation, and marketing services until 2022.
- On February 23, 2011, MarkWest announced the expansion of its Arapaho processing complex in Western Oklahoma to serve increasing volumes of liquids-rich natural gas production from Granite Wash producers, including Newfield Exploration and LINN Energy. MarkWest’s producer customers are focusing their drilling plans on the liquids-rich zones in the Granite Wash, which has significantly increased the percentage of rich-gas volumes that MarkWest is gathering and processing. To support this growth, MarkWest will expand its rich-gas gathering and compression facilities as well as its Arapaho processing complex. Upon completion of the facility expansions in the third quarter of 2011, the processing capacity at the Arapaho complex will increase by 60 MMcf/d to a total of 220 MMcf/d. The gathering and processing expansions are supported by long-term agreements with producer customers.
- Liberty – On January 4, 2011, MarkWest Liberty, a partnership between MarkWest and The Energy & Minerals Group, announced the development of a natural gas processing plant near EQT’s Logansport compressor station in Wetzel County, West Virginia. MarkWest Liberty will construct a 120 MMcf/d cryogenic gas processing facility and associated NGL pipeline by mid 2012 to process rich gas transported in EQT Corporation’s Equitrans gas pipeline. The NGLs recovered at the plant will be transported via a newly constructed pipeline to MarkWest Liberty’s fractionation, storage, and marketing complex in Houston, Pennsylvania.
On January 19, 2011, MarkWest Liberty announced the execution of a long-term agreement with Chesapeake Energy Corporation to provide additional natural gas midstream services for Chesapeake’s substantial rich-gas Marcellus acreage in northern West Virginia. MarkWest Liberty will provide the midstream services at its Majorsville, West Virginia processing complex, which includes a 135 MMcf/d cryogenic gas processing plant that is operating near capacity and a second 135 MMcf/d cryogenic plant that is under construction and nearing completion. The NGLs recovered at Majorsville are transported via pipeline to MarkWest Liberty’s Houston complex.
FINANCIAL RESULTS
Balance Sheet
- At December 31, 2010, the Partnership had $63.9 million of cash and cash equivalents in wholly owned subsidiaries and $677.6 million available for borrowing under its $705 million revolving credit facility after consideration of $27.4 million of outstanding letters of credit.
Operating Results
- Operating income before items not allocated to segments for the three months ended December 31, 2010, was $134.6 million, an increase of $24.1 million when compared to segment operating income of $110.5 million in the same period in 2009. This increase is primarily attributable to higher commodity prices compared to the prior year quarter, an increase in throughput volumes and NGL sales in certain business units, and a larger contribution from the Liberty segment.
- Operating income before items not allocated to segments does not include realized gain (loss) on commodity derivative instruments. Realized losses on commodity derivative instruments were $(19.8) million in the fourth quarter of 2010 compared to realized losses on commodity derivative instruments of $(6.9) million in the fourth quarter of 2009.
- In the fourth quarter of 2010, the Partnership recorded a charge of $46.3 million related to the redemption of its $375 million of senior notes due 2014. Approximately $36.6 million related to a non-cash write off of the unamortized discount and deferred finance costs and approximately $9.7 million related to the call and tender premiums associated with redeeming the 2014 senior notes. The effect of this refinancing was to extend the maturity of this portion of the Partnership's long-term debt until 2020 and to reduce the Partnership's cost of debt capital.
Growth Capital Expenditures
- For the three months and year ended December 31, 2010, the Partnership’s portion of growth capital expenditures was $55.3 million and $264.5 million, respectively.
2011 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST
The Partnership increased its 2011 DCF forecast to a range of $260 million to $310 million based on forecasted operational volumes from existing operations, growth capital projects that will be completed and commence operations during 2011, derivative instruments currently outstanding, and a reasonable range of price estimates for crude oil and natural gas. The midpoint of this range results in approximately 146 percent coverage of the Partnership’s full-year distribution based on current quarterly distributions and common units outstanding. A sensitivity analysis for forecasted 2011 DCF is provided within the tables of this press release.
The Partnership also updated its 2011 growth capital expenditure forecast to a range of $600 million to $650 million, which includes the $230 million acquisition of EQT’s Langley processing complex and the Ranger NGL pipeline. The Partnership forecasts maintenance capital for 2011 in a range of $10 million to $20 million.
