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 $148.4 million for the three months ended March 31, 2014, compared to $109.8 million for the three months ended March 31, 2013. DCF for the three months ended March 31, 2014 represents distribution coverage of 105 percent. The first quarter distribution of $141.4 million, or $0.87 per common unit, will be paid to unitholders on May 15, 2014. The first quarter 2014 distribution represents an increase of $0.01 per common unit or 1.2 percent over the fourth quarter 2013 distribution and an increase of $0.04 per common unit or 4.8 percent compared to the first 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 of $187.6 million for the three months ended March 31, 2014, compared to $140.8 million for the same period in 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 (loss) before provision for income tax for the three months ended March 31, 2014 of $28.5 million, compared to ($14.6) million for the same period in 2013. Income (loss) before provision for income tax includes non-cash gains associated with the change in fair value of derivative instruments of $11.8 million and $9.0 million for the three months ended March 31, 2014 and March 31, 2013, respectively, and a loss associated with the redemption of debt of $38.5 million for the three months ended March 31, 2013. Excluding these items, income before provision for income tax for the three months ended March 31, 2014 and 2013 would have been $16.7 million and $14.9 million, respectively.
“We are pleased to announce strong financial performance and record growth for the first quarter of 2014,” stated Frank Semple, Chairman, President and Chief Executive Officer. “Due to the ongoing success of our producer customers, we continue to expand our full service midstream infrastructure throughout the rich-gas areas of the Northeast Shales and in our key growth areas of Oklahoma and Texas. Our customers’ rich-gas production continues to accelerate and we expect that in 2014 our overall system processed volumes will increase by 60 percent over last year. We also anticipate that the continued ramp up of volumes and cash flow will provide opportunities for additional increases in distribution growth in 2015 and 2016.”
BUSINESS HIGHLIGHTS
Marcellus:
- In January 2014, the Partnership commenced operations of a NGL pipeline connecting the Hopedale fractionation and marketing complex in Harrison County, Ohio to the Partnership’s NGL infrastructure in the Marcellus Shale. By integrating MarkWest’s two industry-leading midstream systems in the Northeast, the Partnership has expanded fractionation capacity for its Marcellus producers.
- Yesterday, the Partnership announced that it will increase total processing capacity at the Mobley complex in Wetzel County, West Virginia to 920 million cubic feet per day (MMcf/d) with the construction of an additional 200 MMcf/d processing plant. The new plant is anchored by a long-term, fee-based contract with EQT Corporation (NYSE: EQT) and is expected to be in service by the second quarter of 2015. The Mobley complex currently consists of three plants with 520 MMcf/d of total processing capacity and during the fourth quarter of this year, MarkWest will begin operations of a fourth plant at the complex, increasing capacity to 720 MMcf/d. The Mobley complex supports growing Marcellus rich-gas production from EQT, Magnum Hunter Resources Corporation (NYSE: MHR), Stone Energy Corporation (NYSE: SGY), CONSOL Energy Inc. (NYSE: CNX), and Noble Energy, Inc. (NYSE: NBL).
- Yesterday, the Partnership announced that it will construct an additional 200 MMcf/d processing plant at the Sherwood complex in Doddridge County, West Virginia, at the request of Antero Resources Corporation (NYSE: AR) (Antero). The new plant is anchored by a long-term, fee-based contract and will expand total capacity at the Sherwood complex to 1.2 billion cubic feet (Bcf/d) by the second quarter of 2015. Antero continues to develop its prolific rich-gas acreage position in northern West Virginia and is the anchor producer supporting the Sherwood complex.
