Attached files
| file | filename |
|---|---|
| 8-K - 8-K - MARKWEST ENERGY PARTNERS L P | a14-23786_18k.htm |
Exhibit 99.1
|
MarkWest Energy Partners, L.P. |
Contact: |
Frank Semple, Chairman, President & CEO |
|
1515 Arapahoe Street |
|
Nancy Buese, Executive VP and CFO |
|
Tower 1, Suite 1600 |
|
Josh Hallenbeck, VP of Finance & Treasurer |
|
Denver, Colorado 80202 |
Phone: |
(866) 858-0482 |
|
E-mail: |
|
investorrelations@markwest.com |
MarkWest Energy Partners Reports Record Third Quarter 2014 Financial Results, Increased 2014 Distributable Cash Flow Forecast & Provides 2015 Financial Guidance
· Reported third quarter DCF of $195.2 million, Adjusted EBITDA of $235.5 million and an increased quarterly distribution of 89 cents per common unit with 119 percent distribution coverage
· Increased 2014 DCF forecast to $680 to $700 million and Adjusted EBITDA forecast to $860 to $880 million
· Reported record Marcellus and Utica processed gas volumes for the third quarter, totaling over 2.6 Bcf/d
· Placed into service 800 MMcf/d of new processing capacity, with the addition of Sherwood IV & Sherwood V in the Marcellus Shale; Cadiz II and Seneca III in the Utica Shale
· Announced new producer agreements with American Energy Partners in the Utica Shale and PennEnergy Resources and EdgeMarc Energy in the Marcellus Shale
· Announced major expansion of processing and fractionation infrastructure at the Keystone complex in the Marcellus Shale, and an additional processing plant at the Cadiz complex in the Utica Shale
· Announced construction of a third 60,000 Bbl/d fractionation facility at the Hopedale complex in Ohio that will increase total capacity for propane and heavier natural gas liquids to 274,000 Bbl/d in the first quarter of 2016
· 21 major processing and fractionation facilities under construction with 2014 capital forecast of $2.0 to $2.3 billion, 2015 forecast of $1.8 to $2.3 billion, and 2016 forecast of approximately $2.0 billion
DENVER—November 5, 2014—MarkWest Energy Partners, L.P. (NYSE: MWE) (“the Partnership”) today reported quarterly cash available for distribution to common unitholders, or distributable cash flow (DCF), of $195.2 million for the three months ended September 30, 2014, and $505.4 million for the nine months ended September 30, 2014. DCF for the three months ended September 30, 2014 represents distribution coverage of 119 percent. The third quarter distribution of $163.8 million, or $0.89 per common unit, will be paid to unitholders on November 14, 2014. The third quarter 2014 distribution represents an increase of $0.01 per common unit or 1.1 percent over the second quarter 2014 distribution and an increase of $0.04 per common unit or 4.7 percent compared to the third quarter 2013 distribution. As a Master Limited Partnership, cash distributions to common unitholders are largely determined based on DCF. A reconciliation of DCF to net income, the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.
The Partnership reported Adjusted EBITDA for the three and nine months ended September 30, 2014, of $235.5 million and $631.3 million, respectively, compared to $153.9 million and $450.5 million for the respective three and nine months ended September 30, 2013. 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 and nine months ended September 30, 2014 of $97.1 million and $135.6 million, respectively. Income before provision for income tax includes non-cash gains associated with the change in fair value of derivative instruments of $25.2 million and $18.2 million for the respective three and nine months ended September 30, 2014. Excluding these items, income before provision for income tax for the three and nine months ended September 30, 2014 would have been $71.9 million and $117.4 million, respectively.
“Our strong third quarter performance demonstrates the continued success of our producer customers and the ongoing strength of our business model,” commented Frank Semple, Chairman, President and Chief Executive Officer of MarkWest. “Year to date our team has completed 12 major processing and fractionation plants and the utilization of our large scale integrated midstream facilities continues to accelerate. As we move into 2015 and beyond, our operational and commercial execution will drive increasing cash flow, distributions and total returns for our unitholders.”
BUSINESS HIGHLIGHTS
Marcellus:
· In August, the Partnership announced that it will construct a seventh 200 million cubic feet per day (MMcf/d) processing plant at the Sherwood complex in Doddridge County, West Virginia, at the request of Antero Resources Corporation (NYSE: AR) (Antero Resources). The new plant is anchored by long-term, fee-based agreements and will expand total capacity at the Sherwood complex to 1.4 billion cubic feet per day (Bcf/d) by the third quarter of 2015. Antero Resources is the anchor producer supporting the Sherwood complex and continues to develop its prolific rich-gas acreage position in northern West Virginia. In August, the Partnership commenced operations of the Sherwood IV plant.
· In August, the Partnership announced that it will construct a sixth processing complex in the Marcellus Shale. The new Fox complex (formerly known as the Hillman complex) will be located in Washington County, Pennsylvania and will support Range Resources Corporation’s (NYSE: RRC) rapidly growing rich-gas production. The Fox complex will initially consist of Fox I, a 200 MMcf/d processing plant, and an associated de-ethanization facility. The Fox complex is scheduled to become operational during the first quarter of 2016. Propane and heavier natural gas liquids (NGLs) recovered at the Fox complex will be delivered into the Partnership’s extensive NGL network.
· In September, the Partnership announced a major expansion project at its Keystone complex in Butler County, West Virginia to support growing rich-gas production from Rex Energy Corporation (NASDAQ: REXX) and EdgeMarc Energy. The Partnership is developing Bluestone III, a 200 MMcf/d plant that is scheduled to be operational during the fourth quarter of 2015, and Bluestone IV, an additional 200 MMcf/d plant is scheduled to be operational by
the second quarter of 2016. The Partnership is also developing 40,000 barrels per day (Bbl/d) of purity ethane fractionation capacity and 20,000 Bbl/d of propane and heavier NGL fractionation capacity by the third quarter of 2015 and first quarter of 2016, respectively.