CONFERENCE CALL
The Partnership will host a conference call and webcast on Tuesday, March 1, 2011, at 4:00 p.m. Eastern Time to review its fourth quarter 2010 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 800-879-1270 (no passcode required).
MarkWest Energy Partners, L.P. is a master limited partnership engaged in the gathering, transportation, and processing of natural gas; the transportation, fractionation, marketing, and storage of natural gas liquids; and the gathering and transportation of crude oil. MarkWest has extensive natural gas gathering, processing, and transmission operations in the southwest, Gulf Coast, and northeast regions of the United States, including the Marcellus Shale, and is the largest natural gas processor and fractionator in the Appalachian region.
This press release includes “forward-looking statements.” All statements other than statements of historical facts included or incorporated herein may constitute forward-looking statements. Actual results could vary significantly from those expressed or implied in such statements and are subject to a number of risks and uncertainties. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. The forward-looking statements involve risks and uncertainties that affect our operations, financial performance, and other factors as discussed in our filings with the Securities and Exchange Commission. Among the factors that could cause results to differ materially are those risks discussed in the periodic reports we file with the SEC, including our Annual Report on Form 10-K for the year ended December 31, 2010. 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.” We do not undertake any duty to update any forward-looking statement except as required by law.
| MarkWest Energy Partners, L.P. | ||||||||||||||||
| Financial Statistics | ||||||||||||||||
| (in thousands, except per unit data) | ||||||||||||||||
| Three months ended December 31, | Year ended December 31, | |||||||||||||||
| Statement of Operations Data | 2010 | 2009 | 2010 | 2009 | ||||||||||||
| Revenue: | ||||||||||||||||
| Revenue | $ | 356,630 | $ | 282,335 | $ | 1,241,563 | $ | 858,635 | ||||||||
| Derivative loss | (56,639 | ) | (55,179 | ) | (53,932 | ) | (120,352 | ) | ||||||||
| Total revenue | 299,991 | 227,156 | 1,187,631 | 738,283 | ||||||||||||
| Operating expenses: | ||||||||||||||||
| Purchased product costs | 169,508 | 134,774 | 578,627 | 408,826 | ||||||||||||
| Derivative loss related to purchased product costs | 2,720 | 28,929 | 27,713 | 68,883 | ||||||||||||
| Facility expenses | 38,183 | 33,032 | 151,449 | 126,977 | ||||||||||||
| Derivative gain related to facility expenses | (859 | ) | (495 | ) | (1,295 | ) | (373 | ) | ||||||||
| Selling, general and administrative expenses | 20,194 | 17,463 | 75,258 | 63,728 | ||||||||||||
| Depreciation | 33,831 | 25,916 | 123,198 | 95,537 | ||||||||||||
| Amortization of intangible assets | 10,254 | 10,193 | 40,833 | 40,831 | ||||||||||||
| Loss on disposal of property, plant and equipment | 1,033 | 245 | 3,149 | 1,677 | ||||||||||||
| Accretion of asset retirement obligations | (45 | ) | 51 | 237 | 198 | |||||||||||
| Impairment of long-lived assets | - | - | - | 5,855 | ||||||||||||
| Total operating expenses | 274,819 | 250,108 | 999,169 | 812,139 | ||||||||||||
| Income (loss) from operations | 25,172 | (22,952 | ) | 188,462 | (73,856 | ) | ||||||||||
| Other income (expense): | ||||||||||||||||
| Earnings from unconsolidated affiliates | 45 | 2,245 | 1,562 | 3,505 | ||||||||||||