Utica:
- In January 2014, MarkWest Utica EMG and the Partnership commenced operations of the jointly-owned Hopedale fractionation and marketing complex (Hopedale complex) in Harrison County, Ohio. The Hopedale complex currently consists of a 60,000 barrels per day (Bbl/d) propane and heavier purity products (C3+) fractionator, over 230,000 barrels of purity product storage, truck loading facilities, and a 24-bay rail car loading facility with slots to accommodate 200 rail cars. The Hopedale complex is connected by NGL pipeline to MarkWest Utica EMG’s Cadiz processing complex in Harrison County, Ohio, to its Seneca processing complex in Noble County, Ohio, and to the Partnership’s extensive NGL gathering network in the Marcellus Shale.
- In February 2014, MarkWest Utica EMG commenced operations of Seneca II, a 200 MMcf/d processing plant at the Seneca complex in Noble County, Ohio. The Seneca complex currently consists of two cryogenic processing plants totaling 400 MMcf/d of capacity and is supported by long-term, fee-based agreements with Antero, Gulfport Energy Corporation (NASDAQ: GPOR), Rex Energy Corporation (NASDAQ: REXX), PDC Energy (NASDAQ: PDCE) and other producers. A third 200 MMcf/d plant at the complex was announced in May of 2013 and is expected to be completed during the second quarter of 2014.
- In February 2014, MarkWest Utica EMG announced the expansion of the Seneca complex with the development of a fourth 200 MMcf/d processing plant that is expected to be operational by the second quarter of 2015. The new plant is anchored by Antero under a long-term, fee-based contract and will expand total processing capacity of the complex to 800 MMcf/d.
Southwest:
- In February 2014, the Partnership announced the commencement of the 200 MMcf/d Buffalo Creek processing facility in Beckham County, Oklahoma, and associated gas gathering and compression assets in the Granite Wash. The new facility is supported by long-term, fee-based agreements with Chesapeake Energy Corporation (NYSE: CHK). The completion of the Buffalo Creek plant increases the Partnership’s total processing capacity in the Granite Wash to 435 MMcf/d at two major complexes.
- In April 2014, the Partnership’s Centrahoma Joint Venture (Centrahoma) with Atlas Pipeline Partners, L.P. (NYSE: APL) commenced operations of the Stonewall processing facility, a 120 MMcf/d plant in the Woodford Shale in Southwest Oklahoma. The completion of the Stonewall plant increases Centrahoma’s total processing capacity to 220 MMcf/d.
Capital Markets
- During the first quarter of 2014, the Partnership offered 4.2 million units and received net proceeds of approximately $271.9 million.
- Achieved investment grade rating on Credit Facility.
FINANCIAL RESULTS
Balance Sheet
- As of March 31, 2014, the Partnership had $123.1 million of cash and cash equivalents in wholly owned subsidiaries and $911.4 million of remaining capacity under its $1.3 billion revolving credit facility after consideration of $11.3 million of outstanding letters of credit and $377.3 million of outstanding borrowings.
Operating Results
-
Operating income before items not allocated to segments for the three
months ended March 31, 2014, was $217.8 million, an increase of $56.1
million when compared to $161.7 million over the same period in 2013.
This increase was primarily attributable to higher gathering and
processing volumes. Processed volumes continued to increase in the
first quarter of 2014, growing approximately 58 percent when compared
to the first 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) gains on commodity derivative instruments. Realized (losses) gains on commodity derivative instruments were ($7.7) million in the first quarter of 2014 and $1.8 million in the first quarter of 2013.
Capital Expenditures
- For the three months ended March 31, 2014, the Partnership’s portion of capital expenditures was $587.1 million.
2014 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST
For 2014, the Partnership forecasts DCF in a range of $600 million to $690 million based on its current forecast of operational volumes and prices for crude oil, natural gas, natural gas liquids and derivative instruments currently outstanding. 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 2014, the Partnership estimates that net operating margin will be over 70 percent fee-based. In addition, the Partnership has hedged approximately 62 percent of its forecasted 2014 NGL exposure on a volumetric basis, 90 percent of these with direct product hedges. An updated sensitivity analysis for forecasted 2014 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 2014 has been narrowed and is forecasted in a range of $2.0 billion to $2.3 billion. Maintenance capital is forecasted at approximately $25 million.