· Today, the Partnership is announcing the completion of Sherwood V, a 200 MMcf/d processing plant at the Sherwood complex in the Marcellus Shale. Sherwood V supports growing rich-gas production from Antero Resources and increases total processing capacity of the Sherwood complex to 1 Bcf/d.
· Today, the Partnership is announcing the completion of definitive agreements with PennEnergy Resources, LLC (PennEnergy Resources) to provide processing, fractionation and NGL marketing services in the Marcellus Shale. PennEnergy Resources is a growing producer operating in Beaver, Butler, and Armstrong counties of Pennsylvania and will be supported at the Partnership’s Keystone complex.
Utica:
· In July, MarkWest Utica EMG, a joint venture between the Partnership and The Energy & Minerals Group, completed Seneca III, a 200 MMcf/d processing plant in Noble County, Ohio. The new plant is anchored by Antero Resources under a long-term, fee-based contract and has expanded the total processing capacity of the Seneca complex to 600 MMcf/d. In order to support the continued growth of Antero Resources and other producers, the Partnership expects to complete a fourth 200 MMcf/d processing plant in the second quarter of 2015.
· In July, MarkWest Utica EMG completed a 40,000 Bbl/d de-ethanization facility at the Cadiz complex in Harrison County, Ohio. This new fractionation facility provides MarkWest Utica EMG’s producer customers with the ability to meet residue gas quality specifications and downstream ethane pipeline commitments. Purity ethane produced at the new Cadiz facility will be delivered to the ATEX pipeline.
· In August, MarkWest Utica EMG announced the development of Cadiz III, a 200 MMcf/d processing plant at the Cadiz complex in Harrison County, Ohio. The new facility is expected to begin operations during the first quarter of 2015. MarkWest Utica EMG recently began operations of the 200 MMcf/d Cadiz II plant to support rich-gas production from Gulfport Energy Corporation (NASDAQ: GPOR) and other producers.
· In September, MarkWest Utica EMG announced the completion of definitive agreements with American Energy — Utica, LLC (AEU), an affiliate of American Energy Partners, LP, to provide natural gas gathering, processing and fractionation services in the Utica Shale. AEU has dedicated over 60,000 net acres to MarkWest Utica EMG and Ohio Gathering Company, L.L.C. (Ohio Gathering), a joint venture between MarkWest Utica EMG and Summit Midstream Partners, LLC. Ohio Gathering will provide gas gathering and compression services for all of AEU’s gas produced from the dedicated area, while MarkWest Utica EMG will provide processing and fractionation services.
· Today, MarkWest Utica EMG is announcing the development of Cadiz IV, a 200 MMcf/d processing plant at the Cadiz complex in Harrison County, Ohio. The new facility is scheduled to begin operations in the first quarter of 2016 and will increase MarkWest Utica EMG’s total processing capacity in Ohio to over 1.5 Bcf/d.
· Today, the Partnership and MarkWest Utica EMG are announcing the development of a third fractionation facility at the Hopedale complex in Ohio. The new 60,000 Bbl/d fractionator is
scheduled to begin operations in the first quarter of 2016 and will increase total fractionation capacity for propane and heavier natural gas liquids to 274,000 Bbl/d in the Marcellus and Utica Shales.
Southwest:
· In August, the Partnership announced that it will construct a fourth processing plant at its Carthage facilities in Panola County, Texas to support growing rich-gas production from the Haynesville Shale and Cotton Valley formation. The new plant will have an initial capacity of 120 MMcf/d and is now scheduled to begin operations in December 2014. Once completed, total processing capacity at the Partnership’s East Texas operations will increase to 520 MMcf/d.
Capital Markets
· Year-to-date through November 5, 2014, the Partnership has issued 22.1 million new units and received net proceeds of approximately $1.5 billion.
FINANCIAL RESULTS
Balance Sheet
· As of September 30, 2014, the Partnership had $85.4 million of cash and cash equivalents in wholly owned subsidiaries and $762.8 million of remaining capacity under its $1.3 billion Senior Secured Credit Facility after consideration of $11.3 million of outstanding letters of credit and $525.9 million of outstanding borrowings.
Operating Results
· Operating income before items not allocated to segments for the three months ended September 30, 2014, was $256.9 million, an increase of $75.0 million when compared to $181.9 million over the same period in 2013. This increase was primarily attributable to higher processing volumes. Processed volumes continued to increase in the third quarter of 2014, growing approximately 68 percent when compared to the third quarter of 2013, primarily due to the Partnership’s Marcellus and Utica segments.
A reconciliation of operating income before items not allocated to segments to income before provision for income tax, the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.
· Operating income before items not allocated to segments does not include losses on commodity derivative instruments. Realized losses on commodity derivative instruments were ($0.9) million in the third quarter of 2014 and ($5.3) million in the third quarter of 2013.
Capital Expenditures
· For the three months ended September 30, 2014, the Partnership’s portion of capital expenditures was $371.7 million.
2014 ADJUSTED EBITDA, DCF AND CAPITAL EXPENDITURE FORECAST
The Partnership has increased its forecast of 2014 Adjusted EBITDA to a range of $860 million to $880 million and has narrowed its 2014 DCF forecast to a range of $680 million to $700 million. The Partnership has become less sensitive to changes in commodity prices as a result of significant increases in fee-based income.
The Partnership’s portion of growth capital expenditures for 2014 is forecasted in a range of $2.0 billion to $2.3 billion. Maintenance capital for 2014 is forecasted at approximately $25 million.
