Attached files
| file | filename |
|---|---|
| 8-K - 8-K - MARKWEST ENERGY PARTNERS L P | a13-6234_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 |
|
|
Josh Hallenbeck, VP of Finance & Treasurer |
|
Denver, Colorado 80202 |
|
Phone: |
(866) 858-0482 |
|
|
|
E-mail: |
investorrelations@markwest.com |
MarkWest Energy Partners Reports Record Distributable Cash Flow and Full-Year Distribution Growth of 12.6 Percent
DENVER—February 27, 2013—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 $111.8 million for the three months ended December 31, 2012, and $416.4 million for the year ended December 31, 2012. Distributable cash flow for the three months and year ended December 31, 2012, represents distribution coverage of 106 percent and 112 percent, respectively. The fourth quarter distribution of $105.4 million, or $0.82 per common unit, was paid to unitholders on February 14, 2013. The fourth quarter 2012 distribution represents an increase of $0.01 per common unit, over the third quarter 2012 distribution and a full-year increase of 12.6 percent compared to 2011. As a Master Limited Partnership, cash distributions to common unitholders are largely determined based on DCF. A reconciliation of DCF to net income, the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.
The Partnership reported Adjusted EBITDA of $135.1 million for the three months ended December 31, 2012 and $528.2 million for the year ended December 31, 2012, as compared to $147.2 million and $515.3 million for the three months and year ended December 31, 2011. The Partnership believes the presentation of Adjusted EBITDA provides useful information because it is commonly used by investors in Master Limited Partnerships to assess financial performance and operating results of ongoing business operations. A reconciliation of Adjusted EBITDA to net income, the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.
The Partnership reported income before provision for income tax for the three months and year ended December 31, 2012, of $26.9 million and $257.1 million, respectively. Income before provision for income tax includes non-cash gain associated with the change in mark-to-market of derivative instruments of $0.3 million and $102.1 million for the three months and year ended December 31, 2012, respectively. Excluding these items, income before provision for income tax for the three months and year ended December 31, 2012, would have been $26.6 million and $155.0 million, respectively.
“We are extremely pleased with our performance in 2012, which was highlighted by record distributable cash flow, our second consecutive year of double digit distribution increases and 23 percent growth in processed volumes,” said Frank Semple, Chairman, President and Chief Executive Officer. “We have continued to build on our industry-leading position in the Marcellus Shale and as a result of our producer customers’ very successful drilling programs our fourth quarter year-over-year Liberty processed volumes increased by 86 percent. In addition, with our partner EMG, we have made enormous progress in the development of our full service integrated midstream platform to
support the rapidly developing Utica Shale. In 2012 we invested almost $2 billion on strategic growth projects primarily in our Marcellus and Utica business units and in 2013 we expect to invest between $1.5 and $1.8 billion on additional capital projects, which are supported by long-term, largely fee-based contracts. Our diverse asset base and strategic position in some of the premier resource plays in the U.S. continues to provide us with significant growth opportunities. We are committed to provide our producer customers with fully-integrated midstream solutions and outstanding customer service.”
BUSINESS HIGHLIGHTS
Business Development
Liberty:
· In October 2012, the Partnership commenced operations of the 200 million cubic feet per day (MMcf/d) Sherwood I processing facility and associated gathering and compression in Doddridge County, West Virginia. These assets are supported by a long-term, fee-based agreement with Antero Resources. The initiation of Sherwood operations represents the first phase of the Partnership’s on-going development of midstream infrastructure in Doddridge County. The Partnership expects the Sherwood II and Sherwood III cryogenic processing plants, totaling 400 MMcf/d, to be operational in the second and third quarters of 2013, respectively.
· In November 2012, the Partnership announced plans to further expand the processing capacity at its Mobley complex in Wetzel County, West Virginia by 200 MMcf/d. This expansion is supported by an existing long-term, fee-based agreement with EQT Corporation (NYSE: EQT) and is expected to be completed in the fourth quarter of 2013. Upon completion of the third facility, the Partnership’s total cryogenic processing capacity at Mobley will be 520 MMcf/d.
· In December 2012, the Partnership commenced operations of the first Mobley processing facility. The 200 MMcf/d plant supports the development of rich-gas acreage in the Marcellus Shale by EQT Corporation, Magnum Hunter Resources Corporation (NYSE: MHR) and other producers.
Utica:
· In November 2012, MarkWest Utica EMG, LLC (MarkWest Utica EMG) a joint venture between the Partnership and The Energy and Minerals Group (EMG), announced the execution of definitive agreements with Antero Resources to provide gas processing, fractionation and marketing services in Noble County, Ohio. Under long-term, fee-based agreements, MarkWest Utica EMG will construct two processing facilities totaling 400 MMcf/d at its Seneca complex. In addition to the Seneca processing complex, MarkWest Utica EMG will construct an NGL gathering system to the Cadiz processing complex and then on to the Hopedale fractionation and marketing complex in Harrison County, Ohio.
· In November 2012, MarkWest Utica EMG completed its refrigeration facility at the Cadiz complex, which provides 60 MMcf/d of interim processing capacity to support rapidly expanding development of the Utica Shale. The completion of this facility is a significant milestone and is MarkWest Utica EMG’s first processing facility in the Utica Shale.
· In February 2013, MarkWest Utica EMG announced the execution of definitive agreements with Rex Energy Corporation (NYSE: REXX) (Rex) to provide gathering, processing, fractionation, and marketing services in the Utica Shale. MarkWest Utica EMG expects to begin providing the full-suite of midstream services for Rex by June 1, 2013.
