Attached files
| file | filename |
|---|---|
| 8-K - 8-K - MARKWEST ENERGY PARTNERS L P | a12-6066_18k.htm |
Exhibit 99.1
|
MarkWest Energy Partners, L.P. |
|
Contact: |
Frank Semple, Chairman, President & CEO |
|
1515 Arapahoe Street |
|
|
Nancy Buese, Senior VP and CFO |
|
Tower 1, Suite 1600 |
|
|
Dan Campbell, VP of Finance & Treasurer |
|
Denver, Colorado 80202 |
|
Phone: |
(866) 858-0482 |
|
|
|
E-mail: |
investorrelations@markwest.com |
MarkWest Energy Partners Reports Record Fourth Quarter
and Full Year 2011 Financial Results
DENVER—February 28, 2012—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 $88.4 million for the three months ended December 31, 2011, and $332.8 million for the year ended December 31, 2011. Distributable cash flow for the three months and year ended December 31, 2011, represents distribution coverage of 121 percent and 138 percent, respectively. 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 record Adjusted EBITDA of $128.2 million for the three months ended December 31, 2011, and $451.4 million for the year ended December 31, 2011. 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, 2011, of $ (74.5) million and $119.9 million, respectively. Income before provision for income tax includes non-cash gains (losses) associated with the change in fair value of derivative instruments of $(102.4) million and $0.3 million for the three months and year ended December 31, 2011, respectively, and costs associated with the redemption of debt of $(35.5) million and $(79.0) million for the three months and year ended December 31, 2011, respectively. Excluding these items, income before provision for income tax for the three months and year ended December 31, 2011, would have been $63.4 million and $198.6 million, respectively.
“Our record distributable cash flow for the fourth quarter and full year allowed us to deliver year-over-year distribution growth of nearly 17 percent while maintaining a coverage ratio of approximately 1.4 times for the full year,” said Frank Semple, Chairman, President and Chief Executive Officer. “It was an exciting end to an extraordinary year with the completion of the Marcellus Liberty acquisition and the announcement of our Utica joint venture with The Energy and Minerals Group. We look forward to another year of continued growth and strong performance for our unitholders.”
BUSINESS HIGHLIGHTS
Capital Markets
· During the fourth quarter 2011, the Partnership completed two common unit equity offerings of 16.5 million common units, which includes the January 2012 exercise of the underwriters’ over-allotment option related to the December 2011 equity offering. The net proceeds of approximately $810 million were used to fund a portion of the acquisition of all of the interests in MarkWest Liberty Midstream & Resources, L.L.C. (MarkWest Liberty) previously held by an affiliate of The Energy & Minerals Group (EMG), to repay amounts outstanding under its revolving credit facility, and to fund its ongoing capital expenditure program.
· On November 3, 2011, the Partnership completed a public offering of $700 million aggregate principal amount of 6.25% senior unsecured notes due 2022 issued at par. The aggregate net proceeds of approximately $688 million were used to fund the repurchase of approximately $253 million in aggregate principal amount of its outstanding 8.75% senior notes due 2018. All remaining net proceeds were used to fund its ongoing capital expenditure program.
· On December 29, 2011, the Partnership executed a $150 million increase to its senior secured revolving credit facility, increasing total borrowing capacity to $900 million. The maturity date of the credit facility remains September 2016.
Business Development
· Liberty — In October 2011, MarkWest Liberty entered into definitive agreements with subsidiaries of Magnum Hunter Resources Corporation to provide long-term midstream processing and related services in the liquids-rich area of the Marcellus Shale in northern West Virginia. MarkWest Liberty will install a 200 million cubic feet per day (MMcf/d) cryogenic natural gas processing plant at its Mobley processing complex in West Virginia. When combined with the 120 MMcf/d Mobley I plant currently under construction, MarkWest Liberty expects to operate 320 MMcf/d of cryogenic processing capacity at its Mobley complex by the second half of 2012. The natural gas liquids (NGL) recovered at the Mobley complex will be transported via a newly constructed liquids pipeline to MarkWest Liberty’s fractionation, storage, and marketing complex in Houston, Pennsylvania.
· In December 2011, MarkWest announced the closing of the acquisition of the 49 percent interest in MarkWest Liberty held by an affiliate of EMG. The acquisition consideration included $994 million of cash and the issuance of approximately 19.95 million unregistered MWE Class B Units to EMG. MarkWest expects that on a DCF per unit basis, the acquisition is immediately accretive in 2012 and up to 6 percent accretive in 2013 and beyond.
· Liberty — In January 2012, MarkWest Liberty announced significant expansion projects to serve producer customers in the hydrocarbon-rich area of the Marcellus Shale, including a 400 MMcf/d expansion of its Majorsville, West Virginia processing complex, which would bring the total cryogenic processing capacity at Majorsville to 670 MMcf/d. The Majorsville expansion is expected to come online in 2013, and will be supported by long-term agreements with CONSOL Energy, Noble Energy, and Range Resources. When these expansions come online, MarkWest will operate more than 1.5 billion cubic feet per day of processing capacity in the rich-gas corridor of the Marcellus.