2015 ADJUSTED EBITDA, DCF AND CAPITAL EXPENDITURE FORECAST
For 2015, the Partnership forecasts Adjusted EBITDA in a range of $1.0 to $1.1 billion and DCF in a range of $800 million to $880 million based on its current forecast of operational volumes and prices for natural gas liquids, crude oil, natural gas, and derivative instruments currently outstanding.
A sensitivity analysis for forecasted 2015 DCF based on changes in composite NGL prices and changes in volume assumptions is provided within the tables of this press release.
The Partnership’s portion of growth capital expenditures for 2015 is forecasted in a range of $1.8 billion to $2.3 billion. Maintenance capital for 2015 is forecasted at approximately $30 million.
CONFERENCE CALL
The Partnership will host a conference call and webcast on Thursday, November 6, 2014, at 12:00 p.m. Eastern Time to review its third quarter 2014 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 and associated third quarter 2014 earnings call presentation, please visit the Investor Relations section of the Partnership’s website at www.markwest.com. A replay of the conference call will be available on the Partnership’s website or by dialing (888) 568-0541 (no passcode required).
###
MarkWest Energy Partners, L.P. is a master limited partnership engaged in the gathering, processing and transportation of natural gas; the gathering, transportation, fractionation, storage and marketing of natural gas liquids; and the gathering and transportation of crude oil. MarkWest has a leading presence in many unconventional gas plays including the Marcellus Shale, Utica Shale, Huron/Berea Shale, Haynesville Shale, Woodford Shale and Granite Wash formation.
This press release includes “forward-looking statements.” All statements other than statements of historical facts included or incorporated herein may constitute forward-looking statements. Actual results could vary significantly from those expressed or implied in such statements and are subject to a number of risks and uncertainties. Although MarkWest believes that the expectations reflected in the forward-looking statements are reasonable, MarkWest can give no assurance that such expectations will prove to be correct. The forward-looking statements involve risks and uncertainties that affect operations, financial performance, and other factors as discussed in filings with the Securities and Exchange Commission (SEC). Among the factors that could cause results to differ materially are those risks discussed in the periodic reports filed with the SEC, including MarkWest’s Annual Report on Form 10-K for the year ended December 31, 2013. You are urged to carefully review and consider the cautionary statements and other disclosures made in those filings, specifically those under the heading “Risk Factors.” MarkWest does not undertake any duty to update any forward-looking statement except as required by law.
MarkWest Energy Partners, L.P.
Financial Statistics
(unaudited, in thousands, except per unit data)
|
|
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Three months ended September 30, |
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Nine months ended September 30, |
| ||||||||
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|
|
2014 |
|
2013 |
|
2014 |
|
2013 |
| ||||
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Statement of Operations Data |
|
|
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|
|
|
|
|
| ||||
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|
|
|
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|
| ||||
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Revenue: |
|
$ |
595,257 |
|
$ |
450,834 |
|
$ |
1,636,819 |
|
$ |
1,219,713 |
|
|
Derivative gain (loss) |
|
11,829 |
|
(30,318 |
) |
1,109 |
|
(10,804 |
) | ||||
|
Total revenue |
|
607,086 |
|
420,516 |
|
1,637,928 |
|
1,208,909 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Operating expenses: |
|
|
|
|
|
|
|
|
| ||||
|
Purchased product costs |
|
246,801 |
|
191,672 |
|
674,189 |
|
499,588 |
| ||||
|
Derivative (gain) loss related to purchased product costs |
|
(13,564 |
) |
20,234 |
|
(9,398 |
) |
(10,902 |
) | ||||
|
Facility expenses |
|
83,579 |
|
77,542 |
|
250,829 |
|
199,849 |
| ||||
|
Derivative loss related to facility expenses |
|
1,128 |
|
2,332 |
|
2,905 |
|
2,800 |
| ||||
|
Selling, general and administrative expenses |
|
28,860 |
|
26,647 |
|
91,851 |
|
77,388 |
| ||||
|
Depreciation |
|
105,072 |
|
76,323 |
|
311,079 |
|
215,902 |
| ||||
|
Amortization of intangible assets |
|
16,313 |
|
16,003 |
|
48,256 |
|
47,925 |
| ||||
|
(Gain) loss on disposal of property, plant and equipment |
|
(766 |
) |
1,840 |
|
591 |
|
(35,758 |
) | ||||
|
Accretion of asset retirement obligations |
|
168 |
|
160 |
|
504 |
|
669 |
| ||||
|
Total operating expenses |
|
467,591 |
|
412,753 |
|
1,370,806 |
|
997,461 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Income from operations |
|
139,495 |
|
7,763 |
|
267,122 |
|
211,448 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
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Other (expense) income: |
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|
|
|
|
|
|
|
| ||||
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Equity in (loss) earnings from unconsolidated affiliates |
|
(1,555 |
) |
896 |
|
(2,026 |
) |
1,561 |
| ||||
|
Interest expense |
|
(39,448 |
) |
(38,889 |
) |
(123,823 |
) |
(114,180 |
) | ||||
|
Amortization of deferred financing costs and debt discount (a component of interest expense) |
|
(1,469 |
) |
(1,584 |
) |
(5,742 |
) |
(5,198 |
) | ||||
|
Loss on redemption of debt |
|
— |
|
— |
|
— |
|
(38,455 |
) | ||||
|
Miscellaneous income, net |
|
55 |
|
1,531 |
|
117 |
|
1,748 |
| ||||
|
Income (loss) before provision for income tax |
|
97,078 |
|
(30,283 |
) |
135,648 |
|
56,924 |
| ||||
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|
|
|
|
|
|
|
|
|
| ||||
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Provision for income tax expense (benefit): |
|
|
|
|
|
|
|
|
| ||||
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Current |
|
39 |
|
(2,344 |
) |
365 |
|
(10,503 |
) | ||||
|
Deferred |
|
10,991 |
|
(7,912 |
) |
20,271 |
|
23,087 |
| ||||
|
Total provision for income tax |
|
11,030 |
|
(10,256 |
) |
20,636 |
|