CONFERENCE CALL
The Partnership will host a conference call and webcast on Thursday, May 8, 2014, at 12:00 p.m. Eastern Time to review its first 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 first 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 (800) 688-2171 (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) | ||||||||||||
| Three months ended March 31, | ||||||||||||
| Statement of Operations Data | 2014 | 2013 | ||||||||||
| Revenue: | ||||||||||||
| Revenue | $ | 516,443 | $ | 373,458 | ||||||||
| Derivative loss | (3,967 | ) | (185 | ) | ||||||||
| Total revenue | 512,476 | 373,273 | ||||||||||
| Operating expenses: | ||||||||||||
| Purchased product costs | 211,564 | 152,557 | ||||||||||
| Derivative gain related to purchased product costs | (7,798 | ) | (10,704 | ) | ||||||||
| Facility expenses | 83,705 | 59,510 | ||||||||||
| Derivative gain related to facility expenses | (268 | ) | (332 | ) | ||||||||
| Selling, general and administrative expenses | 35,290 | 25,242 | ||||||||||
| Depreciation | 101,929 | 68,017 | ||||||||||
| Amortization of intangible assets | 15,978 | 14,830 | ||||||||||
| (Gain) loss on sale or disposal of property, plant and equipment | (93 | ) | 138 | |||||||||
| Accretion of asset retirement obligations | 168 | 352 | ||||||||||
| Total operating expenses | 440,475 | 309,610 | ||||||||||
| Income from operations | 72,001 | 63,663 | ||||||||||
| Other income (expense): | ||||||||||||
Equity in earnings from unconsolidated affiliates | 250 | 235 | ||||||||||
| Interest income | 9 | 149 | ||||||||||
| Interest expense | (40,984 | ) | (38,336 | ) | ||||||||
Amortization of deferred financing costs and debt discount (a component of interest expense) | (2,824 | ) | (1,830 | ) | ||||||||
| Loss on redemption of debt | - | (38,455 | ) | |||||||||
| Miscellaneous income, net | 10 | - | ||||||||||
| Income (loss) before provision for income tax | 28,462 | (14,574 | ) | |||||||||
| Provision for income tax expense (benefit): | ||||||||||||
| Current | 345 | (5,414 | ) | |||||||||
| Deferred | 12,201 | 11,971 | ||||||||||
| Total provision for income tax | 12,546 | 6,557 | ||||||||||
| Net income (loss) | 15,916 | (21,131 | ) | |||||||||
Net (income) loss attributable to non-controlling interest | (3,424 | ) | 5,673 | |||||||||
| Net income (loss) attributable to the Partnership's unitholders | $ | 12,492 | $ | (15,458 | ) | |||||||
| Net income (loss) attributable to the Partnership's common unitholders per common unit: | ||||||||||||
| Basic | $ | 0.08 | $ | (0.12 | ) | |||||||
| Diluted | $ | 0.07 | $ | (0.12 | ) | |||||||
| Weighted average number of outstanding common units: | ||||||||||||
| Basic | 158,808 | 128,615 | ||||||||||
| Diluted | 175,488 | 128,615 | ||||||||||
| Cash Flow Data | ||||||||||||
| Net cash flow provided by (used in): | ||||||||||||
| Operating activities | $ | 112,373 | $ | 83,758 | ||||||||
| Investing activities | $ | (575,474 | ) | $ | (609,361 | ) | ||||||
| Financing activities | $ | 501,277 | $ | 831,356 | ||||||||
| Other Financial Data | ||||||||||||
| Distributable cash flow | $ | 148,446 | $ | 109,825 | ||||||||
| Adjusted EBITDA | $ | 187,567 | $ | 140,801 | ||||||||
| Balance Sheet Data | March 31, 2014 | December 31, 2013 | ||||||||||
| Working capital | $ | (349,978 | ) | $ | (353,273 | ) | ||||||
