MARKWEST ENERGY PARTNERS L P - FORM 10-Q - May 10, 2010
Attached files
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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ý |
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QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2010 |
OR |
o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period
from to
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Commission File Number 001-31239
MARKWEST ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
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Delaware |
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27-0005456 |
(State or other jurisdiction of
incorporation or organization) |
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(IRS Employer
Identification No.) |
1515 Arapahoe Street, Tower 2, Suite 700, Denver, Colorado 80202-2126
(Address of principal executive offices)
Registrant's
telephone number, including area code: 303-925-9200
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the
past 90 days. Yes ý Noo
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to
be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that
the registrant was required to submit and post such files). Yes o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
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Large accelerated filer ý |
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Accelerated filer o |
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Non-accelerated filer o (Do not check if a smaller
reporting company) |
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Smaller reporting company o |
Indicate
by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2 of the Exchange
Act). Yes o No ý
The number of the registrant's common units outstanding as of May 3, 2010, was 71,433,372.
Table of Contents
Throughout
this document we make statements that are classified as "forward-looking." Please refer to the "Forward-Looking Statements" included in Part I, Item 2 for an
explanation of these types of assertions. Also, in this document, unless the context requires otherwise, references to "we," "us," "our," "MarkWest Energy" or the "Partnership" are intended to mean
MarkWest Energy Partners, L.P., and its consolidated subsidiaries. References to "MarkWest Hydrocarbon" or the "Corporation" are intended to mean MarkWest Hydrocarbon, Inc., a
wholly-owned taxable subsidiary of the Partnership.
Table of Contents
Glossary of Terms
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Bbl |
|
Barrel |
Bbl/d |
|
Barrels per day |
Btu |
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One British thermal unit, an energy measurement |
Dth/d |
|
Dekatherms per day |
FASB |
|
Financial Accounting Standards Board |
FERC |
|
Federal Energy Regulatory Commission |
GAAP |
|
Accounting principles generally accepted in the United States of America |
Gal |
|
Gallon |
Gal/d |
|
Gallons per day |
LIBOR |
|
London Interbank Offered Rate |
Mcf/d |
|
One thousand cubic feet of natural gas per day |
MMBtu |
|
One million British thermal units, an energy measurement |
MMBtu/d |
|
One million British thermal units per day |
MMcf/d |
|
One million cubic feet of natural gas per day |
Net operating margin (a non-GAAP financial measure) |
|
Revenue, excluding any derivative gain (loss), less purchased product costs, excluding any derivative gain
(loss) |
NGL |
|
Natural gas liquids, such as ethane, propane, butanes and natural gasoline |
N/A |
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Not applicable |
OTC |
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Over-the-Counter |
SEC |
|
Securities and Exchange Commission |
VIE |
|
Variable interest entity |
VIEB |
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An asset balance attributable to consolidated VIEs that can only be used to settle obligations of the
consolidated VIEs or a liability balance attributable to consolidated VIEs for which creditors or beneficial interest holders do not have recourse to the general credit of the Partnership |
2002 LTIP |
|
2002 Long-Term Incentive Plan |
2006 Hydrocarbon Plan |
|
2006 Hydrocarbon Stock Incentive Plan |
2008 LTIP |
|
2008 Long-Term Incentive Plan |
1
Table of Contents
PART IFINANCIAL INFORMATION
Item 1. Financial Statements
MARKWEST ENERGY PARTNERS, L.P.