12,584 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Net income (loss) |
|
86,048 |
|
(20,027 |
) |
115,012 |
|
44,340 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Net (income) loss attributable to non-controlling interest |
|
(8,614 |
) |
(3,577 |
) |
(16,109 |
) |
297 |
| ||||
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|
|
|
|
|
|
|
|
|
| ||||
|
Net income (loss) attributable to the Partnership’s unitholders |
|
$ |
77,434 |
|
$ |
(23,604 |
) |
$ |
98,903 |
|
$ |
44,637 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
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Net income (loss) attributable to the Partnership’s common unitholders per common unit: |
|
|
|
|
|
|
|
|
| ||||
|
Basic |
|
$ |
0.43 |
|
$ |
(0.17 |
) |
$ |
0.58 |
|
$ |
0.32 |
|
|
Diluted |
|
$ |
0.41 |
|
$ |
(0.17 |
) |
$ |
0.54 |
|
$ |
0.29 |
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|
|
|
|
|
|
|
|
|
|
| ||||
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Weighted average number of outstanding common units: |
|
|
|
|
|
|
|
|
| ||||
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Basic |
|
176,757 |
|
142,352 |
|
166,792 |
|
134,115 |
| ||||
|
Diluted |
|
189,440 |
|
142,352 |
|
182,105 |
|
153,455 |
| ||||
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|
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Cash Flow Data |
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Net cash flow provided by (used in): |
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|
|
|
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|
|
|
| ||||
|
Operating activities |
|
$ |
139,257 |
|
$ |
153,063 |
|
$ |
496,080 |
|
$ |
330,659 |
|
|
Investing activities |
|
$ |
(609,887 |
) |
$ |
(751,286 |
) |
$ |
(1,615,045 |
) |
$ |
(2,186,307 |
) |
|
Financing activities |
|
$ |
269,254 |
|
$ |
571,822 |
|
$ |
1,131,696 |
|
$ |
1,838,045 |
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|
|
|
|
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Other Financial Data |
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|
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Distributable cash flow |
|
$ |
195,223 |
|
$ |
117,897 |
|
$ |
505,402 |
|
$ |
356,113 |
|
|
Adjusted EBITDA |
|
$ |
235,519 |
|
$ |
153,936 |
|
$ |
631,316 |
|
$ |
450,477 |
|
|
|
|
September 30, 2014 |
|
December 31, 2013 |
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|
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| ||
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Balance Sheet Data |
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Total assets |
|
$ |
10,561,565 |
|
$ |
9,396,423 |
|
|
|
|
|
|
Total debt |
|
$ |
3,549,521 |
|
$ |
3,023,071 |
|
|
|
|
|
|
Total equity |
|
$ |
5,673,358 |
|
$ |
4,798,133 |
|
|
|
|
|
MarkWest Energy Partners, L.P.
Operating Statistics
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|
|
Three months ended September 30, |
|
Nine months ended September 30, |
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|
|
2014 |
|
2013 |
|
2014 |
|
2013 |
|
|
Marcellus |
|
|
|
|
|
|
|
|
|
|
Gathering systems throughput (Mcf/d) |
|
702,300 |
|
563,200 |
|
634,800 |
|
617,200 |
|
|
Natural gas processed (Mcf/d) |
|
2,223,300 |
|
1,137,400 |
|
1,897,900 |
|
1,000,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
C2 (purity ethane) produced (Bbl/d) (1) |
|
55,200 |
|
— |
|
51,200 |
|
— |
|
|
C3+ NGLs fractionated (Bbl/d) (2) |
|
102,700 |
|
48,200 |
|
85,100 |
|
44,500 |
|
|
Total NGLs fractionated (Bbl/d) |
|
157,900 |
|
48,200 |
|
136,300 |
|
44,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Utica |
|
|
|
|
|
|
|
|
|
|
Gathering systems throughput (Mcf/d) |
|
322,300 |
|
85,100 |
|
231,100 |
|
47,100 |
|
|
Natural gas processed (Mcf/d) (3) |
|
459,800 |
|
131,100 |
|
335,700 |
|
62,200 |
|
|
C3+ NGLs fractionated (Bbl/d) (2) |
|
19,500 |
|
— |
|
16,100 |
|
— |
|
|
|
|
|
|
|
|
|
|
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|
Northeast |
|
|
|
|
|
|
|
|
|
|
Natural gas processed (Mcf/d) |
|
296,500 |
|
297,800 |
|
278,000 |
|
298,900 |
|
|
NGLs fractionated (Bbl/d) (4) |
|
20,200 |
|
21,500 |
|
18,400 |
|
18,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Keep-whole NGL sales (gallons, in thousands) |
|
30,400 |
|
28,200 |
|
87,400 |
|
92,600 |
|
|
Percent-of-proceeds NGL sales (gallons, in thousands) |
|
32,300 |
|
34,700 |
|
88,300 |
|
101,800 |
|
|
Total NGL sales (gallons, in thousands) (5) |
|
62,700 |
|
62,900 |
|
175,700 |
|
194,400 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil transported for a fee (Bbl/d) |
|
9,200 |
|
9,400 |
|
9,900 |
|
9,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Southwest |
|
|
|
|
|
|
|
|
|
|
East Texas gathering systems throughput (Mcf/d) |
|
591,800 |
|
494,300 |
|
546,100 |
|
505,000 |
|
|
East Texas natural gas processed (Mcf/d) (6) |
|
458,700 |
|
345,400 |
|
414,900 |
|
354,200 |
|
|
East Texas NGL sales (gallons, in thousands) (7) |
|
119,600 |
|
77,200 |
|
323,100 |
|
235,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Western Oklahoma gathering systems throughput (Mcf/d) (8) |
|
358,800 |
|
262,000 |
|
334,900 |
|
228,400 |
|
|
Western Oklahoma natural gas processed (Mcf/d) (9) |
|
298,600 |
|
218,500 |
|
279,500 |
|
198,400 |
|
|
Western Oklahoma NGL sales (gallons, in thousands) (7) |
|
54,500 |
|
64,400 |
|
165,800 |
|
162,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Southeast Oklahoma gathering systems throughput (Mcf/d) |
|
396,300 |
|
444,200 |
|
397,600 |
|
459,500 |
|
|
Southeast Oklahoma natural gas processed (Mcf/d) (10) |
|
176,700 |
|
156,700 |
|
170,300 |
|
156,100 |
|
|
Southeast Oklahoma NGL sales (gallons, in thousands) |
|
28,500 |
|
44,000 |
|
78,700 |
|
137,300 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Southwest gathering systems throughput (Mcf/d) (11) |
|
50,000 |
|
33,000 |
|
48,600 |
|
31,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast refinery off-gas processed (Mcf/d) |
|
117,200 |
|
117,100 |
|
113,300 |
|
110,100 |
|
|
Gulf Coast liquids fractionated (Bbl/d) (12) |
|
21,700 |
|
21,400 |
|
20,700 |
|
20,300 |
|
|
Gulf Coast NGL sales (gallons, in thousands) (12) |
|
83,800 |
|
82,800 |
|
237,100 |
|
232,500 |
|
(1) The Bluestone ethane fractionation facility began operations in June 2014. The volumes reported for 2014 are the average daily rate for the days of operation.