MarkWest Liberty is also expanding its Marcellus NGL infrastructure with the construction of new de-ethanization capacity at its Houston and Majorsville complexes and the installation of a large purity ethane pipeline between its Majorsville and Houston processing complexes. In 2011, MarkWest announced the construction of two de-ethanization facilities with the combined capacity to produce up to 75,000 barrels per day (Bbl/d) of purity ethane by mid-2013. In order to accommodate increasing liquids-rich production from its producer customers, MarkWest is
planning to construct a third de-ethanization facility that will increase production capacity of purity ethane to 115,000 Bbl/d by 2014. The first phase of ethane production capacity of 75,000 Bbl/d and the purity ethane pipeline are expected to come online in mid-2013 in conjunction with the completion of Mariner West, a pipeline project jointly developed by MarkWest and Sunoco Logistics L.P. (NYSE: SXL) to deliver Marcellus ethane to petrochemical markets in Sarnia, Ontario, Canada.
· Utica — In January 2012, MarkWest Utica EMG, L.L.C. (MarkWest Utica), a joint venture between MarkWest and EMG focused on the development of significant natural gas processing and NGL fractionation, transportation, and marketing infrastructure in the Utica shale in eastern Ohio, and MarkWest Liberty announced the first phase of their Utica Shale development plan including two new processing complexes and 100,000 Bbl/d of fractionation, storage, and marketing capacity. The initial processing and fractionation complex in Harrison County is expected to begin initial operations in mid-2013. MarkWest is finalizing the design capacity and the location of the second processing complex, which is also expected to begin operations in 2013. Both processing complexes would be connected via an NGL gathering system to the Harrison County fractionation facilities. The Harrison fractionation facilities would be connected to MarkWest’s extensive processing and NGL pipeline network in Pennsylvania and West Virginia and would provide for the integrated operation of the two largest fractionation complexes in the Northeastern United States. Under the terms of the Utica joint venture, EMG would fund a majority of the initial capital expenditures required to develop the Utica midstream infrastructure.
· Liberty — In February 2012, MarkWest Liberty agreed to expand its Sherwood processing complex by 200 MMcf/d to provide midstream processing and related services for Antero Resources in the liquids-rich area of the Marcellus Shale in northern West Virginia. When combined with the 200 MMcf/d Sherwood I plant currently under construction, MarkWest Liberty expects to operate 400 MMcf/d of cryogenic processing capacity at its Sherwood complex in 2013. The NGLs recovered at the Sherwood complex will be transported via a newly constructed liquids pipeline to MarkWest Liberty’s fractionation, storage, and marketing complex in Houston, Pennsylvania. While Antero has until July 1, 2012 to finalize its decision of whether to proceed with the additional 200 MMcf/d Sherwood II plant, Antero has publicly stated its intent to move forward with the project.
FINANCIAL RESULTS
Balance Sheet
· At December 31, 2011, the Partnership had $113.7 million of cash and cash equivalents in wholly owned subsidiaries and $814.7 million available for borrowing under its $900 million revolving credit facility after consideration of $66.0 million of borrowings outstanding and $19.3 million of outstanding letters of credit.
Operating Results
· Operating income before items not allocated to segments for the three months ended December 31, 2011, was $171.0 million, an increase of $36.4 million when compared to $134.6 million for the same period in 2010. This increase is primarily attributable to favorable commodity prices compared to the prior quarter in all of our segments, expanding operations in the Liberty segment, and increased volumes in the Southwest segment.
A reconciliation of operating income before items not allocated to segments to income (loss) 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 gain (loss) on commodity derivative instruments. Realized losses on commodity derivative instruments were $(20.0) million in the fourth quarter of 2011 compared to realized losses of $(19.8) million in the fourth quarter of 2010.
· In the fourth quarter of 2011, the Partnership recorded a charge of $35.5 million related to the redemption of a portion of its $500 million of senior notes due 2018. Approximately $3.8 million related to a non-cash write off of the unamortized discount and deferred finance costs and approximately $31.7 million related to the premium and consent fees associated with redeeming the 2018 senior notes. The effect of this refinancing was to extend the maturity of this portion of the Partnership’s long-term debt until 2022 and to reduce the Partnership’s cost of debt capital.
Capital Expenditures
· For the three months and year ended December 31, 2011, the Partnership’s portion of capital expenditures was $130.2 million and $652.4 million, respectively. Capital expenditures for the year ended December 31, 2011, include the $230.7 million acquisition of EQT’s Langley processing complex and the partially completed Ranger NGL pipeline.
2012 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST
For 2012, the Partnership forecasts DCF in a range of $440 million to $500 million based on the acquisition of the remaining 49% interest in Liberty; forecasted operational volumes from existing operations and growth capital projects; derivative instruments currently outstanding; a reasonable range of price estimates for crude oil and natural gas; and no acquisitions. The contribution to the Partnership’s 2012 forecasted DCF from the acquisition of the 49 percent interest in MarkWest Liberty remains unchanged from its December 2011 guidance. The midpoint of this range results in approximately 161 percent coverage of the Partnership’s full-year distribution based on current quarterly distributions and common units outstanding. A sensitivity analysis for forecasted 2012 DCF is provided within the tables of this press release.