| Total assets | $ | 9,942,247 | $ | 9,396,423 | ||||||||
| Total debt | $ | 3,400,554 | $ | 3,023,071 | ||||||||
| Total equity | $ | 5,042,731 | $ | 4,798,133 | ||||||||
| MarkWest Energy Partners, L.P. | ||||||||
| Operating Statistics | ||||||||
| Three months ended March 31, | ||||||||
| 2014 | 2013 | |||||||
| Marcellus | ||||||||
| Gathering system throughput (Mcf/d) (1) | 601,500 | 509,200 | ||||||
| Natural gas processed (Mcf/d) | 1,640,800 | 828,100 | ||||||
| C2 (purity ethane) produced (Bbl/d) | 46,200 | - | ||||||
| C3+ fractionated (Bbl/d) (2) | 70,300 | 37,000 | ||||||
| Total NGLs fractionated (Bbl/d) | 116,500 | 37,000 | ||||||
Utica | ||||||||
| Gathering system throughput (Mcf/d) | 180,600 | 9,000 | ||||||
Natural gas processed (Mcf/d) (3) | 251,300 | 7,900 | ||||||
| C3+ fractionated (Bbl/d) (2) | 12,100 | - | ||||||
| Northeast | ||||||||
| Natural gas processed (Mcf/d) | 255,600 | 302,600 | ||||||
| NGLs fractionated (Bbl/d) (4) | 17,400 | 17,100 | ||||||
| Keep-whole sales (gallons, in thousands) | 32,200 | 37,400 | ||||||
| Percent-of-proceeds sales (gallons, in thousands) | 26,000 | 34,900 | ||||||
| Total NGL sales (gallons, in thousands) (5) | 58,200 | 72,300 | ||||||
| Crude oil transported for a fee (Bbl/d) | 9,900 | 10,300 | ||||||
| Southwest | ||||||||
| East Texas gathering systems throughput (Mcf/d) | 495,800 | 500,300 | ||||||
| East Texas natural gas processed (Mcf/d) | 368,100 | 339,500 | ||||||
| East Texas NGL sales (gallons, in thousands) (6) | 93,900 | 72,200 | ||||||
| Western Oklahoma gathering system throughput (Mcf/d) (7) | 296,900 | 202,600 | ||||||
| Western Oklahoma natural gas processed (Mcf/d) | 250,100 | 186,300 | ||||||
| Western Oklahoma NGL sales (gallons, in thousands) (8) | 53,900 | 54,800 | ||||||
| Southeast Oklahoma gathering system throughput (Mcf/d) | 381,800 | 461,300 | ||||||
| Southeast Oklahoma natural gas processed (Mcf/d) (9) | 147,300 | 151,200 | ||||||
| Southeast Oklahoma NGL sales (gallons, in thousands) (10) | 21,000 | 39,300 | ||||||
| Other Southwest gathering system throughput (Mcf/d) (11) | 46,900 | 20,600 | ||||||
| Gulf Coast refinery off-gas processed (Mcf/d) | 110,500 | 95,300 | ||||||
| Gulf Coast liquids fractionated (Bbl/d) (12) | 19,300 | 17,200 | ||||||
| Gulf Coast NGL sales (gallons, in thousands) (12) | 73,000 | 65,100 | ||||||
| (1) | The 2013 volumes exclude Sherwood gathering for comparability as this system was sold to Summit in June 2013. | |||
| (2) | The Marcellus segment includes both the Houston Fractionation and Marcellus’ portion utilized of the jointly owned Hopedale Fractionation. Hopedale is currently jointly owned 60% and 40% by MarkWest Liberty Midstream and MarkWest Utica EMG, respectively. The Utica segment includes only the portion it utilized of the jointly owned Hopedale Fractionation. 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 2013. | |||
| (4) | Includes NGLs fractionated at Siloam on behalf of Utica and Marcellus segments. | |||
| (5) | Represents sales at the Siloam fractionator. The total sales exclude approximately 13,254,000 gallons and 207,000 gallons sold by the Northeast on behalf of Marcellus for the three months ended March 31, 2014 and 2013, respectively. | |||
| (6) | Excludes approximately 317,500 gallons and 8,362,300 gallons processed in conjunction with take in kind contracts for the three months ended March 31, 2014 and March 31, 2013, respectively. | |||