· In February 2013, the Partnership, together with EMG, completed an Amended and Restated Limited Liability Company Agreement (Amended LLC Agreement) for MarkWest Utica EMG. The Amended LLC Agreement allows EMG to increase its capital investment in MarkWest Utica EMG from $500 million to $950 million. The transaction provides the Partnership with flexibility in the timing of future capital contributions to MarkWest Utica EMG and accelerates the continued development of critical midstream infrastructure in the highly prospective Utica Shale.
Northeast:
· In October 2012, the Partnership commenced operations of its 150 MMcf/d Langley cryogenic processing plant expansion supporting producers’ gas development in the Huron/Berea Shale. This expansion increases the Partnership’s total processing capacity in the Northeast segment to 652 MMcf/d and further expands the Partnership’s position as the largest natural gas processor in the Appalachian Basin.
Southwest:
· In November 2012, the Partnership completed its 120 MMcf/d Carthage East cryogenic processing plant, to support producers’ gas development in the liquids-rich Haynesville Shale. This expansion increases the Partnership’s total processing capacity in East Texas to 400 MMcf/d.
Capital Markets
· On November 7, 2012, the Partnership filed a prospectus supplement for an at-the-market equity program with a total value of up to $600 million. This program allows, but does not require, the Partnership to issue common units from time to time. Through the year ended December 31, 2012 the Partnership offered 0.13 million common units. The net proceeds of approximately $6.3 million were used to fund the Partnership’s capital expenditure program and for general partnership purposes.
· On November 19, 2012, the Partnership completed an equity offering of 9.8 million common units. The net proceeds of approximately $437.2 million were used to partially fund the Partnership’s capital expenditure program and for general partnership purposes.
· On January 10, 2013, the Partnership completed a public offering of $1.0 billion of 4.50% senior unsecured notes priced at par due in 2023. A portion of the net proceeds of approximately $986.9 million, together with cash on hand resulting in part from recent equity offerings, was used to fund the redemption of all of its outstanding 8.75% senior notes due 2018, and a portion of its 6.50% senior notes due 2021 and 6.25% senior notes due 2022, with the balance of such proceeds to be used to fund the Partnership’s capital expenditure program and for general partnership purposes.
FINANCIAL RESULTS
Balance Sheet
· At December 31, 2012, the Partnership had $313.0 million of cash and cash equivalents in wholly owned subsidiaries and $1.19 billion available for borrowing under its $1.2 billion revolving credit facility after consideration of $11.6 million of outstanding letters of credit.
Operating Results
· Operating income before items not allocated to segments for the three months ended December 31, 2012, was $163.1 million, a decrease of $7.9 million when compared to segment operating income of $171.0 million over the same period in 2011. This decrease was primarily attributable to lower commodity prices compared to the prior year quarter. Processed volumes continued to remain strong, growing over 27 percent when compared to the fourth quarter of 2011, primarily due to the Partnership’s Liberty and Southwest segments. The Partnership has changed its segment reporting. The Javelina facility, which was previously reported separately in the Gulf Coast segment, is now included in the Southwest segment. In addition, operations in Ohio are now reported separately as the Utica 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 loss on commodity derivative instruments. Realized losses on commodity derivative instruments were $2.1 million in the fourth quarter of 2012 and $20.0 million in the fourth quarter of 2011.
Capital Expenditures
· For the three months and year ended December 31, 2012, the Partnership’s portion of capital expenditures was $532.5 million and $1,718.4 million, respectively. These expenditures do not include the Keystone purchase price of $507.3 million.
2013 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST
For 2013, the Partnership is maintaining its DCF forecast in a range of $500 million to $575 million based on its current forecast of operational volumes and prices for crude oil, natural gas and natural gas liquids; and derivative instruments currently outstanding. A commodity price sensitivity analysis for forecasted 2013 DCF is provided within the tables of this press release.
The Partnership’s portion of growth capital expenditures for 2013 has been narrowed to a range of $1.5 billion to $1.8 billion.
CONFERENCE CALL
The Partnership will host a conference call and webcast on Thursday, February 28, 2013, at 12:00 p.m. Eastern Time to review its fourth quarter and full year 2012 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) 388-9075 (no passcode required).
###
MarkWest Energy Partners, L.P. is a master limited partnership engaged in the gathering, processing and transportation of natural gas; the gathering, transportation, fractionation, storage and marketing of natural gas liquids; and the gathering and transportation of crude oil. MarkWest has a leading presence in many unconventional gas plays including the Marcellus Shale, Utica Shale, Huron/Berea Shale, Haynesville Shale, Woodford Shale and Granite Wash formation.
This press release includes “forward-looking statements.” All statements other than statements of historical facts included or incorporated herein may constitute forward-looking statements. Actual results could vary significantly from those expressed or implied in such statements and are subject to a number of risks and uncertainties. Although MarkWest believes that the expectations reflected in the forward-looking statements are reasonable, MarkWest can give no assurance that such expectations will prove to be correct. The forward-looking statements involve risks and uncertainties that affect operations, financial performance, and other factors as discussed in filings with the Securities and Exchange Commission (SEC). Among the factors that could cause results to differ materially are those risks discussed in the periodic reports filed with the SEC, including MarkWest’s Annual Report on Form 10-K for the year ended December 31, 2012. You are urged to carefully review and consider the cautionary statements and other disclosures made in those filings, specifically those under the heading “Risk Factors.” MarkWest does not undertake any duty to update any forward-looking statement except as required by law.