(2) The Marcellus segment includes both the Houston Fractionation Facility and Marcellus’ portion utilized of the jointly owned Hopedale Fractionation Facility. Hopedale is jointly owned by MarkWest Liberty Midstream and MarkWest Utica EMG, respectively. The Utica segment includes only the portion it utilized of the jointly owned Hopedale Fractionation Facility. Operations began in January 2014. The volumes reported for 2014 are the average daily rate for the days of operation.
(3) Utica operations began in August 2012 and have continued to grow. The volumes reported are the average daily rate for the days of operation.
(4) Includes NGLs fractionated for Utica and Marcellus segments.
(5) Represents sales at the Siloam fractionator. The total sales exclude approximately 18,255,000 gallons and 21,049,000 gallons sold by the Northeast on behalf of Marcellus for the three months ended September 30, 2014 and 2013, respectively. The total sales exclude approximately 40,265,000 gallons and 27,867,000 gallons sold by the Northeast on behalf of Marcellus for the nine months ended September 30, 2014 and 2013, respectively.
(6) Includes certain amounts in 2014 in excess of East Texas’ operating capacity that were processed by third-parties.
(7) Excludes gallons processed in conjunction with take in kind contracts for the three and nine months ended September 30, 2014 and September 30, 2013, respectively, as shown below.
|
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
| ||||
|
Gallons processed in conjunction with take in kind contracts |
|
2014 |
|
2013 |
|
2014 |
|
2013 |
|
|
East Texas |
|
— |
|
1,392,000 |
|
318,000 |
|
13,743,000 |
|
|
Western Oklahoma |
|
38,983,000 |
|
— |
|
88,001,000 |
|
— |
|
(8) 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.
(9) The Buffalo Creek plant began operations in February 2014.
(10) The natural gas processing in Southeast Oklahoma is outsourced to our joint venture Centrahoma or other third-party processors.
(11) Excludes lateral pipelines where revenue is not based on throughput.
(12) Excludes Hydrogen volumes.
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Operating Income before Items not Allocated to Segments
(unaudited, in thousands)
|
Three months ended September 30, 2014 |
|
Marcellus |
|
Utica |
|
Northeast |
|
Southwest |
|
Eliminations (1) |
|
Total |
| ||||||
|
Segment revenue |
|
$ |
230,241 |
|
$ |
47,520 |
|
$ |
52,120 |
|
$ |
276,666 |
|
$ |
(1,298 |
) |
$ |
605,249 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
Segment purchased product costs |
|
57,569 |
|
11,023 |
|
18,350 |
|
159,964 |
|
— |
|
246,906 |
| ||||||
|
Segment facility expenses |
|
36,171 |
|
14,150 |
|
9,515 |
|
32,267 |
|
(1,298 |
) |
90,805 |
| ||||||
|
Total operating expenses before items not allocated to segments |
|
93,740 |
|
25,173 |
|
27,865 |
|
192,231 |
|
(1,298 |
) |
337,711 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
Segment portion of operating income attributable to non-controlling interests |
|
— |
|
10,616 |
|
— |
|
5 |
|
— |
|
10,621 |
| ||||||
|
Operating income before items not allocated to segments |
|
$ |
136,501 |
|
$ |
11,731 |
|
$ |
24,255 |
|
$ |
84,430 |
|
$ |
— |
|
$ |
256,917 |
|
|
Three months ended September 30, 2013 |
|
Marcellus |
|
Utica |
|
Northeast |
|
Southwest |
|
Total |
| |||||
|
Segment revenue |
|
$ |
147,290 |
|
$ |
8,373 |
|
$ |
48,829 |
|
$ |
247,885 |
|
$ |
452,377 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
| |||||
|
Segment purchased product costs |
|
36,995 |
|
— |
|
15,330 |
|
139,347 |
|
191,672 |
| |||||
|
Segment facility expenses |
|
29,621 |
|
9,858 |
|
7,359 |
|
32,559 |
|
79,397 |
| |||||
|
Total operating expenses before items not allocated to segments |
|
66,616 |
|
9,858 |
|
22,689 |
|
171,906 |
|
271,069 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
Segment portion of operating (loss) income attributable to non-controlling interests |
|
— |
|
(599 |
) |
— |
|
40 |
|
(559 |
) | |||||
|
Operating income (loss) before items not allocated to segments |
|
$ |
80,674 |
|
$ |
(886 |
) |
$ |
26,140 |
|
$ |
75,939 |
|
$ |
181,867 |
|
(1) Amounts represent revenues and expenses associated with the Northeast segment fractionation completed on behalf of the Marcellus segment.