Condensed Consolidated Balance Sheets
(unaudited, in thousands)
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March 31, 2010 |
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December 31, 2009 |
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ASSETS |
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Current assets: |
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Cash and cash equivalents, including VIEB of $54,944 and $21,942, respectively |
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$ |
105,175 |
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$ |
97,752 |
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Receivables, net, including VIEB of $27,845 and $22,033, respectively |
|
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147,237 |
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140,969 |
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Inventories, including VIEB of $2,243 and $3,343, respectively |
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19,926 |
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29,075 |
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Fair value of derivative instruments |
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8,002 |
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8,821 |
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Deferred income taxes |
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12,228 |
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12,228 |
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Other current assets, including VIEB of $360 and $327, respectively |
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4,578 |
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10,674 |
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Total current assets |
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297,146 |
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299,519 |
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Property, plant and equipment, including VIEB of $552,309 and $494,918, respectively |
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2,248,762 |
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2,154,644 |
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Less: accumulated depreciation, including VIEB of $16,854 and $11,324, respectively |
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(201,092 |
) |
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(173,000 |
) |
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Total property, plant and equipment, net |
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2,047,670 |
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1,981,644 |
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Other long-term assets: |
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Investment in unconsolidated affiliate |
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29,565 |
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29,633 |
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Intangibles, net of accumulated amortization of $93,928 and $83,735, respectively |
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644,218 |
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654,411 |
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Goodwill |
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9,421 |
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9,421 |
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Deferred financing costs, net of accumulated amortization of $8,034 and $6,990, respectively |
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19,984 |
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21,027 |
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Deferred contract cost, net of accumulated amortization of $1,716 and $1,638, respectively |
|
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1,534 |
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|
1,612 |
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Fair value of derivative instruments |
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9,968 |
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15,810 |
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Other long-term assets, including VIEB of $300 and $314, respectively |
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1,624 |
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1,660 |
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Total assets |
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$ |
3,061,130 |
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$ |
3,014,737 |
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LIABILITIES AND EQUITY |
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Current liabilities: |
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Accounts payable, including VIEB of $6,426 and $2,745, respectively |
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$ |
112,639 |
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$ |
87,832 |
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Accrued liabilities, including VIEB of $50,199 and $44,615, respectively |
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139,190 |
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137,687 |
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Fair value of derivative instruments |
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63,544 |
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60,464 |
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Total current liabilities |
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315,373 |
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285,983 |
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Deferred income taxes |
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9,662 |
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11,034 |
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Fair value of derivative instruments |
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55,103 |
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62,519 |
|
Long-term debt, net of discounts of $37,828 and $39,417, respectively |
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1,165,306 |
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1,170,072 |
|
Other long-term liabilities, including VIEB of $372 and $365, respectively |
|
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108,486 |
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105,736 |
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Commitments and contingencies (Note 9) |
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Equity: |
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MarkWest Energy Partners, L.P. partners' capital (66,546 and 66,275 common units outstanding, respectively) |
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1,079,017 |