MarkWest Energy Partners, L.P.
Financial Statistics
(in thousands, except per unit data)
|
|
|
Three months ended December 31, |
|
Twelve months ended December 31, |
| ||||||||
|
|
|
2012 |
|
2011 |
|
2012 |
|
2011 |
| ||||
|
Statement of Operations Data |
|
|
|
|
|
|
|
|
| ||||
|
Revenue: |
|
|
|
|
|
|
|
|
| ||||
|
Revenue |
|
$ |
365,927 |
|
$ |
424,802 |
|
$ |
1,395,231 |
|
$ |
1,534,434 |
|
|
Derivative gain (loss) |
|
5,583 |
|
(90,889 |
) |
56,535 |
|
(29,035 |
) | ||||
|
Total revenue |
|
371,510 |
|
333,913 |
|
1,451,766 |
|
1,505,399 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Operating expenses: |
|
|
|
|
|
|
|
|
| ||||
|
Purchased product costs |
|
143,673 |
|
184,877 |
|
530,328 |
|
682,370 |
| ||||
|
Derivative loss (gain) related to purchased product costs |
|
7,174 |
|
35,094 |
|
(13,962 |
) |
52,960 |
| ||||
|
Facility expenses |
|
57,714 |
|
49,240 |
|
208,385 |
|
173,598 |
| ||||
|
Derivative loss (gain) related to facility expenses |
|
235 |
|
(3,609 |
) |
1,371 |
|
(6,480 |
) | ||||
|
Selling, general and administrative expenses |
|
25,091 |
|
20,775 |
|
94,116 |
|
81,229 |
| ||||
|
Depreciation |
|
57,350 |
|
39,674 |
|
189,549 |
|
149,954 |
| ||||
|
Amortization of intangible assets |
|
15,040 |
|
10,985 |
|
53,320 |
|
43,617 |
| ||||
|
Loss on disposal of property, plant and equipment |
|
3,271 |
|
4,178 |
|
6,254 |
|
8,797 |
| ||||
|
Accretion of asset retirement obligations |
|
137 |
|
256 |
|
677 |
|
1,190 |
| ||||
|
Total operating expenses |
|
309,685 |
|
341,470 |
|
1,070,038 |
|
1,187,235 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Income (loss) from operations |
|
61,825 |
|
(7,557 |
) |
381,728 |
|
318,164 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Other income (expense): |
|
|
|
|
|
|
|
|
| ||||
|
(Loss) earnings from unconsolidated affiliates |
|
(89 |
) |
167 |
|
699 |
|
(1,095 |
) | ||||
|
Interest income |
|
124 |
|
208 |
|
419 |
|
422 |
| ||||
|
Interest expense |
|
(33,336 |
) |
(30,595 |
) |
(120,191 |
) |
(113,631 |
) | ||||
|
Amortization of deferred financing costs and discount (a component of interest expense) |
|
(1,658 |
) |
(1,241 |
) |
(5,601 |
) |
(5,114 |
) | ||||
|
Loss on redemption of debt |
|
— |
|
(35,535 |
) |
— |
|
(78,996 |
) | ||||
|
Miscellaneous (expense) income, net |
|
(1 |
) |
17 |
|
62 |
|
144 |
| ||||
|
Income (loss) before provision for income tax |
|
26,865 |
|
(74,536 |
) |
257,116 |
|
119,894 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Provision for income tax (benefit) expense: |
|
|
|
|
|
|
|
|
| ||||
|
Current |
|
(4,568 |
) |
9,474 |
|
(2,366 |
) |
17,578 |
| ||||
|
Deferred |
|
1,298 |
|
(22,267 |
) |
40,694 |
|
(3,929 |
) | ||||
|
Total provision for income tax |
|
(3,270 |
) |
(12,793 |
) |
38,328 |
|
13,649 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Net income (loss) |
|
30,135 |
|
(61,743 |
) |
218,788 |
|
106,245 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Net loss (income) attributable to non-controlling interest |
|
1,679 |
|
(12,342 |
) |
1,614 |
|
(45,550 |
) | ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Net income (loss) attributable to the Partnership |
|
$ |
31,814 |
|
$ |
(74,085 |
) |
$ |
220,402 |
|
$ |
60,695 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
Net income (loss) attributable to the Partnership’s common unitholders per common unit: |
|
|
|
|
|
|
|
|
| ||||
|
Basic |
|
$ |
0.26 |
|
$ |
(0.87 |
) |
$ |
1.98 |
|
$ |
0.75 |
|
|
Diluted |
|
$ |
0.22 |
|
$ |
(0.87 |
) |
$ |
1.69 |
|
$ |
0.75 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
Weighted average number of outstanding common units: |
|
|
|
|
|
|
|
|
| ||||
|
Basic |
|
122,079 |
|
85,431 |
|
109,979 |
|
78,466 |
| ||||
|
Diluted |
|
142,720 |
|
85,431 |
|
130,648 |
|
78,619 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Cash Flow Data |
|
|
|
|
|
|
|
|
| ||||
|
Net cash flow provided by (used in): |
|
|
|
|
|
|
|
|
| ||||
|
Operating activities |
|
$ |
106,995 |
|
$ |
83,449 |
|
$ |
496,713 |
|
$ |
414,698 |
|
|
Investing activities |
|
$ |
(726,281 |
) |
$ |
(188,867 |
) |
$ |
(2,472,352 |
) |
$ |
(776,553 |
) |
|
Financing activities |
|
$ |
552,121 |
|
$ |
63,257 |
|
$ |
2,206,522 |
|
$ |
411,421 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
Other Financial Data |
|
|
|
|
|
|
|
|
| ||||
|
Distributable cash flow |
|
$ |
111,774 |
|
$ |
88,405 |
|
$ |
416,423 |
|
$ |
332,796 |
|
|
Adjusted EBITDA |
|
$ |
135,079 |
|
$ |
147,235 |
|
$ |
528,168 |
|
$ |
515,258 |
|
|
|
|
December 31, 2012 |
|
December 31, 2011 |
|
|
|
|
| ||
|
Balance Sheet Data |
|
|
|
|
|
|
|
|
| ||
|
Working capital |
|
$ |
(82,587 |
) |
$ |
4,234 |
|
|
|
|
|
|
Total assets |
|
6,835,716 |
|
4,070,425 |
|
|
|
|
| ||
|
Total debt |
|
2,523,051 |
|
1,846,062 |
|
|
|
|
| ||
|
Total equity |
|
3,215,591 |
|
1,502,067 |
|
|
|
|
| ||
MarkWest Energy Partners, L.P.