|
|
|
Three months ended September 30, |
| ||||
|
|
|
2014 |
|
2013 |
| ||
|
|
|
|
|
|
| ||
|
Operating income before items not allocated to segments |
|
$ |
256,917 |
|
$ |
181,867 |
|
|
Portion of operating income (loss) attributable to non-controlling interests |
|
6,065 |
|
(559 |
) | ||
|
Derivative gain (loss) not allocated to segments |
|
24,265 |
|
(52,884 |
) | ||
|
Revenue adjustment for unconsolidated affiliate |
|
(15,463 |
) |
— |
| ||
|
Revenue deferral adjustment and other |
|
5,471 |
|
(1,543 |
) | ||
|
Compensation expense included in facility expenses not allocated to segments |
|
(801 |
) |
(833 |
) | ||
|
Facility expense and purchase product cost adjustments for unconsolidated affiliate |
|
5,444 |
|
— |
| ||
|
Portion of operating loss attributable to non-controlling interests of an unconsolidated affiliate |
|
4,556 |
|
— |
| ||
|
Facility expenses adjustments |
|
2,688 |
|
2,688 |
| ||
|
Selling, general and administrative expenses |
|
(28,860 |
) |
(26,647 |
) | ||
|
Depreciation |
|
(105,072 |
) |
(76,323 |
) | ||
|
Amortization of intangible assets |
|
(16,313 |
) |
(16,003 |
) | ||
|
Gain (loss) on disposal of property, plant and equipment |
|
766 |
|
(1,840 |
) | ||
|
Accretion of asset retirement obligations |
|
(168 |
) |
(160 |
) | ||
|
Income from operations |
|
139,495 |
|
7,763 |
| ||
|
Other (expense) income: |
|
|
|
|
| ||
|
Equity in (loss) earnings from unconsolidated affiliates |
|
(1,555 |
) |
896 |
| ||
|
Interest expense |
|
(39,448 |
) |
(38,889 |
) | ||
|
Amortization of deferred financing costs and debt discount (a component of interest expense) |
|
(1,469 |
) |
(1,584 |
) | ||
|
Miscellaneous income, net |
|
55 |
|
1,531 |
| ||
|
Income (loss) before provision for income tax |
|
$ |
97,078 |
|
$ |
(30,283 |
) |
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Operating Income before Items not Allocated to Segments
(unaudited, in thousands)
|
Nine months ended September 30, 2014 |
|
Marcellus |
|
Utica |
|
Northeast |
|
Southwest |
|
Eliminations (1) |
|
Total |
| ||||||
|
Segment revenue |
|
$ |
589,134 |
|
$ |
102,112 |
|
$ |
157,150 |
|
$ |
807,136 |
|
$ |
(3,769 |
) |
$ |
1,651,763 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
Segment purchased product costs |
|
131,569 |
|
22,511 |
|
53,974 |
|
466,276 |
|
— |
|
674,330 |
| ||||||
|
Segment facility expenses |
|
105,399 |
|
38,176 |
|
25,138 |
|
99,143 |
|
(3,769 |
) |
264,087 |
| ||||||
|
Total operating expenses before items not allocated to segments |
|
236,968 |
|
60,687 |
|
79,112 |
|
565,419 |
|
(3,769 |
) |
938,417 |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
Segment portion of operating income attributable to non-controlling interests |
|
— |
|
18,439 |
|
— |
|
10 |
|
— |
|
18,449 |
| ||||||
|
Operating income before items not allocated to segments |
|
$ |
352,166 |
|
$ |
22,986 |
|
$ |
78,038 |
|
$ |
241,707 |
|
$ |
— |
|
$ |
694,897 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
Nine months ended September 30, 2013 |
|
Marcellus |
|
Utica |
|
Northeast |
|
Southwest |
|
Total |
|
|
| ||||||
|
Segment revenue |
|
$ |
375,844 |
|
$ |
12,590 |
|
$ |
151,530 |
|
$ |
684,093 |
|
$ |
1,224,057 |
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
Segment purchased product costs |
|
72,781 |
|
— |
|
50,118 |
|
376,689 |
|
499,588 |
|
|
| ||||||
|
Segment facility expenses |
|
74,529 |
|
20,232 |
|
20,538 |
|
91,027 |
|
206,326 |
|
|
| ||||||
|
Total operating expenses before items not allocated to segments |
|
147,310 |
|
20,232 |
|
70,656 |
|
467,716 |
|
705,914 |
|
|
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
Segment portion of operating (loss) income attributable to non-controlling interests |
|
— |
|
(3,081 |
) |
— |
|
157 |
|
(2,924 |
) |
|
| ||||||
|
Operating income (loss) before items not allocated to segments |
|
$ |
228,534 |
|
$ |
(4,561 |
) |
$ |
80,874 |
|
$ |
216,220 |
|
$ |
521,067 |
|
|
| |
(1) Amounts represent revenues and expenses associated with the Northeast segment fractionation completed on behalf of the Marcellus segment.