The Partnership’s portion of growth capital expenditures for 2012 is forecasted in a range of $900 million to $1.3 billion and maintenance capital for 2012 is forecasted at approximately $20 million.
CONFERENCE CALL
The Partnership will host a conference call and webcast on Wednesday, February 29, 2012, at 4:00 p.m. Eastern Time to review its fourth quarter 2011 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 (866) 453-2338 (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, 2011. 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)
|
|
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Three months ended December 31, |
|
Year ended December 31, |
| ||||||||
|
|
|
2011 |
|
2010 |
|
2011 |
|
2010 |
| ||||
|
Statement of Operations Data |
|
|
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|
|
|
| ||||
|
Revenue: |
|
|
|
|
|
|
|
|
| ||||
|
Revenue |
|
$ |
424,802 |
|
$ |
356,630 |
|
$ |
1,534,434 |
|
$ |
1,241,563 |
|
|
Derivative loss |
|
(90,889 |
) |
(56,639 |
) |
(29,035 |
) |
(53,932 |
) | ||||
|
Total revenue |
|
333,913 |
|
299,991 |
|
1,505,399 |
|
1,187,631 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Operating expenses: |
|
|
|
|
|
|
|
|
| ||||
|
Purchased product costs |
|
184,877 |
|
169,508 |
|
682,370 |
|
578,627 |
| ||||
|
Derivative loss related to purchased product costs |
|
35,094 |
|
2,720 |
|
52,960 |
|
27,713 |
| ||||
|
Facility expenses |
|
49,240 |
|
38,183 |
|
173,598 |
|
151,449 |
| ||||
|
Derivative gain related to facility expenses |
|
(3,609 |
) |
(859 |
) |
(6,480 |
) |
(1,295 |
) | ||||
|
Selling, general and administrative expenses |
|
20,775 |
|
20,194 |
|
81,229 |
|
75,258 |
| ||||
|
Depreciation |
|
39,674 |
|
33,831 |
|
149,954 |
|
123,198 |
| ||||
|
Amortization of intangible assets |
|
10,985 |
|
10,254 |
|
43,617 |
|
40,833 |
| ||||
|
Loss on disposal of property, plant and equipment |
|
4,178 |
|
1,033 |
|
8,797 |
|
3,149 |
| ||||
|
Accretion of asset retirement obligations |
|
256 |
|
(45 |
) |
1,190 |
|
237 |
| ||||
|
Total operating expenses |
|
341,470 |
|
274,819 |
|
1,187,235 |
|
999,169 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
(Loss) income from operations |
|
(7,557 |
) |
25,172 |
|
318,164 |
|
188,462 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Other income (expense): |
|
|
|
|
|
|
|
|
| ||||
|
Earnings (loss) from unconsolidated affiliates |
|
167 |
|
45 |
|
(1,095 |
) |
1,562 |
| ||||
|
Interest income |
|
208 |
|
485 |
|
422 |
|
1,670 |
| ||||
|
Interest expense |
|
(30,595 |
) |
(27,903 |
) |
(113,631 |
) |
(103,873 |
) | ||||
|
Amortization of deferred financing costs and discount (a component of interest expense) |
|
(1,241 |
) |
(1,747 |
) |
(5,114 |
) |
(10,264 |
) | ||||
|
Derivative gain related to interest expense |
|
— |
|
— |
|
— |
|
1,871 |
| ||||
|
Loss on redemption of debt |
|
(35,535 |
) |
(46,326 |
) |
(78,996 |
) |
(46,326 |
) | ||||
|
Miscellaneous income, net |
|
17 |
|
60 |
|
144 |
|
1,189 |
| ||||
|
(Loss) income before provision for income tax |
|
(74,536 |
) |
(50,214 |
) |
119,894 |
|
34,291 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Provision for income tax expense (benefit): |
|
|
|
|
|
|
|
|
| ||||
|
Current |
|
9,474 |
|
(2,599 |
) |
17,578 |
|
7,655 |
| ||||
|
Deferred |
|
(22,267 |
) |
(4,421 |
) |
(3,929 |
) |
(4,466 |
) | ||||
|
Total provision for income tax |
|
(12,793 |
) |
(7,020 |
) |
13,649 |
|
3,189 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Net (loss) income |
|
(61,743 |
) |
(43,194 |
) |
106,245 |
|
31,102 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Net income attributable to non-controlling interest |
|
(12,342 |
) |
(10,915 |
) |
(45,550 |
) |
(30,635 |
) | ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Net (loss) income attributable to the Partnership |
|
$ |
(74,085 |
) |
$ |
(54,109 |
) |
$ |
60,695 |
|
$ |
467 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
Net income (loss) attributable to the Partnership’s common unitholders per common unit: |
|
|
|
|
|
|
|
|
| ||||
|
Basic |
|
$ |
(0.87 |
) |
$ |
(0.76 |
) |
$ |
0.75 |
|
$ |
(0.01 |
) |
|
Diluted |
|
$ |