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1,096,654 |
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Non-controlling interest in consolidated subsidiaries |
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328,183 |
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282,739 |
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Total equity |
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1,407,200 |
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1,379,393 |
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Total liabilities and equity |
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$ |
3,061,130 |
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$ |
3,014,737 |
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The accompanying notes are an integral part of these condensed consolidated financial statements.
2
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Condensed Consolidated Statements of Operations
(unaudited, in thousands, except per unit amounts)
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Three months ended
March 31, |
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2010 |
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2009 |
|
Revenue: |
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Revenue |
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$ |
315,615 |
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$ |
183,367 |
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Derivative (loss) gain |
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(7,236 |
) |
|
8,304 |
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Total revenue |
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308,379 |
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191,671 |
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Operating expenses: |
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Purchased product costs |
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144,296 |
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|
102,314 |
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Derivative loss related to purchased product costs |
|
|
13,389 |
|
|
29,513 |
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Facility expenses |
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37,905 |
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|
31,444 |
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|
Derivative gain related to facility expenses |
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|
(806 |
) |
|
(371 |
) |
|
Selling, general and administrative expenses |
|
|
21,508 |
|
|
15,927 |
|
|
Depreciation |
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|
28,187 |
|
|
20,943 |
|
|
Amortization of intangible assets |
|
|
10,193 |
|
|
10,233 |
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|
(Gain) loss on disposal of property, plant and equipment |
|
|
(9 |
) |
|
729 |
|
|
Accretion of asset retirement obligations |
|
|
143 |
|
|
47 |
|
|
|
|
|
|
|
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Total operating expenses |
|
|
254,806 |
|
|
210,779 |
|
|
|
|
|
|
|
|
|
Income (loss) from operations |
|
|
53,573 |
|
|
(19,108 |
) |
Other income (expense): |
|
|
|
|
|
|
|
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Loss from unconsolidated affiliates |
|
|
(68 |
) |
|
(105 |
) |
|
Interest income |
|
|
386 |
|
|
41 |
|
|
Interest expense |
|
|
(23,782 |
) |
|
(17,782 |
) |
|
Amortization of deferred financing costs and discount (a component of interest expense) |
|
|
(2,612 |
) |
|
(1,391 |
) |
|
Derivative gain related to interest expense |
|
|
1,871 |
|
|
|
|
|
Miscellaneous income (expense), net |
|
|
1,062 |
|
|
(662 |
) |
|
|
|
|
|
|
|
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Income (loss) before provision for income tax |
|
|
30,430 |
|
|
(39,007 |
) |
Provision for income tax expense (benefit): |
|
|
|
|
|
|
|
|
Current |
|
|
5,798 |
|
|
6,253 |
|
|
Deferred |
|
|
(1,372 |
) |
|
(15,591 |
) |
|
|
|
|
|
|
|
|
Total provision for income tax |
|
|
4,426 |
|
|
(9,338 |
) |
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
26,004 |
|
|
(29,669 |
) |
Net (income) loss attributable to non-controlling interest |
|
|
(4,494 |
) |
|
20 |
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to the Partnership |
|
$ |
21,510 |
|
$ |
(29,649 |
) |
|
|
|
|
|
|
Net income (loss) attributable to the Partnership's common unitholders per common unit (Note 12): |
|
|
|
|
|
|
|
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Basic |
|
$ |
0.32 |
|
$ |
(0.53 |
) |
|
|
|
|
|
|
|
Diluted |
|
$ |
0.32 |
|
$ |
(0.53 |
) |
|
|
|
|
|
|
Weighted average number of outstanding common units: |
|
|
|
|
|
|
|
|
Basic |
|
|
66,453 |
|
|
56,806 |
|
|
|
|
|
|
|
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Diluted |
|
|
66,453 |
|
|
56,806 |
|
|
|
|
|
|
|
Cash distribution declared per common unit |
|
$ |
0.64 |
|
$ |
0.64 |
|
|
|
|
|
|
|
The accompanying notes are an integral part of these condensed consolidated financial statements.
3
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Condensed Consolidated Statements of Changes in Equity
(unaudited, in thousands)
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MarkWest Energy
Partners, L.P.
Unitholders |
|
|
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|
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Common
Units |
|
Partners'
Capital |
|
Non-controlling
Interest |
|
Total |
|
December 31, 2009 |
|
|
66,275 |
|
$ |
1,096,654 |
|
$ |
282,739 |
|
$ |
1,379,393 |
|
Share-based compensation activity |
|
|
271 |
|
|
3,622 |
|
|
|
|
|
3,622 |
|
Excess tax benefits related to share-based compensation |
|
|
|
|
|
97 |
|
|
|
|
|
97 |
|
Distributions paid |
|
|
|
|
|
(42,866 |
) |
|
(1,270 |
) |
|
(44,136 |
) |
Contributions to MarkWest Liberty Midstream joint venture, net |
|
|
|
|
|
|
|
|
42,220 |
|
|
42,220 |
|
Net income |
|
|
|
|
|
21,510 |
|
|
4,494 |
|
|
26,004 |
|
|
|
|
|
|
|
|
|
|
|
March 31, 2010 |
|
|
66,546 |
|
$ |
1,079,017 |
|
$ |
328,183 |
|
$ |
1,407,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MarkWest Energy
Partners, L.P.
Unitholders |
|
|
|
|
|
|
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Common
Units |
|
Partners'
Capital |
|
Non-controlling
Interest |
|
Total |
|
December 31, 2008 |
|
|
56,640 |
|
$ |
1,204,458 |
|
$ |
3,301 |
|
$ |
1,207,759 |
|
Share-based compensation activity |
|
|
254 |
|
|
1,762 |
|
|
|
|
|
1,762 |
|
Distributions paid |
|
|
|
|
|
(36,803 |
) |
|
|
|
|
(36,803 |
) |
Contributions to MarkWest Liberty Midstream joint venture, net |
|
|
|
|
|
(5,464 |
) |
|
50,000 |
|
|
44,536 |
|
Net loss |
|
|
|
|
|
(29,649 |
) |
|
(20 |
) |
|
(29,669 |
) |
|
|
|
|
|
|
|
|
|
|
March 31, 2009 |
|
|
56,894 |
|
$ |
1,134,304 |
|
$ |
53,281 |
|
$ |
1,187,585 |
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these condensed consolidated financial statements.