|
|
|
Nine months ended September 30, |
| ||||
|
|
|
2014 |
|
2013 |
| ||
|
|
|
|
|
|
| ||
|
Operating income before items not allocated to segments |
|
$ |
694,897 |
|
$ |
521,067 |
|
|
Portion of operating income (loss) attributable to non-controlling interests |
|
13,384 |
|
(2,924 |
) | ||
|
Derivative gain (loss) not allocated to segments |
|
7,602 |
|
(2,702 |
) | ||
|
Revenue adjustment for unconsolidated affiliate |
|
(19,296 |
) |
— |
| ||
|
Revenue deferral adjustment and other |
|
4,352 |
|
(4,344 |
) | ||
|
Compensation expense included in facility expenses not allocated to segments |
|
(2,707 |
) |
(1,587 |
) | ||
|
Facility expense and purchase product cost adjustments for unconsolidated affiliate |
|
8,042 |
|
— |
| ||
|
Portion of operating loss attributable to non-controlling interests of an unconsolidated affiliate |
|
5,065 |
|
— |
| ||
|
Facility expenses adjustments |
|
8,064 |
|
8,064 |
| ||
|
Selling, general and administrative expenses |
|
(91,851 |
) |
(77,388 |
) | ||
|
Depreciation |
|
(311,079 |
) |
(215,902 |
) | ||
|
Amortization of intangible assets |
|
(48,256 |
) |
(47,925 |
) | ||
|
(Loss) gain on disposal of property, plant and equipment |
|
(591 |
) |
35,758 |
| ||
|
Accretion of asset retirement obligations |
|
(504 |
) |
(669 |
) | ||
|
Income from operations |
|
267,122 |
|
211,448 |
| ||
|
Other (expense) income: |
|
|
|
|
| ||
|
Equity in (loss) earnings from unconsolidated affiliates |
|
(2,026 |
) |
1,561 |
| ||
|
Interest expense |
|
(123,823 |
) |
(114,180 |
) | ||
|
Amortization of deferred financing costs and debt discount (a component of interest expense) |
|
(5,742 |
) |
(5,198 |
) | ||
|
Loss on redemption of debt |
|
— |
|
(38,455 |
) | ||
|
Miscellaneous income, net |
|
117 |
|
1,748 |
| ||
|
Income before provision for income tax |
|
$ |
135,648 |
|
$ |
56,924 |
|
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Distributable Cash Flow
(unaudited, in thousands)
|
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
| ||||||||
|
|
|
2014 |
|
2013 |
|
2014 |
|
2013 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Net income (loss) |
|
$ |
86,048 |
|
$ |
(20,027 |
) |
$ |
115,012 |
|
$ |
44,340 |
|
|
Depreciation, amortization and other non-cash operating expenses |
|
121,631 |
|
92,564 |
|
360,942 |
|
264,730 |
| ||||
|
(Gain) loss on sale or disposal of property, plant and equipment |
|
(766 |
) |
1,840 |
|
591 |
|
(32,711 |
) | ||||
|
Loss on redemption of debt, net of tax benefit |
|
— |
|
— |
|
— |
|
36,178 |
| ||||
|
Amortization of deferred financing costs and debt discount |
|
1,469 |
|
1,584 |
|
5,742 |
|
5,198 |
| ||||
|
Equity in loss (earnings) from unconsolidated affiliates |
|
1,555 |
|
(896 |
) |
2,026 |
|
(1,561 |
) | ||||
|
Distributions from unconsolidated affiliates |
|
3,276 |
|
2,224 |
|
7,186 |
|
4,952 |
| ||||
|
Non-cash compensation expense |
|
1,646 |
|
1,924 |
|
7,448 |
|
5,464 |
| ||||
|
Unrealized (gain) loss on derivative instruments |
|
(25,186 |
) |
47,542 |
|
(18,162 |
) |
1,222 |
| ||||
|
Deferred income tax expense (benefit) |
|
10,991 |
|
(7,912 |
) |
20,271 |
|
23,087 |
| ||||
|
Cash adjustment for non-controlling interest of consolidated subsidiaries |
|
(5,330 |
) |
1,183 |
|
(10,626 |
) |
4,672 |
| ||||
|
Revenue deferral adjustment |
|
1,720 |
|
1,754 |
|
5,533 |
|
5,164 |
| ||||
|
Other (1) |
|
3,481 |
|
3,197 |
|
24,503 |
|
8,553 |
| ||||
|
Maintenance capital expenditures (2) |
|
(5,312 |
) |
(7,080 |
) |
(15,064 |
) |
(13,175 |
) | ||||
|
Distributable cash flow |
|
$ |
195,223 |
|
$ |
117,897 |
|
$ |
505,402 |
|
$ |
356,113 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
Maintenance capital expenditures (2) |
|
$ |
5,312 |
|
$ |
7,080 |
|
$ |
15,064 |
|
$ |
13,175 |
|
|
Growth capital expenditures of consolidated subsidiaries |
|
491,264 |
|
734,555 |
|
1,756,836 |
|
2,163,544 |
| ||||
|
Growth capital expenditures of unconsolidated subsidiary (3) |
|
148,165 |
|
— |
|
188,178 |
|
— |
| ||||
|
Total capital expenditures |
|
644,741 |
|
741,635 |
|
1,960,078 |
|
2,176,719 |
| ||||
|
Acquisitions, net of cash acquired |
|
— |
|
— |
|
— |
|
225,210 |
| ||||
|
Total capital expenditures and acquisitions |
|
644,741 |
|
741,635 |
|
1,960,078 |
|
2,401,929 |
| ||||
|
Joint venture partner contributions |
|
(273,003 |
) |
(91,163 |
) |
(393,109 |
) |
(716,982 |
) | ||||
|
Total capital expenditures and acquisitions, net |
|
$ |
371,738 |
|
$ |
650,472 |
|
$ |
1,566,969 |
|
$ |
1,684,947 |
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
Distributable cash flow |
|
$ |
195,223 |
|
$ |
117,897 |
|
$ |
505,402 |
|
$ |
356,113 |
|
|
Maintenance capital expenditures (2) |
|
5,312 |
|
7,080 |
|
15,064 |
|
13,175 |
| ||||
|
Changes in receivables, inventories and other assets |
|
(22,250 |
) |
(6,969 |
) |
(65,013 |
) |
(74,470 |
) | ||||
|
Changes in accounts payable, accrued liabilities and other long-term liabilities |
|
(41,545 |
) |
38,504 |
|
53,496 |
|
48,557 |
| ||||
|
Cash adjustment for non-controlling interest of consolidated subsidiaries |
|
5,330 |
|
(1,183 |
) |
10,626 |
|
(4,672 |
) | ||||
|
Other |
|
(2,813 |
) |
(2,266 |
) |
(23,495 |
) |
(8,044 |
) | ||||
|
Net cash provided by operating activities |
|
$ |
139,257 |
|
$ |
153,063 |
|
$ |
496,080 |
|
$ |
330,659 |
|
(1) Other includes amounts related to capitalized interest associated with joint venture capital expenditures and fees earned related to development of joint venture capital projects.