(0.87 |
) |
$ |
(0.76 |
) |
$ |
0.75 |
|
$ |
(0.01 |
) |
|
|
|
|
|
|
|
|
|
|
| ||||
|
Weighted average number of outstanding common units: |
|
|
|
|
|
|
|
|
| ||||
|
Basic |
|
85,431 |
|
71,440 |
|
78,466 |
|
70,128 |
| ||||
|
Diluted |
|
85,431 |
|
71,440 |
|
78,619 |
|
70,128 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Cash Flow Data |
|
|
|
|
|
|
|
|
| ||||
|
Net cash flow provided by (used in): |
|
|
|
|
|
|
|
|
| ||||
|
Operating activities |
|
$ |
83,449 |
|
$ |
115,090 |
|
$ |
414,698 |
|
$ |
312,328 |
|
|
Investing activities |
|
$ |
(188,867 |
) |
$ |
(112,287 |
) |
$ |
(776,553 |
) |
$ |
(485,936 |
) |
|
Financing activities |
|
$ |
63,257 |
|
$ |
(33,848 |
) |
$ |
411,421 |
|
$ |
143,306 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
Other Financial Data |
|
|
|
|
|
|
|
|
| ||||
|
Distributable cash flow |
|
$ |
88,405 |
|
$ |
69,138 |
|
$ |
332,796 |
|
$ |
241,080 |
|
|
Adjusted EBITDA |
|
$ |
128,167 |
|
$ |
88,233 |
|
$ |
451,371 |
|
$ |
333,115 |
|
|
|
|
December 31, 2011 |
|
December 31, 2010 |
|
|
|
|
| ||
|
Balance Sheet Data |
|
|
|
|
|
|
|
|
| ||
|
Working capital |
|
$ |
4,234 |
|
$ |
(43,296 |
) |
|
|
|
|
|
Total assets |
|
4,070,425 |
|
3,333,362 |
|
|
|
|
| ||
|
Total debt |
|
1,846,062 |
|
1,273,434 |
|
|
|
|
| ||
|
Total equity |
|
1,502,067 |
|
1,458,566 |
|
|
|
|
| ||
MarkWest Energy Partners, L.P.
Operating Statistics
|
|
|
Three months ended December 31, |
|
Year ended December 31, |
| ||||
|
|
|
2011 |
|
2010 |
|
2011 |
|
2010 |
|
|
Southwest |
|
|
|
|
|
|
|
|
|
|
East Texas gathering systems throughput (Mcf/d) |
|
423,100 |
|
420,600 |
|
423,600 |
|
430,300 |
|
|
East Texas natural gas processed (Mcf/d) |
|
235,100 |
|
221,600 |
|
228,300 |
|
233,100 |
|
|
East Texas NGL sales (gallons, in thousands) |
|
63,500 |
|
59,500 |
|
238,700 |
|
245,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Western Oklahoma gathering system throughput (Mcf/d) (1) |
|
277,500 |
|
196,600 |
|
237,900 |
|
191,100 |
|
|
Western Oklahoma natural gas processed (Mcf/d) |
|
231,700 |
|
149,900 |
|
175,500 |
|
134,700 |
|
|
Western Oklahoma NGL sales (gallons, in thousands) |
|
66,100 |
|
40,800 |
|
177,200 |
|
134,100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Southeast Oklahoma gathering system throughput (Mcf/d) |
|
524,800 |
|
513,600 |
|
511,900 |
|
521,400 |
|
|
Southeast Oklahoma natural gas processed (Mcf/d) (2) |
|
104,200 |
|
89,500 |
|
103,400 |
|
81,600 |
|
|
Southeast Oklahoma NGL sales (gallons, in thousands) |
|
33,000 |
|
30,000 |
|
125,100 |
|
102,300 |
|
|
Arkoma Connector Pipeline throughput (Mcf/d) |
|
346,000 |
|
367,200 |
|
307,300 |
|
375,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Southwest gathering system throughput (Mcf/d) (3) |
|
25,100 |
|
37,300 |
|
29,900 |
|
39,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast (4) |
|
|
|
|
|
|
|
|
|
|
Natural gas processed (Mcf/d) |
|
320,300 |
|
172,100 |
|
305,900 |
|
188,700 |
|
|
NGLs fractionated (Bbl/d) (5) |
|
17,200 |
|
21,600 |
|
20,300 |
|
20,700 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Keep-whole sales (gallons, in thousands) |
|
31,100 |
|
31,400 |
|
113,800 |
|
136,700 |
|
|
Percent-of-proceeds sales (gallons, in thousands) |
|
34,700 |
|
32,400 |
|
130,300 |
|
120,300 |
|
|
Total NGL sales (gallons, in thousands) (6) |
|
65,800 |
|
63,800 |
|
244,100 |
|
257,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil transported for a fee (Bbl/d) |
|
9,700 |
|
14,100 |
|
10,300 |
|
12,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Liberty |
|
|
|
|
|
|
|
|
|
|
Natural gas processed (Mcf/d) |
|
374,800 |
|
239,000 |
|
323,900 |
|
215,700 |
|
|
Gathering system throughput (Mcf/d) |
|
295,600 |
|
185,000 |
|
245,700 |
|
142,200 |
|
|
NGLs fractionated (Bbl/d) (7) |
|
19,200 |
|
6,300 |
|
11,800 |
|
4,200 |
|
|
NGL sales (gallons, in thousands) (8) |
|
77,700 |
|
42,500 |
|
241,200 |
|
119,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast |
|
|
|
|
|
|
|
|
|
|
Refinery off-gas processed (Mcf/d) |
|
113,700 |
|
119,200 |
|
113,300 |
|
118,600 |
|
|
Liquids fractionated (Bbl/d) |
|
20,800 |
|