| (7) | 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. | |||
| (8) | Excludes approximately 11,716,200 gallons processed in conjunction with take in kind contracts for the three months ended March 31, 2014. | |||
| (9) | The natural gas processing in Southeast Oklahoma is outsourced to Centrahoma or other third-party processors. | |||
| (10) | Southeast Oklahoma processing facilities operated in ethane rejection during the three months ending March 31, 2014. | |||
| (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 March 31, 2014 | Marcellus | Utica | Northeast | Southwest | Eliminations (1) | Total | ||||||||||||||||||||||
| Segment revenue | $ | 175,159 | $ | 23,766 | $ | 61,253 | $ | 259,329 | $ | (1,571 | ) | $ | 517,936 | |||||||||||||||
| Operating expenses: | ||||||||||||||||||||||||||||
| Purchased product costs | 34,290 | 4,135 | 20,455 | 152,684 | - | 211,564 | ||||||||||||||||||||||
| Facility expenses | 35,473 | 11,852 | 7,114 | 32,521 | (1,571 | ) | 85,389 | |||||||||||||||||||||
| Total operating expenses before items not allocated to segments | 69,763 | 15,987 | 27,569 | 185,205 | (1,571 | ) | 296,953 | |||||||||||||||||||||
Portion of operating income (loss) attributable to non-controlling interests | - | 3,136 | - | (1 | ) | - | 3,135 | |||||||||||||||||||||
| Operating income before items not allocated to segments | $ | 105,396 | $ | 4,643 | $ | 33,684 | $ | 74,125 | $ | - | $ | 217,848 | ||||||||||||||||
| Three months ended March 31, 2013 | Marcellus | Utica | Northeast | Southwest | Total | |||||||||||||||||||||||
| Segment revenue | $ | 108,497 | $ | 623 | $ | 57,336 | $ | 208,366 | $ | 374,822 | ||||||||||||||||||
| Operating expenses: | ||||||||||||||||||||||||||||
| Purchased product costs | 18,793 | - | 19,662 | 114,102 | 152,557 | |||||||||||||||||||||||
| Facility expenses | 22,636 | 3,962 | 6,524 | 28,689 | 61,811 | |||||||||||||||||||||||
| Total operating expenses before items not allocated to segments | 41,429 | 3,962 | 26,186 | 142,791 | 214,368 | |||||||||||||||||||||||
| Portion of operating (loss) income attributable to non-controlling interests | - | (1,339 | ) | - | 64 | (1,275 | ) | |||||||||||||||||||||
| Operating income (loss) before items not allocated to segments | $ | 67,068 | $ | (2,000 | ) | $ | 31,150 | $ | 65,511 | $ | 161,729 | |||||||||||||||||
| (1) Amounts represent revenues and expenses associated with the Northeast segment fractionation completed on behalf of the Marcellus segment, which occurs when NGL volumes in the Marcellus exceed its fractionation capacity. | ||||||||||||||||||||||||||||
Three months ended March 31, | ||||||||||||||||||||||||||||
| 2014 | 2013 | |||||||||||||||||||||||||||
| Operating income before items not allocated to segments | $ | 217,848 | $ | 161,729 | ||||||||||||||||||||||||
| Portion of operating income (loss) attributable to non-controlling interests | 3,135 | (1,275 | ) | |||||||||||||||||||||||||
| Derivative gain not allocated to segments | 4,099 | 10,851 | ||||||||||||||||||||||||||
| Revenue deferral adjustment and other | (1,493 | ) | (1,364 | ) | ||||||||||||||||||||||||
| Compensation expense included in facility expenses not allocated to segments | (1,004 | ) | (387 | ) | ||||||||||||||||||||||||