4
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Condensed Consolidated Statements of Cash Flows
(unaudited, in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
March 31, |
|
|
|
2010 |
|
2009 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
26,004 |
|
$ |
(29,669 |
) |
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
Depreciation |
|
|
28,187 |
|
|
20,943 |
|
|
|
Amortization of intangible assets |
|
|
10,193 |
|
|
10,233 |
|
|
|
Amortization of deferred financing costs and discount |
|
|
2,612 |
|
|
1,391 |
|
|
|
Accretion of asset retirement obligations |
|
|
143 |
|
|
47 |
|
|
|
Amortization of deferred contract cost |
|
|
78 |
|
|
78 |
|
|
|
Phantom unit compensation expense |
|
|
6,285 |
|
|
2,703 |
|
|
|
Equity in loss of unconsolidated affiliates |
|
|
68 |
|
|
105 |
|
|
|
Unrealized loss on derivative instruments |
|
|
2,269 |
|
|
66,918 |
|
|
|
(Gain) loss on disposal of property, plant and equipment |
|
|
(9 |
) |
|
729 |
|
|
|
Deferred income taxes |
|
|
(1,372 |
) |
|
(15,591 |
) |
|
|
Gain on sale of trading securities |
|
|
|
|
|
(40 |
) |
|
|
Net sales of trading securities |
|
|
|
|
|
552 |
|
|
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
Receivables |
|
|
(5,968 |
) |
|
21,531 |
|
|
|
Inventories |
|
|
9,149 |
|
|
20,634 |
|
|
|
Other current assets |
|
|
6,096 |
|
|
1,620 |
|
|
|
Accounts payable and accrued liabilities |
|
|
28,507 |
|
|
(6,683 |
) |
|
|
Other long-term assets |
|
|
36 |
|
|
(4,073 |
) |
|
|
Other long-term liabilities |
|
|
2,082 |
|
|
392 |
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
114,360 |
|
|
91,820 |
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(95,322 |
) |
|
(168,942 |
) |
|
Equity investments |
|
|
|
|
|
(4,984 |
) |
|
Proceeds from disposal of property, plant and equipment |
|
|
292 |
|
|
|
|
|
Change in restricted cash |
|
|
|
|
|
(1,125 |
) |
|
|
|
|
|
|
|
|
|
Net cash flows used in investing activities |
|
|
(95,030 |
) |
|
(175,051 |
) |
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Proceeds from revolving credit facility |
|
|
135,604 |
|
|
234,700 |
|
|
Payments of revolving credit facility |
|
|
(141,904 |
) |
|
(125,000 |
) |
|
Payments for debt issuance costs, deferred financing costs and registration costs |
|
|
|
|
|
(4,323 |
) |
|
Contributions to MarkWest Liberty Midstream joint venture, net |
|
|
42,220 |
|
|
44,536 |
|
|
Payments of SMR liability |
|
|
(58 |
) |
|
|
|
|
Cash paid for taxes related to net settlement of share-based payment awards |
|
|
(3,730 |
) |
|
(1,199 |
) |
|
Excess tax benefits related to share-based compensation |
|
|
97 |
|
|
|
|
|
Payment of distributions to common unitholders |
|
|
(42,866 |
) |
|
(36,803 |
) |
|
Payment of distributions to non-controlling interest |
|
|
(1,270 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flows (used in) provided by financing activities |
|
|
(11,907 |
) |
|
111,911 |
|
|
|
|
|
|
|
Net increase in cash |
|
|
7,423 |
|
|
28,680 |
|
Cash and cash equivalents at beginning of year |
|
|
97,752 |
|
|
3,321 |
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
105,175 |
|
$ |
32,001 |
|
|
|
|
|
|
|
The accompanying notes are an integral part of these condensed consolidated financial statements.