Operating Statistics
|
|
|
Three months ended December 31, |
|
Twelve months ended December 31, |
| ||||
|
|
|
2012 |
|
2011 |
|
2012 |
|
2011 |
|
|
Southwest |
|
|
|
|
|
|
|
|
|
|
East Texas gathering systems throughput (Mcf/d) |
|
477,600 |
|
423,100 |
|
450,000 |
|
423,600 |
|
|
East Texas natural gas processed (Mcf/d) |
|
302,000 |
|
235,100 |
|
270,800 |
|
228,300 |
|
|
East Texas NGL sales (gallons, in thousands) |
|
76,500 |
|
63,500 |
|
275,800 |
|
238,700 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Western Oklahoma gathering system throughput (Mcf/d) (1) |
|
200,800 |
|
277,500 |
|
235,600 |
|
237,900 |
|
|
Western Oklahoma natural gas processed (Mcf/d) |
|
193,800 |
|
231,700 |
|
206,500 |
|
175,500 |
|
|
Western Oklahoma NGL sales (gallons, in thousands) |
|
44,500 |
|
66,100 |
|
214,400 |
|
177,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Southeast Oklahoma gathering system throughput (Mcf/d) |
|
463,100 |
|
524,800 |
|
487,900 |
|
511,900 |
|
|
Southeast Oklahoma natural gas processed (Mcf/d) (2) |
|
137,000 |
|
104,200 |
|
121,800 |
|
103,400 |
|
|
Southeast Oklahoma NGL sales (gallons, in thousands) |
|
42,400 |
|
33,000 |
|
163,300 |
|
125,100 |
|
|
Arkoma Connector Pipeline throughput (Mcf/d) |
|
253,700 |
|
346,000 |
|
305,900 |
|
307,300 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Southwest gathering system throughput (Mcf/d) (3) |
|
22,300 |
|
25,100 |
|
24,300 |
|
29,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast refinery off-gas processed (Mcf/d) |
|
113,600 |
|
113,700 |
|
118,400 |
|
113,300 |
|
|
Gulf Coast liquids fractionated (Bbl/d) |
|
21,000 |
|
20,800 |
|
22,500 |
|
21,200 |
|
|
Gulf Coast NGL sales (gallons excluding hydrogen, in thousands) |
|
81,000 |
|
80,200 |
|
345,300 |
|
325,700 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast (4) |
|
|
|
|
|
|
|
|
|
|
Natural gas processed (Mcf/d) |
|
313,700 |
|
320,300 |
|
320,500 |
|
305,900 |
|
|
NGLs fractionated (Bbl/d) (5) |
|
19,500 |
|
17,200 |
|
17,500 |
|
20,300 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Keep-whole sales (gallons, in thousands) |
|
35,100 |
|
31,100 |
|
131,600 |
|
113,800 |
|
|
Percent-of-proceeds sales (gallons, in thousands) |
|
36,200 |
|
34,700 |
|
139,700 |
|
130,300 |
|
|
Total NGL sales (gallons, in thousands) (6) |
|
71,300 |
|
65,800 |
|
271,300 |
|
244,100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil transported for a fee (Bbl/d) |
|
9,900 |
|
9,700 |
|
9,300 |
|
10,300 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Liberty |
|
|
|
|
|
|
|
|
|
|
Natural gas processed (Mcf/d) |
|
696,000 |
|
374,800 |
|
496,400 |
|
323,900 |
|
|
Gathering system throughput (Mcf/d) |
|
587,600 |
|
295,600 |
|
425,000 |
|
245,700 |
|
|
NGLs fractionated (Bbl/d) (7) |
|
31,100 |
|
19,200 |
|
24,900 |
|
11,800 |
|
|
NGL sales (gallons, in thousands) (8) |
|
129,400 |
|
77,700 |
|
393,600 |
|
241,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Utica (9) |
|
|
|
|
|
|
|
|
|
|
Natural gas processed (Mcf/d) |
|
5,000 |
|
N/A |
|
4,200 |
|
N/A |
|
|
Gathering system throughput (Mcf/d) |
|
6,400 |
|
N/A |
|
5,000 |
|
N/A |
|
(1) Includes natural gas gathered in Western Oklahoma and from the Granite Wash formation in the Texas Panhandle. It is considered 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 1,400 and 200 barrels per day fractionated on behalf of Liberty for the three months ended December 31, 2012 and 2011, respectively, and 400 and 3,900 barrels per day fractionated for the twleve months ended December 31, 2012 and 2011, 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 except during temporary periods of capacity constraint.