21,700 |
|
21,200 |
|
22,500 |
|
|
NGL sales (gallons excluding hydrogen, in thousands) |
|
80,200 |
|
83,800 |
|
325,700 |
|
345,500 |
|
|
(1) |
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. |
|
(2) |
The natural gas processing in Southeast Oklahoma is outsourced to Centrahoma, our equity investment, or other third-party processors. |
|
(3) |
Excludes lateral pipelines where revenue is not based on throughput. |
|
(4) |
Includes throughput from the Kenova, Cobb, Boldman, and Langley processing plants. We acquired the Langley processing plant in February 2011. The volumes reported are the average daily rates for the days of operation. |
|
(5) |
Amount includes 200 and 5,400 barrels per day fractionated on behalf of Liberty for the three months ended December 31, 2011, and 2010, respectively and 3,900 barrels per day, and 4,000 barrels per day fractionated for the twelve months ended December, 31 2011, and 2010, respectively. Beginning in the fourth quarter of 2011, Siloam no longer fractionates NGLs on behalf of Liberty due to the operation of Liberty’s fractionation facility that began in September 2011. |
|
(6) |
Represents sales at the Siloam fractionator. The total sales exclude approximately 600,000 and 21,000,000 gallons, sold by the Northeast on behalf of Liberty for three months ended December, 31, 2011 and 2010, respectively, and 59,200,000 gallons, and 60,900,000 gallons, sold for the twelve months ended December 31, 2011 and 2010, respectively. These volumes are included as part of NGLs sold at Liberty. |
|
(7) |
Amount includes all NGLs that were produced at the Liberty processing facilities and fractionated into purity products at our Liberty fractionation facility. Through August 2011, only propane was recovered at our Liberty facilities. In September 2011, Liberty’s fractionation facility commenced operations and Liberty now has full fractionation capabilities. |
|
(8) |
Includes sale of all purity products fractionated at the Liberty facilities and sale of all unfractionated NGLs. Also includes the sale of purity products fractionated and sold at the Siloam facilities on behalf of Liberty. |
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Operating Income before Items not Allocated to Segments
(in thousands)
|
Three months ended December 31, 2011 |
|
Southwest |
|
Northeast |
|
Liberty |
|
Gulf Coast |
|
Total |
| |||||
|
Revenue |
|
$ |
256,166 |
|
$ |
67,197 |
|
$ |
80,807 |
|
$ |
23,163 |
|
$ |
427,333 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
| |||||
|
Purchased product costs |
|
133,660 |
|
19,085 |
|
32,132 |
|
— |
|
184,877 |
| |||||
|
Facility expenses |
|
20,706 |
|
7,724 |
|
12,038 |
|
11,336 |
|
51,804 |
| |||||
|
Total operating expenses before items not allocated to segments |
|
154,366 |
|
26,809 |
|
44,170 |
|
11,336 |
|
236,681 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
Portion of operating income attributable to non-controlling interests |
|
1,686 |
|
— |
|
17,949 |
|
— |
|
19,635 |
| |||||
|
Operating income before items not allocated to segments |
|
$ |
100,114 |
|
$ |
40,388 |
|
$ |
18,688 |
|
$ |
11,827 |
|
$ |
171,017 |
|
|
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, |
|
|
|
|
|
|
| ||||
|
|
|
2011 |
|
2010 |
|
|
|
|
|
|
| ||
|
Operating income before items not allocated to segments |
|
$ |
171,017 |
|
$ |
134,579 |
|
|
|
|
|
|
|
|
Portion of operating income attributable to non-controlling interests |
|
19,635 |
|
11,987 |
|
|
|
|
|
|
| ||
|
Derivative loss not allocated to segments |
|
(122,374 |
) |
(58,500 |
) |
|
|
|
|
|
| ||
|
Revenue deferral adjustment |
|
(2,531 |
) |
— |
|
|
|
|
|
|
| ||
|
Compensation expense included in facility expenses not allocated to segments |
|
(290 |
) |
(478 |
) |
|
|
|
|
|
| ||
|
Facility expenses adjustments |
|
2,854 |
|
2,851 |
|
|
|
|
|
|
| ||
|
Selling, general and administrative expenses |
|
(20,775 |
) |
(20,194 |
) |
|
|
|
|
|
| ||
|
Depreciation |
|
(39,674 |
) |
(33,831 |
) |
|
|
|
|
|
| ||
|
Amortization of intangible assets |
|
(10,985 |
) |
(10,254 |
) |
|
|
|
|
|
| ||
|
Loss on disposal of property, plant and equipment |