5
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements
(unaudited)
1. Organization and Basis of Presentation
MarkWest Energy Partners, L.P. was formed in January 2002 as a Delaware limited partnership. The Partnership is engaged in the gathering, transportation and processing of natural
gas; the transportation, fractionation, marketing and storage of NGLs; and the gathering and transportation of crude oil. The Partnership has extensive natural gas gathering, processing and
transmission operations in the southwest, Gulf Coast, and northeast regions of the United States, including the Marcellus Shale, and is the largest natural gas processor in the Appalachian region.
These
unaudited condensed consolidated financial statements have been prepared in accordance with the rules and regulations of the SEC for interim financial reporting. Accordingly,
certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted. These condensed consolidated financial
statements should be read in conjunction with the Partnership's consolidated financial statements included in the Partnership's Annual Report on Form 10-K for the year ended
December 31, 2009. In management's opinion, the Partnership has made all adjustments necessary for a fair presentation of its results of operations, financial position and cash flows for the
periods shown. These adjustments are of a normal recurring nature. Finally, consider that results for the three months ended March 31, 2010 are not necessarily indicative of results for the
full year 2010, or any other future period.
The
Partnership's unaudited condensed consolidated financial statements include all majority-owned or majority-controlled subsidiaries. In addition, MarkWest Liberty Midstream &
Resources L.L.C. ("MarkWest Liberty Midstream") and MarkWest Pioneer, L.L.C. ("MarkWest Pioneer"), variable interest entities for which the Partnership has been determined to be the primary
beneficiary, are included in the condensed consolidated financial statements (see Note 3 for further discussion of MarkWest Liberty Midstream and MarkWest Pioneer). All significant intercompany
investments, accounts and transactions have been eliminated. Investments in which the Partnership exercises significant influence but does not control, and is not the primary beneficiary, are
accounted for using the equity method.
2. Recent Accounting Pronouncements
In June 2009, the FASB amended the VIE subsections of the consolidation guidance. The amended guidance changes the criteria for determining if a VIE exists and whether or not a VIE
should be consolidated. The amended guidance was effective for the Partnership on January 1, 2010, and the Partnership reconsidered its previous VIE conclusions and financial statement
disclosures. The amendment had no effect on the Partnership's condensed consolidated financial statements.
In
September 2009, the FASB amended the accounting guidance for revenue recognition for multiple-deliverable arrangements. The amended guidance establishes a hierarchy for determining
the selling price of each individual deliverable and eliminates the residual value method of allocating the selling price. The amended guidance is effective prospectively for all revenue arrangements
entered into or materially modified in fiscal years beginning after June 15, 2010. The amendment is not expected to have a material effect on the Partnership's condensed consolidated financial
statements.
In
February 2010, the FASB amended the embedded derivative and hedging guidance. The amended guidance modified the requirements for determining whether an embedded derivative is clearly
and closely related to the host contract. The amended embedded derivative guidance was
6
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
2. Recent Accounting Pronouncements (Continued)
effective
for the Partnership on January 1, 2010. The amended guidance had no effect on the Partnership's condensed consolidated financial statements.
In
March 2010, the FASB amended the exception for embedded credit derivatives in the derivatives and hedging guidance. The amended guidance clarified which types of embedded credit
derivative features are required to be analyzed for potential bifurcation. The amended guidance is effective for the Partnership on July 1, 2010. The Partnership is currently evaluating the
effect of the amended guidance on the Partnership's condensed consolidated financial statements.
3. Variable Interest Entities
MarkWest Liberty Midstream operates in the natural gas midstream business in and around the Marcellus Shale in western Pennsylvania and
northern West Virginia. Equity interests in the entity are owned 60% by the Partnership and 40% by M&R MWE Liberty, LLC ("M&R"), an affiliate of The Energy & Minerals Group and its
affiliated funds, which prior to March 15, 2010 was named Midstream & Resources Funds, until December 31, 2010. Effective January 1, 2011 the equity interests in the entity
will be owned 51% and 49% by the Partnership and M&R, respectively. A wholly-owned subsidiary of the Partnership serves as the operator and provides field
operating and general and administrative services for a fee, a portion of which is fixed. The Partnership's Liberty segment includes the results of operations of MarkWest Liberty Midstream (see
Note 13).