(6) Represents sales at the Siloam fractionator. The total sales exclude approximately 5,500,000 and 600,000 gallons, sold by the Northeast on behalf of Liberty for three months ended December 31, 2012 and 2011, respectively, and 6,500,000 and 59,200,000 gallons sold for the twelve months ended December 31, 2012 and 2011, 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.
(9) Utica operations began in August 2012. The volumes reported are the average daily rate for the days of operation.
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, 2012 |
|
Southwest |
|
Northeast |
|
Liberty |
|
Utica |
|
Total |
| |||||
|
Revenue |
|
$ |
204,370 |
|
$ |
56,862 |
|
$ |
106,106 |
|
$ |
426 |
|
$ |
367,764 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
| |||||
|
Purchased product costs |
|
99,765 |
|
18,740 |
|
25,168 |
|
— |
|
143,673 |
| |||||
|
Facility expenses |
|
30,195 |
|
6,529 |
|
21,281 |
|
2,377 |
|
60,382 |
| |||||
|
Total operating expenses before items not allocated to segments |
|
129,960 |
|
25,269 |
|
46,449 |
|
2,377 |
|
204,055 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
Portion of operating income (loss) attributable to non-controlling interests |
|
1,211 |
|
— |
|
— |
|
(619 |
) |
592 |
| |||||
|
Operating income (loss) before items not allocated to segments |
|
$ |
73,199 |
|
$ |
31,593 |
|
$ |
59,657 |
|
$ |
(1,332 |
) |
$ |
163,117 |
|
|
Three months ended December 31, 2011 |
|
Southwest |
|
Northeast |
|
Liberty |
|
Utica |
|
Total |
| |||||
|
Revenue |
|
$ |
279,329 |
|
$ |
67,197 |
|
$ |
80,807 |
|
$ |
— |
|
$ |
427,333 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
| |||||
|
Purchased product costs |
|
133,660 |
|
19,085 |
|
32,132 |
|
— |
|
184,877 |
| |||||
|
Facility expenses |
|
32,042 |
|
7,724 |
|
12,038 |
|
— |
|
51,804 |
| |||||
|
Total operating expenses before items not allocated to segments |
|
165,702 |
|
26,809 |
|
44,170 |
|
— |
|
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 |
|
$ |
111,941 |
|
$ |
40,388 |
|
$ |
18,688 |
|
N/A |
|
$ |
171,017 |
| |
|
|
|
Three months ended December 31, |
| ||||
|
|
|
2012 |
|
2011 |
| ||
|
|
|
|
|
|
| ||
|
Operating income before items not allocated to segments |
|
$ |
163,117 |
|
$ |
171,017 |
|
|
Portion of operating income attributable to non-controlling interests |
|
592 |
|
19,635 |
| ||
|
Derivative loss not allocated to segments |
|
(1,826 |
) |
(122,374 |
) | ||
|
Revenue deferral adjustment |
|
(1,837 |
) |
(2,531 |
) | ||
|
Compensation expense included in facility expenses not allocated to segments |
|
(196 |
) |
(290 |
) | ||
|
Facility expenses adjustments |
|
2,864 |
|
2,854 |
| ||
|
Selling, general and administrative expenses |
|
(25,091 |
) |
(20,775 |
) | ||
|
Depreciation |
|
(57,350 |
) |
(39,674 |
) | ||
|
Amortization of intangible assets |
|
(15,040 |
) |
(10,985 |
) | ||
|
Loss on disposal of property, plant and equipment |
|
(3,271 |
) |
(4,178 |
) | ||
|
Accretion of asset retirement obligations |
|
(137 |
) |
(256 |
) | ||
|
Income (loss) from operations |
|
61,825 |
|
(7,557 |
) | ||
|
Other income (expense): |
|
|
|
|
| ||
|
(Loss) earnings from unconsolidated affiliate |
|
(89 |
) |
167 |
| ||
|
Interest income |
|
124 |
|
208 |
| ||
|
Interest expense |
|
(33,336 |
) |
(30,595 |
) | ||
|
Amortization of deferred financing costs and discount (a component of interest expense) |
|
(1,658 |
) |
(1,241 |
) | ||
|
Loss on redemption of debt |
|
— |
|
(35,535 |
) | ||
|
Miscellaneous (expense) income, net |
|
(1 |
) |
17 |
| ||
|
Income (loss) before provision for income tax |
|
$ |
26,865 |
|
$ |
(74,536 |
) |
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)
|
Twelve months ended December 31, 2012 |
|
Southwest |
|
Northeast |
|
Liberty |
|
Utica |
|
Total |
| |||||
|
Revenue |
|
$ |
856,416 |
|
$ |
225,818 |
|
$ |
319,867 |
|
$ |
571 |
|
$ |
1,402,672 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
| |||||
|
Purchased product costs |
|
387,902 |
|
68,402 |
|
74,024 |
|
— |
|
530,328 |
| |||||
|