(2) Net of joint venture partner contributions.
(3) Growth capital expenditures for Ohio Gathering, L.L.C.
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Adjusted EBITDA
(unaudited, in thousands)
|
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
| ||||||||
|
|
|
2014 |
|
2013 |
|
2014 |
|
2013 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
|
Net income (loss) |
|
86,048 |
|
(20,027 |
) |
115,012 |
|
44,340 |
| ||||
|
Non-cash compensation expense |
|
1,646 |
|
1,924 |
|
7,448 |
|
5,464 |
| ||||
|
Unrealized (gain) loss on derivative instruments |
|
(25,186 |
) |
47,542 |
|
(18,162 |
) |
1,222 |
| ||||
|
Interest expense (1) |
|
38,856 |
|
38,356 |
|
123,339 |
|
112,988 |
| ||||
|
Depreciation, amortization and other non-cash operating expenses |
|
121,631 |
|
92,564 |
|
360,942 |
|
264,730 |
| ||||
|
(Gain) loss on disposal of property, plant and equipment |
|
(766 |
) |
1,840 |
|
591 |
|
(35,758 |
) | ||||
|
Loss on redemption of debt |
|
— |
|
— |
|
— |
|
38,455 |
| ||||
|
Provision for income tax expense (benefit) |
|
11,030 |
|
(10,256 |
) |
20,636 |
|
12,584 |
| ||||
|
Adjustment for cash flow from unconsolidated affiliates |
|
4,831 |
|
1,328 |
|
9,212 |
|
3,391 |
| ||||
|
Other (2) |
|
(2,571 |
) |
665 |
|
12,298 |
|
3,061 |
| ||||
|
Adjusted EBITDA |
|
$ |
235,519 |
|
$ |
153,936 |
|
$ |
631,316 |
|
$ |
450,477 |
|
(1) Includes amortization of deferred financing costs and debt discount, and excludes interest expense related to the Steam Methane Reformer.
(2) For the three and nine months ended September 30, 2014, Other includes amounts related to capitalized interest associated with joint venture capital expenditures and fees earned related to development of joint venture capital projects.
MarkWest Energy Partners, L.P.
Distributable Cash Flow Sensitivity Analysis
(unaudited, in millions)
The Partnership periodically estimates the effect on DCF resulting from changes in its volume forecast and NGL prices. The Partnership has become less sensitive to changes in commodity prices as a result of significant increases in fee-based income. For the full year 2015, the Partnership estimates that net operating margin will be approximately 80 percent fee-based.
The analysis further assumes derivative instruments outstanding as of November 4, 2014, and production volumes estimated through December 31, 2015.
|
Estimated Range of 2015 DCF | |||||||||||||
|
|
|
|
|
|
| ||||||||
|
|
|
|
|
Volume Forecast (1) |
| ||||||||
|
|
|
|
|
Low Case |
|
Base Case |
|
High Case |
| ||||
|
|
|
$ |
1.00 |
|
$ |
832 |
|
$ |
872 |
|
$ |
910 |
|
|
NGL |
|
$ |
0.95 |
|
$ |
814 |
|
$ |
854 |
|
$ |
892 |
|
|
$/Gal |
|
$ |
0.90 |
|
$ |
796 |
|
$ |
836 |
|
$ |
873 |
|
|
(2) (3) |
|
$ |
0.85 |
|
$ |
779 |
|
$ |
818 |
|
$ |
855 |
|
|
|
|
$ |
0.80 |
|
$ |
761 |
|
$ |
800 |
|
$ |
836 |
|
(1) Volume Forecast is increased/decreased by 5% in the Marcellus and Utica segments for the High and Low Cases.
(2) The composition is based on the Partnership’s projected NGL barrel of approximately: Ethane: 35%, Propane: 35%, Iso-Butane: 6%, Normal Butane: 12%, Natural Gasoline: 12%.
(3) Composite NGL prices are based on the Partnership’s average forecasted price.
The table is based on current information, expectations, and beliefs concerning future developments and their potential effects, and does not consider actions the Partnership’s management may take to mitigate exposure to changes. Further, the table does not consider the effects that such hypothetical adverse changes may have on overall economic activity. Historical volumes, prices and correlations do not guarantee future results.
Although the Partnership believes the expectations reflected in this analysis are reasonable, the Partnership can give no assurance that such expectations will prove to be correct and readers are cautioned that projected performance, results, or distributions may not be achieved. Actual changes in market prices, market conditions and constraints, production, NGL composition, infrastructure availability, market participants, and ratios between product prices may differ from the assumptions utilized in the analysis. Actual results, performance, distributions, volumes, events, or transactions could vary significantly from those expressed, considered or implied in this analysis. All results, performance, distributions, volumes, events or transactions are subject to a number of uncertainties and risks. Those uncertainties and risks may not be factored into or accounted for in this analysis. Readers are urged to carefully review and consider the cautionary statements and disclosures made in the Partnership’s periodic reports filed with the SEC, specifically those under the heading “Risk Factors.”