The
Partnership and M&R will jointly fund the capital requirements of MarkWest Liberty Midstream at agreed upon levels until the Partnership's contributed capital is proportionate to its
eventual 51% ownership interest (the "Equalization Date"), which is expected to occur on or before December 31, 2012. The Partnership is required to reinvest all cash distributions from
MarkWest Liberty Midstream until the Equalization Date has occurred. During 2010, M&R will contribute at least $150.0 million to MarkWest Liberty Midstream and the Partnership will fund all
capital expenditures in excess of M&R's contributions. MarkWest Liberty Midstream's capital plan for 2011 and 2012 has not been finalized and the exact timing of the members' contributions is
currently uncertain. If the Equalization Date has not occurred by the end of 2012, M&R may require the Partnership to contribute the amount of the shortfall at December 31, 2012, or may allow
the Partnership to continue to fund up to 100% of MarkWest Liberty Midstream's capital expenditures until its total contributed capital is proportionate to its ownership interest. Following the
Equalization Date, M&R will have pre-emptive rights to maintain its ownership interest in MarkWest Liberty Midstream in a range of between 45% and 49% or have its ownership interest
diluted to the extent that it elects not to fund its proportionate share.
As
of March 31, 2010, the capital contributed to MarkWest Liberty Midstream is disproportionate to each member's respective ownership interest. Under the terms of the joint
venture agreement, M&R received a special $2.3 million non-cash allocation of net income from MarkWest Liberty Midstream during the first quarter of 2010 because the capital M&R
contributed exceeded its ownership interest by $89.3 million. The non-cash allocation is recorded in Net (income) loss attributable to
non-controlling interest.
7
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
3. Variable Interest Entities (Continued)
MarkWest Pioneer is the owner and operator of the Arkoma Connector Pipeline, a 50-mile FERC-regulated pipeline
that was placed in service in July 2009. The Arkoma Connector Pipeline interconnects with the Midcontinent Express Pipeline and the Gulf Crossing Pipeline and is designed to provide approximately
638,000 Dth/d of Arkoma Basin takeaway capacity. A wholly-owned subsidiary of the Partnership serves as the operator and provides field operating and general and administrative services for fixed
fees. The Partnership's Southwest segment includes the results of operations of MarkWest Pioneer (see Note 13).
Equity
interests in the entity are shared equally by the members. The Partnership was obligated to fund all capital expenditures necessary to complete construction of the Arkoma
Connector Pipeline in excess of $125.0 million. As of March 31, 2010, the carrying value of the Partnership's ownership interest exceeds its stated ownership interest in MarkWest Pioneer
by approximately $2.0 million. The difference between the carrying value of the Partnership's ownership interest and its stated ownership interest is amortized based upon the respective useful
lives of the assets to which the difference relates.
The Partnership has determined that MarkWest Liberty Midstream and MarkWest Pioneer are both VIEs primarily due to the Partnership's
disproportionate economic interests as compared to its voting interests in each entity. The Partnership has made capital contributions to both entities that differ from its stated ownership interests.
Additionally, MarkWest Liberty Midstream has insufficient equity at risk, as evidenced by the additional capital funding requirements discussed above.
Although
voting interests are shared equally between the respective members in both MarkWest Liberty Midstream and MarkWest Pioneer, the Partnership has concluded that it is the primary
beneficiary of both entities based on its affiliate's role as the operator. The Partnership believes that its role as the operator along with its equity interests give it the power to direct the
activities that most significantly affect the economic performance of each VIE.