| Gain on sale of unconsolidated affiliate | - | 6,801 | - | 6,801 | ||||||||||||
| Interest income | 485 | 148 | 1,670 | 349 | ||||||||||||
| Interest expense | (27,903 | ) | (23,455 | ) | (103,873 | ) | (87,419 | ) | ||||||||
| Amortization of deferred financing costs and discount (a component of interest expense) | (1,747 | ) | (3,190 | ) | (10,264 | ) | (9,718 | ) | ||||||||
| Derivative gain related to interest expense | - | 244 | 1,871 | 2,509 | ||||||||||||
| Loss on redemption of debt | (46,326 | ) | - | (46,326 | ) | - | ||||||||||
| Miscellaneous income (expense), net | 60 | (87 | ) | 1,189 | 2,459 | |||||||||||
| (Loss) income before provision for income tax | (50,214 | ) | (40,246 | ) | 34,291 | (155,370 | ) | |||||||||
| Provision for income tax (benefit) expense: | ||||||||||||||||
| Current | (2,599 | ) | 1,542 | 7,655 | 8,072 | |||||||||||
| Deferred | (4,421 | ) | (15,395 | ) | (4,466 | ) | (50,088 | ) | ||||||||
| Total provision for income tax | (7,020 | ) | (13,853 | ) | 3,189 | (42,016 | ) | |||||||||
| Net (loss) income | (43,194 | ) | (26,393 | ) | 31,102 | (113,354 | ) | |||||||||
| Net income attributable to non-controlling interest | (10,915 | ) | (3,400 | ) | (30,635 | ) | (5,314 | ) | ||||||||
| Net (loss) income attributable to the Partnership | $ | (54,109 | ) | $ | (29,793 | ) | $ | 467 | $ | (118,668 | ) | |||||
| Net loss attributable to the Partnership's common unitholders per common unit: | ||||||||||||||||
| Basic | $ | (0.76 | ) | $ | (0.45 | ) | $ | (0.01 | ) | $ | (1.97 | ) | ||||
| Diluted | $ | (0.76 | ) | $ | (0.45 | ) | $ | (0.01 | ) | $ | (1.97 | ) | ||||
| Weighted average number of outstanding common units: | ||||||||||||||||
| Basic | 71,440 | 66,266 | 70,128 | 60,957 | ||||||||||||
| Diluted | 71,440 | 66,266 | 70,128 | 60,957 | ||||||||||||
| Cash Flow Data | ||||||||||||||||
| Net cash flow provided by (used in): | ||||||||||||||||
| Operating activities | $ | 115,090 | $ | 75,236 | $ | 312,328 | $ | 223,101 | ||||||||
| Investing activities | $ | (112,287 | ) | $ | (57,066 | ) | $ | (485,936 | ) | $ | (461,753 | ) | ||||
| Financing activities | $ | (33,848 | ) | $ | 14,276 | $ | 143,306 | $ | 333,083 | |||||||
| Other Financial Data | ||||||||||||||||
| Distributable cash flow | $ | 69,138 | $ | 63,202 | $ | 241,080 | $ | 192,398 | ||||||||
| Adjusted EBITDA | $ | 88,233 | $ | 76,933 | $ | 333,115 | $ | 279,183 | ||||||||
| Balance Sheet Data | December 31, 2010 | December 31, 2009 | ||||||||||||||
| Working capital | $ | (43,296 | ) | $ | 13,536 | |||||||||||
| Total assets | 3,333,362 | 3,014,737 | ||||||||||||||
| Total debt | 1,273,434 | 1,170,072 | ||||||||||||||
| Total equity | 1,536,020 | 1,379,393 | ||||||||||||||
| MarkWest Energy Partners, L.P. | ||||||||
| Operating Statistics | ||||||||
| Three months ended December 31, | Year ended December 31, | |||||||
| 2010 | 2009 | 2010 | 2009 | |||||
| Southwest | ||||||||
| East Texas | ||||||||
| Gathering systems throughput (Mcf/d) | 420,600 | 447,500 | 430,300 | 454,400 | ||||
| NGL product sales (gallons) | 59,493,800 | 65,727,900 | 245,781,200 | 245,787,000 | ||||
| Oklahoma | ||||||||
| Foss Lake gathering system throughput (Mcf/d) | 69,300 | 78,500 | 71,100 | 86,600 | ||||
| Stiles Ranch gathering system throughput (Mcf/d) | 119,900 | 85,200 | 112,300 | 89,300 | ||||
| Grimes gathering system throughput (Mcf/d) | 7,400 | 8,600 | 7,700 | 9,700 | ||||
| Arapaho NGL product sales (gallons) | 40,759,200 | 34,016,500 | 134,118,600 | 126,870,500 | ||||