Facility expenses |
|
124,921 |
|
24,106 |
|
65,825 |
|
3,968 |
|
218,820 |
| |||||
|
Total operating expenses before items not allocated to segments |
|
512,823 |
|
92,508 |
|
139,849 |
|
3,968 |
|
749,148 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
Portion of operating income (loss) attributable to non-controlling interests |
|
5,790 |
|
— |
|
— |
|
(1,359 |
) |
4,431 |
| |||||
|
Operating income (loss) before items not allocated to segments |
|
$ |
337,803 |
|
$ |
133,310 |
|
$ |
180,018 |
|
$ |
(2,038 |
) |
$ |
649,093 |
|
|
Twelve months ended December 31, 2011 |
|
Southwest |
|
Northeast |
|
Liberty |
|
Utica |
|
Total |
| |||||
|
Revenue |
|
$ |
1,031,986 |
|
$ |
268,884 |
|
$ |
248,949 |
|
$ |
— |
|
$ |
1,549,819 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
| |||||
|
Purchased product costs |
|
506,911 |
|
91,612 |
|
83,847 |
|
— |
|
682,370 |
| |||||
|
Facility expenses |
|
121,197 |
|
27,126 |
|
34,913 |
|
— |
|
183,236 |
| |||||
|
Total operating expenses before items not allocated to segments |
|
628,108 |
|
118,738 |
|
118,760 |
|
— |
|
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 |
|
$ |
398,447 |
|
$ |
150,146 |
|
$ |
66,458 |
|
N/A |
|
$ |
615,051 |
| |
|
|
|
Twelve months ended December 31, |
| ||||
|
|
|
2012 |
|
2011 |
| ||
|
|
|
|
|
|
| ||
|
Operating income before items not allocated to segments |
|
$ |
649,093 |
|
$ |
615,051 |
|
|
Portion of operating income attributable to non-controlling interests |
|
4,431 |
|
69,162 |
| ||
|
Derivative gain (loss) not allocated to segments |
|
69,126 |
|
(75,515 |
) | ||
|
Revenue deferral adjustment |
|
(7,441 |
) |
(15,385 |
) | ||
|
Compensation expense included in facility expenses not allocated to segments |
|
(1,022 |
) |
(1,781 |
) | ||
|
Facility expenses adjustments |
|
11,457 |
|
11,419 |
| ||
|
Selling, general and administrative expenses |
|
(94,116 |
) |
(81,229 |
) | ||
|
Depreciation |
|
(189,549 |
) |
(149,954 |
) | ||
|
Amortization of intangible assets |
|
(53,320 |
) |
(43,617 |
) | ||
|
Loss on disposal of property, plant and equipment |
|
(6,254 |
) |
(8,797 |
) | ||
|
Accretion of asset retirement obligations |
|
(677 |
) |
(1,190 |
) | ||
|
Income from operations |
|
381,728 |
|
318,164 |
| ||
|
Other income (expense): |
|
|
|
|
| ||
|
Earnings (loss) from unconsolidated affiliate |
|
699 |
|
(1,095 |
) | ||
|
Interest income |
|
419 |
|
422 |
| ||
|
Interest expense |
|
(120,191 |
) |
(113,631 |
) | ||
|
Amortization of deferred financing costs and discount (a component of interest expense) |
|
(5,601 |
) |
(5,114 |
) | ||
|
Loss on redemption of debt |
|
— |
|
(78,996 |
) | ||
|
Miscellaneous income, net |
|
62 |
|
144 |
| ||
|
Income before provision for income tax |
|
$ |
257,116 |
|
$ |
119,894 |
|
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, |
|
Twelve months ended December 31, |
| ||||||||
|
|
|
2012 |
|
2011 |
|
2012 |
|
2011 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Net income (loss) |
|
$ |
30,135 |
|
$ |
(61,743 |
) |
$ |
218,788 |
|
$ |
106,245 |
|
|
Depreciation, amortization, impairment, and other non-cash operating expenses |
|
75,876 |
|
55,171 |
|
250,112 |
|
203,870 |
| ||||
|
Loss on redemption of debt, net of tax benefit |
|
— |
|
32,446 |
|
— |
|
72,064 |
| ||||
|
Amortization of deferred financing costs and discount |
|
1,658 |
|
1,241 |
|
5,601 |
|
5,114 |
| ||||
|
Non-cash loss (earnings) from unconsolidated affiliate |
|
89 |
|
(167 |
) |
(699 |
) |
1,095 |
| ||||
|
Distributions from unconsolidated affiliate |
|
400 |
|
(560 |
) |
2,600 |
|
(260 |
) | ||||
|
Non-cash compensation expense |
|
1,977 |
|
(308 |
) |
8,247 |
|
3,399 |
| ||||
|
Non-cash derivative activity |
|
(312 |
) |
102,391 |
|
(102,127 |
) |
(290 |
) | ||||
|
Provision for income tax - deferred |
|
1,298 |
|
(22,267 |
) |
40,694 |
|
(3,929 |
) | ||||
|
Cash adjustment for non-controlling interest of consolidated subsidiaries |
|
(67 |
) |
(18,185 |
) |
(2,580 |
) |
(64,470 |
) | ||||
|
Revenue deferral adjustment |
|