|
(4,178 |
) |
(1,033 |
) |
|
|
|
|
|
| ||
|
Accretion of asset retirement obligations |
|
(256 |
) |
45 |
|
|
|
|
|
|
| ||
|
(Loss) income from operations |
|
(7,557 |
) |
25,172 |
|
|
|
|
|
|
| ||
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
| ||
|
Earnings from unconsolidated affiliates |
|
167 |
|
45 |
|
|
|
|
|
|
| ||
|
Interest income |
|
208 |
|
485 |
|
|
|
|
|
|
| ||
|
Interest expense |
|
(30,595 |
) |
(27,903 |
) |
|
|
|
|
|
| ||
|
Amortization of deferred financing costs and discount (a component of interest expense) |
|
(1,241 |
) |
(1,747 |
) |
|
|
|
|
|
| ||
|
Loss on redemption of debt |
|
(35,535 |
) |
(46,326 |
) |
|
|
|
|
|
| ||
|
Miscellaneous income, net |
|
17 |
|
60 |
|
|
|
|
|
|
| ||
|
Loss before provision for income tax |
|
$ |
(74,536 |
) |
$ |
(50,214 |
) |
|
|
|
|
|
|
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Operating Income before Items not Allocated to Segments
(in thousands)
|
Year ended December 31, 2011 |
|
Southwest |
|
Northeast |
|
Liberty |
|
Gulf Coast |
|
Total |
| |||||
|
Revenue |
|
$ |
935,513 |
|
$ |
268,884 |
|
$ |
248,949 |
|
$ |
96,473 |
|
$ |
1,549,819 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
| |||||
|
Purchased product costs |
|
506,911 |
|
91,612 |
|
83,847 |
|
— |
|
682,370 |
| |||||
|
Facility expenses |
|
82,761 |
|
27,126 |
|
34,913 |
|
38,436 |
|
183,236 |
| |||||
|
Total operating expenses before items not allocated to segments |
|
589,672 |
|
118,738 |
|
118,760 |
|
38,436 |
|
865,606 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
Portion of operating income attributable to non-controlling interests |
|
5,431 |
|
— |
|
63,731 |
|
— |
|
69,162 |
| |||||
|
Operating income before items not allocated to segments |
|
$ |
340,410 |
|
$ |
150,146 |
|
$ |
66,458 |
|
$ |
58,037 |
|
$ |
615,051 |
|
|
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 |
|
|
|
|
Twelve months ended December 31, |
| ||||
|
|
|
2011 |
|
2010 |
| ||
|
|
|
|
|
|
|
|
|
|
Operating income before items not allocated to segments |
|
$ |
615,051 |
|
$ |
471,720 |
|
|
Portion of operating income attributable to non-controlling interests |
|
69,162 |
|
32,566 |
| ||
|
Derivative loss not allocated to segments |
|
(75,515 |
) |
(80,350 |
) | ||
|
Revenue deferral adjustment |
|
(15,385 |
) |
— |
| ||
|
Compensation expense included in facility expenses not allocated to segments |
|
(1,781 |
) |
(1,890 |
) | ||
|
Facility expenses adjustments |
|
11,419 |
|
9,091 |
| ||
|
Selling, general and administrative expenses |
|
(81,229 |
) |
(75,258 |
) | ||
|
Depreciation |
|
(149,954 |
) |
(123,198 |
) | ||
|
Amortization of intangible assets |
|
(43,617 |
) |
(40,833 |
) | ||
|
Loss on disposal of property, plant and equipment |
|
(8,797 |
) |
(3,149 |
) | ||
|
Accretion of asset retirement obligations |
|
(1,190 |
) |
(237 |
) | ||
|
Income from operations |
|
318,164 |
|
188,462 |
| ||
|
Other income (expense): |
|
|
|
|
| ||
|
(Loss) earnings from unconsolidated affiliates |
|
(1,095 |
) |
1,562 |
| ||
|
Interest income |
|
422 |
|
1,670 |
| ||
|
Interest expense |
|
(113,631 |
) |
(103,873 |
) | ||
|
Amortization of deferred financing costs and discount (a component of interest expense) |
|
(5,114 |
) |
(10,264 |
) | ||
|
Derivative gain related to interest expense |
|
— |
|
1,871 |
| ||
|
Loss on redemption of debt |
|
(78,996 |
) |
(46,326 |
) | ||
|
Miscellaneous income, net |
|
144 |
|
1,189 |
| ||
|
Income before provision for income tax |
|
$ |
119,894 |
|
$ |
34,291 |
|
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Distributable Cash Flow
(in thousands)
|
|
|
Three months ended December 31, |
|
Year ended December 31, |
| ||||||||
|
|
|
2011 |
|
2010 |
|
2011 |
|
2010 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Net (loss) income |
|
$ |
(61,743 |
) |
$ |
(43,194 |
) |
$ |
106,245 |
|
$ |
31,102 |
|
|
Depreciation, amortization, impairment, and other non-cash operating expenses |
|
55,171 |
|
45,151 |
|
203,870 |
|
167,729 |
| ||||
|
Loss on redemption of debt, net of tax benefit |
|
32,446 |
|
42,021 |
|
72,064 |
|
42,021 |
| ||||
|