| Southeast Oklahoma gathering system throughput (Mcf/d) | 513,600 | 456,100 | 521,400 | 416,800 | ||||
| Arkoma Connector Pipeline throughput (Mcf/d) (1) | 367,200 | 318,300 | 375,900 | 277,300 | ||||
| Other Southwest | ||||||||
| Appleby gathering system throughput (Mcf/d) | 30,500 | 38,400 | 31,600 | 47,300 | ||||
| Other gathering systems throughput (Mcf/d) (2) | 6,800 | 9,300 | 7,900 | 10,300 | ||||
| Northeast | ||||||||
| Appalachia | ||||||||
| Natural gas processed (Mcf/d) (3) | 172,100 | 185,700 | 188,700 | 194,600 | ||||
| Keep-whole sales (gallons) | 31,382,700 | 41,111,800 | 136,711,200 | 145,493,100 | ||||
| Percent-of-proceeds sales (gallons) | 32,368,400 | 29,988,000 | 120,255,100 | 99,910,200 | ||||
| Total NGL product sales (gallons) (4) | 63,751,100 | 71,099,800 | 256,966,300 | 245,403,300 | ||||
| Michigan | ||||||||
| Crude oil transported for a fee (Bbl/d) | 14,100 | 11,900 | 12,800 | 12,300 | ||||
| Liberty | ||||||||
| Natural gas processed (Mcf/d) | 239,000 | 77,200 | 215,700 | 51,800 | ||||
| Gathering system throughput (Mcf/d) | 185,000 | 80,500 | 142,200 | 53,500 | ||||
| NGL product sales (gallons) | 42,549,100 | 15,413,800 | 119,921,400 | 34,409,000 | ||||
| Gulf Coast | ||||||||
| Javelina | ||||||||
| Refinery off-gas processed (Mcf/d) | 119,200 | 123,700 | 118,600 | 120,200 | ||||
| Liquids fractionated (Bbl/d) | 21,700 | 23,200 | 22,500 | 23,200 | ||||
| (1) | The Arkoma Connector Pipeline was placed into service in July 2009. The volume reported for 2009 is the average daily rate for the days of operation. | |
| (2) | Excludes lateral pipelines where revenue is not based on throughput. | |
| (3) | Includes throughput from the Kenova, Cobb, and Boldman processing plants. | |
| (4) | Represents sales at the Siloam NGL fractionation plant. The total sales exclude 20,951,500 gallons and 10,163,200 gallons sold by the Northeast on behalf of Liberty for the three months ended December 31, 2010 and 2009, respectively, and 60,909,100 gallons and 23,285,600 gallons sold for the twelve months ended December 31, 2010 and 2009, respectively. | |
| MarkWest Energy Partners, L.P. | |||||||||||||||||
| Operating Income before Items not Allocated to Segments and Reconciliation to GAAP Financial Measure | |||||||||||||||||
| (in thousands) | |||||||||||||||||
| Three months ended December 31, 2010 | Southwest | Northeast | Liberty | Gulf Coast | Total | ||||||||||||
| Revenue | $ | 186,717 | $ | 108,154 | $ | 39,557 | $ | 22,202 | $ | 356,630 | |||||||
| Operating expenses: | |||||||||||||||||
| Purchased product costs | 88,111 | 73,127 | 8,270 | - | 169,508 | ||||||||||||
| Facility expenses | 21,229 | 4,958 | 4,907 | 9,462 | 40,556 | ||||||||||||
| Total operating expenses before items not allocated to segments | 109,340 | 78,085 | 13,177 | 9,462 | 210,064 | ||||||||||||
| Portion of operating income attributable to non-controlling interests | 1,478 | - | 10,509 | - | 11,987 | ||||||||||||
| Operating income before items not allocated to segments | $ | 75,899 | $ | 30,069 | $ | 15,871 | $ | 12,740 | $ | 134,579 | |||||||
| Three months ended December 31, 2009 | Southwest | Northeast | Liberty | Gulf Coast | Total | ||||||||||||
| Revenue | $ | 152,402 | $ | 94,764 | $ | 18,458 | $ | 16,711 | $ | 282,335 | |||||||
| Operating expenses: | |||||||||||||||||
| Purchased product costs | 70,565 | 57,786 | 6,423 | - | 134,774 | ||||||||||||
| Facility expenses | 17,918 | 5,543 | 5,711 | 3,791 | 32,963 | ||||||||||||