1,837 |
|
2,531 |
|
7,441 |
|
15,385 |
| ||||
|
Other |
|
(314 |
) |
4,634 |
|
3,648 |
|
9,171 |
| ||||
|
Maintenance capital expenditures, net of joint venture partner contributions |
|
(803 |
) |
(6,779 |
) |
(15,302 |
) |
(14,598 |
) | ||||
|
Distributable cash flow |
|
$ |
111,774 |
|
$ |
88,405 |
|
$ |
416,423 |
|
$ |
332,796 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
Maintenance capital expenditures |
|
$ |
803 |
|
$ |
7,490 |
|
$ |
15,302 |
|
$ |
16,067 |
|
|
Growth capital expenditures |
|
709,758 |
|
183,865 |
|
1,936,125 |
|
535,214 |
| ||||
|
Total capital expenditures |
|
710,561 |
|
191,355 |
|
1,951,427 |
|
551,281 |
| ||||
|
Acquisitions, net of cash acquired |
|
— |
|
— |
|
506,797 |
|
230,728 |
| ||||
|
Total capital expenditures and acquisitions |
|
710,561 |
|
191,355 |
|
2,458,224 |
|
782,009 |
| ||||
|
Joint venture partner contributions |
|
(178,018 |
) |
(61,115 |
) |
(233,018 |
) |
(129,616 |
) | ||||
|
Total capital expenditures and acquisitions, net |
|
$ |
532,543 |
|
$ |
130,240 |
|
$ |
2,225,206 |
|
$ |
652,393 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
Distributable cash flow |
|
$ |
111,774 |
|
$ |
88,405 |
|
$ |
416,423 |
|
$ |
332,796 |
|
|
Maintenance capital expenditures, net |
|
803 |
|
6,779 |
|
15,302 |
|
14,598 |
| ||||
|
Changes in receivables and other assets |
|
(1,540 |
) |
(32,268 |
) |
25,406 |
|
(65,523 |
) | ||||
|
Changes in accounts payable, accrued liabilities and other long-term liabilities |
|
(3,645 |
) |
466 |
|
41,723 |
|
69,838 |
| ||||
|
Derivative instrument premium payments, net of amortization |
|
— |
|
1,155 |
|
— |
|
4,436 |
| ||||
|
Cash adjustment for non-controlling interest of consolidated subsidiaries |
|
67 |
|
18,185 |
|
2,580 |
|
64,470 |
| ||||
|
Other |
|
(464 |
) |
727 |
|
(4,721 |
) |
(5,917 |
) | ||||
|
Net cash provided by operating activities |
|
$ |
106,995 |
|
$ |
83,449 |
|
$ |
496,713 |
|
$ |
414,698 |
|
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Adjusted EBITDA (1)
(in thousands)
|
|
|
Three months ended December 31, |
|
Twelve months ended December 31, |
| ||||||||
|
|
|
2012 |
|
2011 |
|
2012 |
|
2011 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Net income (loss) |
|
$ |
30,135 |
|
$ |
(61,743 |
) |
$ |
218,788 |
|
$ |
106,245 |
|
|
Non-cash compensation expense |
|
1,977 |
|
(308 |
) |
8,247 |
|
3,399 |
| ||||
|
Non-cash derivative activity |
|
(312 |
) |
102,391 |
|
(102,127 |
) |
(290 |
) | ||||
|
Interest expense (2) |
|
32,838 |
|
29,634 |
|
117,098 |
|
109,869 |
| ||||
|
Depreciation, amortization, impairment, and other non-cash operating expenses |
|
75,876 |
|
55,171 |
|
250,112 |
|
203,870 |
| ||||
|
Loss on redemption of debt |
|
— |
|
35,535 |
|
— |
|
78,996 |
| ||||
|
Provision for income tax |
|
(3,270 |
) |
(12,793 |
) |
38,328 |
|
13,649 |
| ||||
|
Adjustment for cash flow from unconsolidated affiliate |
|
489 |
|
(167 |
) |
1,901 |
|
1,395 |
| ||||
|
Other |
|
(2,654 |
) |
(485 |
) |
(4,179 |
) |
(1,875 |
) | ||||
|
Adjusted EBITDA |
|
$ |
135,079 |
|
$ |
147,235 |
|
$ |
528,168 |
|
$ |
515,258 |
|
(1) The Partnership has changed its calculation of adjusted EBITDA and removed the line “Adjustment related to non-guarantor of consolidated subsidiaries”.
(2) Includes amortization of deferred financing costs and discount, and excludes interest expense related to the Steam Methane Reformer.
MarkWest Energy Partners, L.P.
Distributable Cash Flow Sensitivity Analysis
(unaudited, in millions)
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 2013 and forecasted crude oil and natural gas prices for 2013. 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 55% for 2013.
b. NGL-to-crude oil ratio at 45% for 2013.
c. NGL-to-crude oil ratio at 35% for 2013.
The analysis further assumes derivative instruments outstanding as of February 27, 2013, and production volumes estimated through December 31, 2013. The range of stated hypothetical changes in commodity prices considers current and historic market performance.