Amortization of deferred financing costs and discount |
|
1,241 |
|
1,747 |
|
5,114 |
|
10,264 |
| ||||
|
Non-cash (earnings) loss from unconsolidated affiliate |
|
(167 |
) |
(45 |
) |
1,095 |
|
(1,562 |
) | ||||
|
(Contributions to) distributions from unconsolidated affiliate |
|
(560 |
) |
— |
|
(260 |
) |
2,508 |
| ||||
|
Non-cash compensation expense |
|
(308 |
) |
1,073 |
|
3,399 |
|
7,529 |
| ||||
|
Non-cash derivative activity |
|
102,391 |
|
38,671 |
|
(290 |
) |
23,889 |
| ||||
|
Provision for income tax - deferred |
|
(22,267 |
) |
(4,421 |
) |
(3,929 |
) |
(4,466 |
) | ||||
|
Cash adjustment for non-controlling interest of consolidated subsidiaries |
|
(18,185 |
) |
(11,286 |
) |
(64,470 |
) |
(30,603 |
) | ||||
|
Revenue deferral adjustment |
|
2,531 |
|
— |
|
15,385 |
|
— |
| ||||
|
Other |
|
4,634 |
|
2,138 |
|
9,171 |
|
2,699 |
| ||||
|
Maintenance capital expenditures, net of joint venture partner contributions |
|
(6,779 |
) |
(2,717 |
) |
(14,598 |
) |
(10,030 |
) | ||||
|
Distributable cash flow |
|
$ |
88,405 |
|
$ |
69,138 |
|
$ |
332,796 |
|
$ |
241,080 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
Maintenance capital expenditures |
|
$ |
7,490 |
|
$ |
2,973 |
|
$ |
16,067 |
|
$ |
10,286 |
|
|
Growth capital expenditures |
|
183,865 |
|
81,522 |
|
535,214 |
|
448,382 |
| ||||
|
Total capital expenditures |
|
191,355 |
|
84,495 |
|
551,281 |
|
458,668 |
| ||||
|
Acquisition |
|
— |
|
— |
|
230,728 |
|
— |
| ||||
|
Total capital expenditures and acquisition |
|
191,355 |
|
84,495 |
|
782,009 |
|
458,668 |
| ||||
|
Joint venture partner contributions |
|
(61,115 |
) |
(25,836 |
) |
(129,616 |
) |
(183,853 |
) | ||||
|
Total capital expenditures and acquisition, net |
|
$ |
130,240 |
|
$ |
58,659 |
|
$ |
652,393 |
|
$ |
274,815 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
Distributable cash flow |
|
$ |
88,405 |
|
$ |
69,138 |
|
$ |
332,796 |
|
$ |
241,080 |
|
|
Maintenance capital expenditures, net |
|
6,779 |
|
2,717 |
|
14,598 |
|
10,030 |
| ||||
|
Changes in receivables and other assets |
|
(32,268 |
) |
4,427 |
|
(65,523 |
) |
(28,552 |
) | ||||
|
Changes in accounts payable, accrued liabilities and other long-term liabilities |
|
466 |
|
20,850 |
|
69,838 |
|
45,185 |
| ||||
|
Derivative instrument premium payments, net of amortization |
|
1,155 |
|
1,689 |
|
4,436 |
|
3,275 |
| ||||
|
Cash adjustment for non-controlling interest of consolidated subsidiaries |
|
18,185 |
|
11,286 |
|
64,470 |
|
30,603 |
| ||||
|
Other |
|
727 |
|
4,983 |
|
(5,917 |
) |
10,707 |
| ||||
|
Net cash provided by operating activities |
|
$ |
83,449 |
|
$ |
115,090 |
|
$ |
414,698 |
|
$ |
312,328 |
|
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Adjusted EBITDA
(in thousands)
|
|
|
Three months ended December 31, |
|
Year ended December 31, |
| ||||||||
|
|
|
2011 |
|
2010 |
|
2011 |
|
2010 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Net (loss) income |
|
$ |
(61,743 |
) |
$ |
(43,194 |
) |
$ |
106,245 |
|
$ |
31,102 |
|
|
Non-cash compensation expense |
|
(308 |
) |
1,073 |
|
3,399 |
|
7,529 |
| ||||
|
Non-cash derivative activity |
|
102,391 |
|
38,671 |
|
(290 |
) |
24,691 |
| ||||
|
Interest expense (1) |
|
29,634 |
|
27,404 |
|
109,869 |
|
105,181 |
| ||||
|
Depreciation, amortization, impairment, and other non-cash operating expenses |
|
55,171 |
|
45,151 |
|
203,870 |
|
167,729 |
| ||||
|
Loss on redemption of debt |
|
35,535 |
|
46,326 |
|
78,996 |
|
46,326 |
| ||||
|
Provision for income tax |
|
(12,793 |
) |
(7,020 |
) |
13,649 |
|
3,189 |
| ||||
|
Adjustment for cash flow from unconsolidated affiliate |
|
(167 |
) |
(45 |
) |
1,395 |
|
1,044 |
| ||||
|
Adjustment related to non-guarantor, consolidated subsidiaries (2) |
|
(19,068 |
) |
(19,691 |
) |
(63,887 |
) |
(52,322 |
) | ||||
|
Other |
|
(485 |
) |
(442 |
) |
(1,875 |
) |
(1,354 |
) | ||||
|
Adjusted EBITDA |
|
$ |
128,167 |
|
$ |
88,233 |
|
$ |
451,371 |
|
$ |
333,115 |
|
(1) Includes derivative activity related to interest expense, amortization of deferred financing costs and discount, and excludes interest expense related to the Steam Methane Reformer.