| Total operating expenses before items not allocated to segments | 88,483 | 63,329 | 12,134 | 3,791 | 167,737 | ||||||||||||
| Portion of operating income attributable to non-controlling interests | 1,606 | - | 2,524 | - | 4,130 | ||||||||||||
| Operating income before items not allocated to segments | $ | 62,313 | $ | 31,435 | $ | 3,800 | $ | 12,920 | $ | 110,468 | |||||||
| Three months ended December 31, | |||||||||||||||||
| 2010 | 2009 | ||||||||||||||||
|
|
|||||||||||||||||
| Operating income before items not allocated to segments | $ | 134,579 | $ | 110,468 | |||||||||||||
| Portion of operating income attributable to non-controlling interests | 11,987 | 4,130 | |||||||||||||||
| Derivative loss not allocated to segments | (58,500 | ) | (83,613 | ) | |||||||||||||
| Compensation expense included in facility expenses not allocated to segments | (478 | ) | (231 | ) | |||||||||||||
| Facility expenses adjustments | 2,851 | 162 | |||||||||||||||
| Selling, general and administrative expenses | (20,194 | ) | (17,463 | ) | |||||||||||||
| Depreciation | (33,831 | ) | (25,916 | ) | |||||||||||||
| Amortization of intangible assets | (10,254 | ) | (10,193 | ) | |||||||||||||
| Loss on disposal of property, plant and equipment | (1,033 | ) | (245 | ) | |||||||||||||
| Accretion of asset retirement obligations | 45 | (51 | ) | ||||||||||||||
|
Income (loss) from operations |
25,172 | (22,952 | ) | ||||||||||||||
| Other income (expense): | |||||||||||||||||
| Earnings from unconsolidated affiliates | 45 | 2,245 | |||||||||||||||
| Gain on sale of unconsolidated affiliate | - | 6,801 | |||||||||||||||
| Interest income | 485 | 148 | |||||||||||||||
| Interest expense | (27,903 | ) | (23,455 | ) | |||||||||||||
| Amortization of deferred financing costs and discount (a component of interest expense) | (1,747 | ) | (3,190 | ) | |||||||||||||
| Derivative gain related to interest expense | - | 244 | |||||||||||||||
| Loss on redemption of debt | (46,326 | ) | - | ||||||||||||||
| Miscellaneous income (expense), net | 60 | (87 | ) | ||||||||||||||
| Loss before provision for income tax | $ | (50,214 | ) | $ | (40,246 | ) | |||||||||||
| MarkWest Energy Partners, L.P. | |||||||||||||||||
| Operating Income before Items not Allocated to Segments and Reconciliation to GAAP Financial Measure | |||||||||||||||||
| (in thousands) | |||||||||||||||||
| Year ended December 31, 2010 | Southwest | Northeast | Liberty | Gulf Coast | Total | ||||||||||||
| Revenue | $ | 665,768 | $ | 384,724 | $ | 105,911 | $ | 85,160 | $ | 1,241,563 | |||||||
| Operating expenses: | |||||||||||||||||
| Purchased product costs | 308,960 | 252,827 | 16,840 | - | 578,627 | ||||||||||||
| Facility expenses | 81,772 | 19,513 | 24,028 | 33,337 | 158,650 | ||||||||||||
| Total operating expenses before items not allocated to segments | 390,732 | 272,340 | 40,868 | 33,337 | 737,277 | ||||||||||||
| Portion of operating income attributable to non-controlling interests | 6,440 | - | 26,126 | - | 32,566 | ||||||||||||
| Operating income before items not allocated to segments | $ | 268,596 | $ | 112,384 | $ | 38,917 | $ | 51,823 | $ | 471,720 | |||||||
| Year ended December 31, 2009 | Southwest | Northeast | Liberty | Gulf Coast | Total | ||||||||||||
| Revenue | $ | 492,369 | $ | 260,529 | $ | 47,968 | $ | 57,769 | $ | 858,635 | |||||||
| Operating expenses: | |||||||||||||||||
| Purchased product costs | 221,021 | 175,326 | 12,479 | - | 408,826 | ||||||||||||