| Facility expenses adjustments | 2,688 | 2,688 | ||||||||||||||||||||||||||
| Selling, general and administrative expenses | (35,290 | ) | (25,242 | ) | ||||||||||||||||||||||||
| Depreciation | (101,929 | ) | (68,017 | ) | ||||||||||||||||||||||||
| Amortization of intangible assets | (15,978 | ) | (14,830 | ) | ||||||||||||||||||||||||
| Gain (loss) on disposal of property, plant and equipment | 93 | (138 | ) | |||||||||||||||||||||||||
| Accretion of asset retirement obligations | (168 | ) | (352 | ) | ||||||||||||||||||||||||
| Income from operations | 72,001 | 63,663 | ||||||||||||||||||||||||||
| Other income (expense): | ||||||||||||||||||||||||||||
| Earnings from unconsolidated affiliates | 250 | 235 | ||||||||||||||||||||||||||
| Interest income | 9 | 149 | ||||||||||||||||||||||||||
| Interest expense | (40,984 | ) | (38,336 | ) | ||||||||||||||||||||||||
| Amortization of deferred financing costs and discount (a component of interest expense) | (2,824 | ) | (1,830 | ) | ||||||||||||||||||||||||
| Loss on redemption of debt | - | (38,455 | ) | |||||||||||||||||||||||||
| Miscellaneous income, net | 10 | - | ||||||||||||||||||||||||||
| Income (Loss) before provision for income tax | $ | 28,462 | $ | (14,574 | ) | |||||||||||||||||||||||
| Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure | ||||||||||||
| Distributable Cash Flow | ||||||||||||
| (unaudited, in thousands) | ||||||||||||
| Three months ended March 31, | ||||||||||||
| 2014 | 2013 | |||||||||||
| Net income (loss) | $ | 15,916 | $ | (21,131 | ) | |||||||
| Depreciation, amortization and other non-cash operating expenses | 118,950 | 83,277 | ||||||||||
(Gain) loss on sale or disposal of property, plant and equipment | (93 | ) | 138 | |||||||||
| Loss on redemption of debt, net of tax benefit | - | 36,178 | ||||||||||
| Amortization of deferred financing costs and debt discount | 2,824 | 1,830 | ||||||||||
Equity in earnings from unconsolidated affiliates | (250 | ) | (235 | ) | ||||||||
| Distributions from unconsolidated affiliates | 1,369 | 766 | ||||||||||
| Non-cash compensation expense | 3,967 | 2,384 | ||||||||||
| Unrealized gain on derivative instruments | (11,820 | ) | (9,033 | ) | ||||||||
| Deferred income taxes | 12,201 | 11,971 | ||||||||||
| Cash adjustment for non-controlling interest of consolidated subsidiaries | (2,118 | ) | 1,769 | |||||||||
| Revenue deferral adjustment | 2,091 | 1,765 | ||||||||||
| Other (1) | 8,155 | 2,037 | ||||||||||
| Maintenance capital expenditures (2) | (2,746 | ) | (1,891 | ) | ||||||||
| Distributable cash flow | $ | 148,446 | $ | 109,825 | ||||||||
| Maintenance capital expenditures (2) | $ | 2,746 | $ | 1,891 | ||||||||
| Growth capital expenditures | 584,374 | 629,667 | ||||||||||
| Total capital expenditures | 587,120 | 631,558 | ||||||||||
| Acquisitions, net of cash acquired | - | - | ||||||||||
| Total capital expenditures and acquisitions | 587,120 | 631,558 | ||||||||||
| Joint venture partner contributions | - | (265,320 | ) | |||||||||
| Total capital expenditures and acquisitions, net | $ | 587,120 | $ | 366,238 | ||||||||
| Distributable cash flow | $ | 148,446 | $ | 109,825 | ||||||||
| Maintenance capital expenditures (2) | 2,746 | 1,891 | ||||||||||
| Changes in receivables, inventories and other assets | (7,053 | ) | 1,266 | |||||||||