(2) The non-guarantor subsidiaries, in accordance with Credit Facility covenants, are MarkWest Liberty Midstream & Resources, L.L.C. (Liberty), MarkWest Utica EMG L.L.C., MarkWest Pioneer, L.L.C., Wirth Gathering Partnership, and Bright Star Partnership. As of Janaury 1, 2012, Liberty is a wholly owned subsidiary but remains a non-guarantor in accordance with the Credit Facility.
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 correlation of NGL prices to crude oil. The table below reflects MarkWest’s estimate of the range of DCF for 2012 and forecasted crude oil and natural gas prices for 2012. The analysis assumes various combinations of crude oil and natural gas prices as well as three NGL to crude correlation scenarios for all NGLs (C2+), including:
a. The three-year NGL correlation to crude for 2012.
b. One standard deviation above the three-year NGL correlation to crude for 2012.
c. One standard deviation below the three-year NGL correlation to crude for 2012.
The analysis further assumes derivative instruments outstanding as of February 17, 2012, and production volumes estimated through December 31, 2012. The range of stated hypothetical changes in commodity prices considers current and historic market performance.
Estimated Range of 2012 DCF
|
|
|
|
|
Natural Gas Price |
| |||||||||||||
|
Crude Oil Price |
|
Three-year NGL Correlation to Crude |
|
$ 2.00 |
|
$ 2.50 |
|
$ 3.00 |
|
$ 3.50 |
|
$ 4.00 |
| |||||
|
|
|
One standard deviation above |
|
$ |
610 |
|
$ |
604 |
|
$ |
599 |
|
$ |
593 |
|
$ |
587 |
|
|
$120 |
|
Three-year NGL correlation to crude |
|
$ |
533 |
|
$ |
527 |
|
$ |
521 |
|
$ |
516 |
|
$ |
510 |
|
|
|
|
One standard deviation below |
|
$ |
458 |
|
$ |
452 |
|
$ |
446 |
|
$ |
441 |
|
$ |
435 |
|
|
|
|
One standard deviation above |
|
$ |
585 |
|
$ |
579 |
|
$ |
573 |
|
$ |
568 |
|
$ |
562 |
|
|
$110 |
|
Three-year NGL correlation to crude |
|
$ |
514 |
|
$ |
508 |
|
$ |
503 |
|
$ |
497 |
|
$ |
491 |
|
|
|
|
One standard deviation below |
|
$ |
446 |
|
$ |
441 |
|
$ |
435 |
|
$ |
429 |
|
$ |
424 |
|
|
|
|
One standard deviation above |
|
$ |
554 |
|
$ |
549 |
|
$ |
543 |
|
$ |
537 |
|
$ |
532 |
|
|
$100 |
|
Three-year NGL correlation to crude |
|
$ |
491 |
|
$ |
485 |
|
$ |
480 |
|
$ |
474 |
|
$ |
468 |
|
|
|
|
One standard deviation below |
|
$ |
430 |
|
$ |
424 |
|
$ |
419 |
|
$ |
413 |
|
$ |
407 |
|
|
|
|
One standard deviation above |
|
$ |
520 |
|
$ |
514 |
|
$ |
509 |
|
$ |
503 |
|
$ |
497 |
|
|
$90 |
|
Three-year NGL correlation to crude |
|
$ |
465 |
|
$ |
459 |
|
$ |
453 |
|
$ |
448 |
|
$ |
442 |
|
|
|
|
One standard deviation below |
|
$ |
409 |
|
$ |
404 |
|
$ |
398 |
|
$ |
392 |
|
$ |
387 |
|
|
|
|
One standard deviation above |
|
$ |
489 |
|
$ |
483 |
|
$ |
478 |
|
$ |
472 |
|
$ |
466 |
|
|
$80 |
|
Three-year NGL correlation to crude |
|
$ |
441 |
|
$ |
435 |
|
$ |
430 |
|
$ |
424 |
|
$ |
418 |
|
|
|
|
One standard deviation below |
|
$ |
391 |
|
$ |
386 |
|
$ |
380 |
|
$ |
375 |
|
$ |
372 |
|
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.”