| Facility expenses | 73,621 | 20,339 | 16,268 | 16,094 | 126,322 | ||||||||||||
| Total operating expenses before items not allocated to segments | 294,642 | 195,665 | 28,747 | 16,094 | 535,148 | ||||||||||||
| Portion of operating income attributable to non-controlling interests | 2,613 | - | 6,637 | - | 9,250 | ||||||||||||
| Operating income before items not allocated to segments | $ | 195,114 | $ | 64,864 | $ | 12,584 | $ | 41,675 | $ | 314,237 | |||||||
| Year ended December 31, | |||||||||||||||||
| 2010 | 2009 | ||||||||||||||||
| Operating income before items not allocated to segments | $ | 471,720 | $ | 314,237 | |||||||||||||
| Portion of operating income attributable to non-controlling interests | 32,566 | 9,250 | |||||||||||||||
| Derivative loss not allocated to segments | (80,350 | ) | (188,862 | ) | |||||||||||||
| Compensation expense included in facility expenses not allocated to segments | (1,890 | ) | (1,032 | ) | |||||||||||||
| Facility expenses adjustments | 9,091 | 377 | |||||||||||||||
| Selling, general and administrative expenses | (75,258 | ) | (63,728 | ) | |||||||||||||
| Depreciation | (123,198 | ) | (95,537 | ) | |||||||||||||
| Amortization of intangible assets | (40,833 | ) | (40,831 | ) | |||||||||||||
| Loss on disposal of property, plant and equipment | (3,149 | ) | (1,677 | ) | |||||||||||||
| Accretion of asset retirement obligations | (237 | ) | (198 | ) | |||||||||||||
| Impairment of long-lived assets | - | (5,855 | ) | ||||||||||||||
| Income (loss) from operations | 188,462 | (73,856 | ) | ||||||||||||||
| Other income (expense): | |||||||||||||||||
| Earnings from unconsolidated affiliates | 1,562 | 3,505 | |||||||||||||||
| Gain on sale of unconsolidated affiliate | - | 6,801 | |||||||||||||||
| Interest income | 1,670 | 349 | |||||||||||||||
| Interest expense | (103,873 | ) | (87,419 | ) | |||||||||||||
| Amortization of deferred financing costs and discount (a component of interest expense) | (10,264 | ) | (9,718 | ) | |||||||||||||
| Derivative gain related to interest expense | 1,871 | 2,509 | |||||||||||||||
| Loss on redemption of debt | (46,326 | ) | - | ||||||||||||||
| Miscellaneous income, net | 1,189 | 2,459 | |||||||||||||||
| Income (loss) before provision for income tax | $ | 34,291 | $ | (155,370 | ) | ||||||||||||
| MarkWest Energy Partners, L.P. | ||||||||||||||||
| Reconciliation of GAAP Financial Measures to Non-GAAP Financial Measures | ||||||||||||||||
| Distributable Cash Flow | ||||||||||||||||
| (in thousands) | ||||||||||||||||
| Three months ended December 31, | Year ended December 31, | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
| Net (loss) income | $ | (43,194 | ) | $ | (26,393 | ) | $ | 31,102 | $ | (113,354 | ) | |||||
| Depreciation, amortization, impairment, and other non-cash operating expenses | 45,151 | 36,483 | 167,729 | 144,410 | ||||||||||||
| Loss on redemption of debt, net of tax benefit | 42,021 | - | 42,021 |
|
- | |||||||||||
| Amortization of deferred financing costs | 1,747 | 3,190 | 10,264 | 9,718 | ||||||||||||
| Non-cash earnings from unconsolidated affiliates | (45 | ) | (2,245 | ) | (1,562 | ) | (3,505 | ) | ||||||||
| Distributions from (contributions to) unconsolidated affiliates | - | 6,030 | 2,508 |
|
(405 | ) | ||||||||||
| Gain on sale of unconsolidated affiliate | - | (6,801 | ) | - |
|
(6,801 | ) | |||||||||
| Starfish partial insurance settlement | - | (2,747 | ) | - | 546 | |||||||||||
| Non-cash compensation expense | 1,073 | 572 | 7,529 | 3,914 | ||||||||||||