| Changes in accounts payable, accrued liabilities and other long-term liabilities | (25,714 | ) | (27,548 | ) | ||||||||
| Cash adjustment for non-controlling interest of consolidated subsidiaries | 2,118 | (1,769 | ) | |||||||||
| Other | (8,170 | ) | 93 | |||||||||
| Net cash provided by operating activities | $ | 112,373 | $ | 83,758 | ||||||||
(1) | For the three months ended March 31, 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. | |||
(2) | Net of joint venture partner contributions | |||
| MarkWest Energy Partners, L.P. | ||||||||
| Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure | ||||||||
| Adjusted EBITDA | ||||||||
| (unaudited, in thousands) | ||||||||
| Three months ended March 31, | ||||||||
| 2014 | 2013 | |||||||
| Net income (loss) | $ | 15,916 | $ | (21,131 | ) | |||
| Non-cash compensation expense | 3,967 | 2,384 | ||||||
| Unrealized gain on derivative instruments | (11,820 | ) | (9,033 | ) | ||||
| Interest expense (1) | 41,718 | 38,022 | ||||||
| Depreciation, amortization and other non-cash operating expenses | 118,950 | 83,277 | ||||||
(Gain) loss on sale or disposal of property, plant and equipment | (93 | ) | 138 | |||||
| Loss on redemption of debt | - | 38,455 | ||||||
| Provision for income tax | 12,546 | 6,557 | ||||||
| Adjustment for cash flow from unconsolidated affiliates | 1,119 | 531 | ||||||
Other (2) | 5,264 | 1,601 | ||||||
| Adjusted EBITDA | $ | 187,567 | $ | 140,801 | ||||
| (1) Includes amortization of deferred financing costs and discount, and excludes interest expense related to the Steam Methane Reformer. |
(2) For the three months ended March 31, 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 2014, the Partnership estimates that net operating margin will be over 70 percent fee-based. In addition, the Partnership has hedged approximately 62 percent of its forecasted 2014 NGL exposure on a volumetric basis, 90 percent of these with direct product hedges.
The analysis further assumes derivative instruments outstanding as of April 30, 2014, and production volumes estimated through December 31, 2014. The range of stated hypothetical changes in commodity prices considers current and historic market performance.
Estimated Range of 2014 DCF | ||||||||||||||||||||||||
| Volume Forecast (1) | ||||||||||||||||||||||||
| Low Case | Base Case | High Case | ||||||||||||||||||||||
| $ | 1.10 | $ | 619 | $ | 658 | $ | 694 | |||||||||||||||||
| NGL $/Gal | $ | 1.05 | $ | 613 | $ | 651 | $ | 686 | ||||||||||||||||
| (2) (3) | $ | 1.00 | $ | 606 | $ | 644 | $ | 679 | ||||||||||||||||
| $ | 0.95 | $ | 599 | $ | 636 | $ | 671 | |||||||||||||||||
| $ | 0.90 | $ | 592 | $ | 630 | $ | 664 | |||||||||||||||||
| (1) | Volume Forecast is increased/decreased by 10% in the Marcellus and Utica segments for the High and Low Cases. | ||
| (2) | The composition is based on the Partnership’s projected barrel of approximately: Ethane: 35%, Propane: 35%, Iso-Butane: 6%, Normal Butane: 12%, Natural Gasoline: 12%. | ||
| (3) | Composite NGL prices is 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. Nor does the table 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.”
Contacts:
Frank Semple, 866-858-0482
Chairman,
President & CEO
or
Nancy Buese, 866-858-0482
Executive
VP and CFO
or
Josh Hallenbeck, 866-858-0482
VP
of Finance & Treasurer
investorrelations@markwest.com