Estimated Range of 2013 DCF
|
|
|
|
|
Natural Gas Price (Henry Hub) |
| |||||||||||||
|
Crude Oil Price |
|
NGL-to-Crude oil |
|
$2.50 |
|
$3.00 |
|
$3.50 |
|
$4.00 |
|
$4.50 |
| |||||
|
|
|
55% of WTI |
|
$ |
614 |
|
$ |
610 |
|
$ |
606 |
|
$ |
602 |
|
$ |
599 |
|
|
$110 |
|
45% of WTI |
|
$ |
538 |
|
$ |
534 |
|
$ |
530 |
|
$ |
527 |
|
$ |
523 |
|
|
|
|
35% of WTI |
|
$ |
466 |
|
$ |
463 |
|
$ |
459 |
|
$ |
455 |
|
$ |
451 |
|
|
|
|
55% of WTI |
|
$ |
583 |
|
$ |
579 |
|
$ |
575 |
|
$ |
571 |
|
$ |
568 |
|
|
$100 |
|
45% of WTI |
|
$ |
515 |
|
$ |
512 |
|
$ |
508 |
|
$ |
504 |
|
$ |
500 |
|
|
|
|
35% of WTI |
|
$ |
450 |
|
$ |
446 |
|
$ |
442 |
|
$ |
439 |
|
$ |
435 |
|
|
|
|
55% of WTI |
|
$ |
549 |
|
$ |
545 |
|
$ |
542 |
|
$ |
538 |
|
$ |
534 |
|
|
$90 |
|
45% of WTI |
|
$ |
491 |
|
$ |
487 |
|
$ |
483 |
|
$ |
479 |
|
$ |
475 |
|
|
|
|
35% of WTI |
|
$ |
431 |
|
$ |
427 |
|
$ |
424 |
|
$ |
420 |
|
$ |
416 |
|
|
|
|
55% of WTI |
|
$ |
526 |
|
$ |
522 |
|
$ |
518 |
|
$ |
514 |
|
$ |
510 |
|
|
$80 |
|
45% of WTI |
|
$ |
473 |
|
$ |
470 |
|
$ |
466 |
|
$ |
462 |
|
$ |
458 |
|
|
|
|
35% of WTI |
|
$ |
421 |
|
$ |
417 |
|
$ |
413 |
|
$ |
408 |
|
$ |
404 |
|
|
|
|
55% of WTI |
|
$ |
507 |
|
$ |
503 |
|
$ |
499 |
|
$ |
495 |
|
$ |
491 |
|
|
$70 |
|
45% of WTI |
|
$ |
461 |
|
$ |
457 |
|
$ |
453 |
|
$ |
449 |
|
$ |
445 |
|
|
|
|
35% of WTI |
|
$ |
414 |
|
$ |
410 |
|
$ |
405 |
|
$ |
400 |
|
$ |
395 |
|
(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.”
MarkWest Energy Partners
2013 DCF Sensitivity Correlation Analysis - Q4 2012
$ millions, except crude price
|
Crude Oil Price |
|
NGL-to-Crude oil |
|
Natural Gas Price (Henry Hub) |
| ||||||||||||||
|
(WTI) |
|
ratio (1) |
|
$2.50 |
|
$3.00 |
|
$3.50 |
|
$4.00 |
|
$4.50 |
| ||||||
|
|
|
55% of WTI |
|
$ |
614 |
|
$ |
610 |
|
$ |
606 |
|
$ |
602 |
|
$ |
599 |
| |
|
$ |
110 |
|
45% of WTI |
|
$ |
538 |
|
$ |
534 |
|
$ |
530 |
|
$ |
527 |
|
$ |
523 |
|
|
|
|
35% of WTI |
|
$ |
466 |
|
$ |
463 |
|
$ |
459 |
|
$ |
455 |
|
$ |
451 |
| |
|
|
|
55% of WTI |
|
$ |
583 |
|
$ |
579 |
|
$ |
575 |
|
$ |
571 |
|
$ |
568 |
| |
|
$ |
100 |
|
45% of WTI |
|
$ |
515 |
|
$ |
512 |
|
$ |
508 |
|
$ |
504 |
|
$ |
500 |
|
|
|
|
35% of WTI |
|
$ |
450 |
|
$ |
446 |
|
$ |
442 |
|
$ |
439 |
|
$ |
435 |
| |
|
|
|
55% of WTI |
|
$ |
549 |
|
$ |
545 |
|
$ |
542 |
|
$ |
538 |
|
$ |
534 |
| |
|
$ |
90 |
|
45% of WTI |
|
$ |
491 |
|
$ |
487 |
|
$ |
483 |
|
$ |
479 |
|
$ |
475 |
|
|
|
|
35% of WTI |
|
$ |
431 |
|
$ |
427 |
|
$ |
424 |
|
$ |
420 |
|
$ |
416 |
| |
|
|
|
55% of WTI |
|
$ |
526 |
|
$ |
522 |
|
$ |
518 |
|
$ |
514 |
|
$ |
510 |
| |
|
$ |
80 |
|
45% of WTI |
|
$ |
473 |
|
$ |
470 |
|
$ |
466 |
|
$ |
462 |
|
$ |
458 |
|
|
|
|
35% of WTI |
|
$ |
421 |
|
$ |
417 |
|
$ |
413 |
|
$ |
408 |
|
$ |
404 |
| |
|
|
|
55% of WTI |
|
$ |
507 |
|
$ |
503 |
|
$ |
499 |
|
$ |
495 |
|
$ |
491 |
| |
|
$ |
70 |
|
45% of WTI |
|
$ |
461 |
|
$ |
457 |
|
$ |
453 |
|
$ |
449 |
|
$ |
445 |
|
|
|
|
35% of WTI |
|
$ |
414 |
|
$ |
410 |
|
$ |
405 |
|
$ |
400 |
|
$ |
395 |
| |