| Non-cash derivative activity | 38,671 | 76,324 | 23,889 | 223,564 | ||||||||||||
| Provision for income tax - deferred | (4,421 | ) | (15,395 | ) | (4,466 | ) | (50,088 | ) | ||||||||
| Cash adjustment for non-controlling interest of consolidated subsidiaries | (11,286 | ) | (3,675 | ) | (30,603 | ) | (8,141 | ) | ||||||||
| Other | 2,138 | 47 | 2,699 | 23 | ||||||||||||
| Maintenance capital expenditures, net | (2,717 | ) | (2,188 | ) | (10,030 | ) | (7,483 | ) | ||||||||
| Distributable cash flow | $ | 69,138 | $ | 63,202 | $ | 241,080 | $ | 192,398 | ||||||||
| Maintenance capital expenditures | $ | 2,973 | $ | 2,188 | $ | 10,286 | $ | 7,483 | ||||||||
| Growth capital expenditures and equity investments | 81,522 | 89,903 | 448,382 | 479,545 | ||||||||||||
| Total capital expenditures and equity investments | $ | 84,495 | $ | 92,091 | $ | 458,668 |
|
$ | 487,028 | |||||||
| Distributable cash flow | $ | 69,138 | $ | 63,202 | $ | 241,080 | $ | 192,398 | ||||||||
| Maintenance capital expenditures, net | 2,717 | 2,188 | 10,030 | 7,483 | ||||||||||||
| Changes in receivables and other assets | 4,427 | (13,535 | ) | (28,552 | ) | (28,622 | ) | |||||||||
| Changes in accounts payable, accrued liabilities and other long-term liabilities | 20,850 | 20,310 | 45,185 |
|
38,203 | |||||||||||
| Derivative instrument premium payments, net of amortization | 1,689 | 1,515 | 3,275 | 5,666 | ||||||||||||
| Contributions to unconsolidated affiliates | - | (6,030 | ) | - |
|
405 | ||||||||||
| Cash adjustment for non-controlling interest of consolidated subsidiaries | 11,286 | 3,675 | 30,603 | 8,141 | ||||||||||||
| Starfish partial insurance settlement | - | 2,747 | - | (546 | ) | |||||||||||
| Other | 4,983 | 1,164 | 10,707 | (27 | ) | |||||||||||
| Net cash provided by operating activities | $ | 115,090 | $ | 75,236 | $ | 312,328 | $ | 223,101 | ||||||||
| MarkWest Energy Partners, L.P. | ||||||||||||||||
| Reconciliation of GAAP Financial Measures to Non-GAAP Financial Measures | ||||||||||||||||
| Adjusted EBITDA | ||||||||||||||||
| (in thousands) | ||||||||||||||||
| Three months ended December 31, | Year ended December 31, | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
| Net (loss) income | $ | (43,194 | ) | $ | (26,393 | ) | $ | 31,102 | $ | (113,354 | ) | |||||
| Non-cash compensation expense | 1,073 | 572 | 7,529 | 3,914 | ||||||||||||
| Non-cash derivative activity | 38,671 | 75,523 | 24,691 | 222,763 | ||||||||||||
| Interest expense (1) | 27,404 | 24,136 | 105,181 | 94,628 | ||||||||||||
| Depreciation, amortization, impairment, and other non-cash operating expenses | 45,151 | 36,483 | 167,729 | 144,410 | ||||||||||||
| Loss on redemption of debt | 46,326 | - | 46,326 | - | ||||||||||||
| Provision for income tax | (7,020 | ) | (13,853 | ) | 3,189 | (42,016 | ) | |||||||||
| Gain on sale of unconsolidated affiliate | - | (6,801 | ) | - | (6,801 | ) | ||||||||||
| Adjustment for cash flow from unconsolidated affiliates | (45 | ) | (1,476 | ) | 1,044 |
|
(1,758 | ) | ||||||||
| Adjustment related to non-wholly owned, consolidated subsidiaries | (19,691 | ) | (11,258 | ) | (52,322 | ) |
|
(22,603 | ) | |||||||
| Other | (442 | ) | - | (1,354 | ) | - | ||||||||||
| Adjusted EBITDA | $ | 88,233 | $ | 76,933 | $ | 333,115 | $ | 279,183 | ||||||||
|
(1) 2010 includes derivative activity related to interest expense and excludes interest expense related to the Steam Methane Reformer. |
||||||||||||||||
MarkWest Energy Partners, L.P.
Distributable Cash Flow Sensitivity Analysis
(unaudited, in millions)
MarkWest periodically estimates the effect on DCF resulting from its hedge program, changes in crude oil and natural gas prices, and the correlation of NGL prices to crude oil. The table below reflects MarkWest’s estimate of the range of DCF for 2011 at the noted crude oil prices. The analysis assumes various combinations of crude oil prices and the ratio of crude oil to gas based on three NGL correlation scenarios, including:
a. The historical average NGL correlation to crude over the past three years.
b. One standard deviation above the historical average NGL correlation to crude over the past three years.
c. One standard deviation below the historical average NGL correlation to crude over the past three years.
The analysis further assumes derivative instruments outstanding as of February 18, 2011, and production volumes estimated through December 31, 2011.
The range of stated hypothetical changes in commodity prices considers current and historic market performance. During the past 10 years, the annual average NGL correlation has ranged between one standard deviation below the historical average and one standard deviation above the historical average.
|
Estimated Range of 2011 DCF |
|||||||||||||||||||||
| Crude Oil to Gas Ratio | |||||||||||||||||||||
| Crude Oil Price | NGL Correlation | 24:1 | 22:1 | 20:1 | 18:1 | 16:1 | |||||||||||||||
| One standard deviation above historical average | $ | 396 | $ | 393 | $ | 389 | $ | 385 | $ | 379 | |||||||||||
| $110 | Historical average | $ | 333 | $ | 330 | $ | 327 | $ | 322 | $ | 316 | ||||||||||
| One standard deviation below historical average | $ | 275 | $ | 272 | $ | 269 | $ | 264 | $ | 259 | |||||||||||
| One standard deviation above historical average | $ | 371 | $ | 368 | $ | 365 | $ | 361 | $ | 355 | |||||||||||
| $100 | Historical average | $ | 316 | $ | 313 | $ | 310 | $ | 306 | $ | 301 | ||||||||||
| One standard deviation below historical average | $ | 263 | $ | 260 | $ | 257 | $ | 252 | $ | 248 | |||||||||||
| One standard deviation above historical average | $ | 346 | $ | 343 | $ | 340 | $ | 336 | $ | 332 | |||||||||||
| $90 | Historical average | $ | 298 | $ | 296 | $ | 293 | $ | 289 | $ | 284 | ||||||||||
| One standard deviation below historical average | $ | 250 | $ | 247 | $ | 244 | $ | 241 | $ | 237 | |||||||||||
| One standard deviation above historical average | $ | 320 | $ | 318 | $ | 315 | $ | 312 | $ | 308 | |||||||||||
| $80 | Historical average | $ | 278 | $ | 275 | $ | 273 | $ | 269 | $ | 265 | ||||||||||
| One standard deviation below historical average | $ | 235 | $ | 232 | $ | 230 | $ | 226 | $ | 223 | |||||||||||
| One standard deviation above historical average | $ | 299 | $ | 297 | $ | 295 | $ | 292 | $ | 288 | |||||||||||
| $70 | Historical average | $ | 261 | $ | 259 | $ | 257 | $ | 254 | $ | 251 | ||||||||||
| One standard deviation below historical average | $ | 224 | $ | 222 | $ | 219 | $ | 217 | $ | 214 | |||||||||||
The table is based on current information, expectations, and beliefs concerning future developments and their potential effects, and does not consider actions MarkWest management may take to mitigate exposure to changes. Nor does the table consider the effects that such hypothetical adverse changes may have on overall economic activity. Historical prices and correlations do not guarantee future results.
Although MarkWest believes the expectations reflected in this analysis are reasonable, MarkWest can give no assurance that such expectations will prove to be correct and readers are cautioned that projected performance, results, or distributions may not be achieved. Actual changes in market prices, and the correlation between crude oil and NGL prices, may differ from the assumptions utilized in the analysis. Actual results, performance, distributions, volumes, events, or transactions could vary significantly from those expressed, considered, or implied in this analysis. All results, performance, distributions, volumes, events, or transactions are subject to a number of uncertainties and risks. Those uncertainties and risks may not be factored into or accounted for in this analysis. Readers are urged to carefully review and consider the cautionary statements and disclosures made in MarkWest’s periodic reports filed with the SEC, specifically those under the heading “Risk Factors.”