As the primary beneficiary of MarkWest Liberty Midstream and MarkWest Pioneer, the Partnership consolidates the entities and recognizes
non-controlling interests. The following tables show
8
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
3. Variable Interest Entities (Continued)
the
assets and liabilities attributable to VIEs as of March 31, 2010 and December 31, 2009 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of March 31, 2010 |
|
|
|
MarkWest Liberty
Midstream |
|
MarkWest
Pioneer |
|
Total |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
52,038 |
|
$ |
2,906 |
|
$ |
54,944 |
|
|
Accounts receivable |
|
|
26,556 |
|
|
1,289 |
|
|
27,845 |
|
|
Inventories |
|
|
2,243 |
|
|
|
|
|
2,243 |
|
|
Other current assets |
|
|
258 |
|
|
102 |
|
|
360 |
|
|
Property, plant and equipment, net of accumulated depreciation of $12,236 and $4,618, respectively |
|
|
383,278 |
|
|
152,177 |
|
|
535,455 |
|
|
Other long-term assets |
|
|
300 |
|
|
|
|
|
300 |
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
464,673 |
|
$ |
156,474 |
|
$ |
621,147 |
|
|
|
|
|
|
|
|
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
6,398 |
|
$ |
28 |
|
$ |
6,426 |
|
|
Accrued liabilities |
|
|
49,284 |
|
|
915 |
|
|
50,199 |
|
|
Other long-term liabilities |
|
|
82 |
|
|
290 |
|
|
372 |
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
$ |
55,764 |
|
$ |
1,233 |
|
$ |
56,997 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009 |
|
|
|
MarkWest Liberty
Midstream |
|
MarkWest
Pioneer |
|
Total |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
18,168 |
|
$ |
3,774 |
|
$ |
21,942 |
|
|
Accounts receivable |
|
|
20,753 |
|
|
1,280 |
|
|
22,033 |
|
|
Inventories |
|
|
3,343 |
|
|
|
|
|
3,343 |
|
|
Other current assets |
|
|
225 |
|
|
102 |
|
|
327 |
|
|
Property, plant and equipment, net of accumulated depreciation of $8,273 and $3,051, respectively |
|
|
330,116 |
|
|
153,478 |
|
|
483,594 |
|
|
Other long-term assets |
|
|
314 |
|
|
|
|
|
314 |
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
372,919 |
|
$ |
158,634 |
|
$ |
531,553 |
|
|
|
|
|
|
|
|
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
2,713 |
|
$ |
32 |
|
$ |
2,745 |
|
|
Accrued liabilities |
|
|
43,136 |
|
|
1,479 |
|
|
44,615 |
|
|
Other long-term liabilities |
|
|
80 |
|
|
285 |
|
|
365 |
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
$ |
45,929 |
|
$ |
1,796 |
|
$ |
47,725 |
|
|
|
|
|
|
|
|
|
9
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
3. Variable Interest Entities (Continued)
The
assets of the VIEs are the property of the respective entities and are not available to the Partnership for any other purpose, including collateral for its secured debt (see
Note 7 and Note 14). The liabilities of the VIEs do not represent additional claims against the Partnership's general assets. The cash flow information for MarkWest Liberty Midstream and
MarkWest Pioneer comprise substantially all of the cash flow information of the Partnership's non-guarantor subsidiaries (see Note 14). The Partnership's maximum exposure to loss as
a result of its involvement with the VIEs includes its equity investment, any additional capital contribution commitments and any operating expense incurred by the subsidiary operator in excess of its
subsidiary's compensation for the performance of those services. The Partnership did not provide any financial support to the VIEs that it was not contractually obligated to provide during the three
months ended March 31, 2010 and 2009.
The
following table shows the net income (loss) attributable to the Partnership and transfers to the non-controlling interest for the three months ended March 31, 2010
and 2009 (in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31, |
|
|
|
2010 |
|
2009 |
|
Net income (loss) attributable to the Partnership |
|
$ |
21,510 |
|
$ |
(29,649 |
) |
|
Transfers to the non-controlling interest: |
|
|
|
|
|
|
|
|
|
Decrease in Partners' Capital for transaction costs related to sale of 40% interest in Liberty Midstream |
|
|
|
|
|
(5,464 |
) |
|
|
|
|
|
|
Net income (loss) attributable to the Partnership and transfers to the non-controlling interest |
|
$ |
21,510 |
|
$ |
(35,113 |
) |
|
|
|
|
|
|
4. Derivative Financial Instruments
The Partnership's primary risk management objective is to reduce downside volatility in its cash flows arising from changes in
commodity prices related to future sales or purchases of natural gas, NGLs and crude oil. Swaps, options and fixed price forward contracts may allow the Partnership to reduce downside volatility in
its realized margins as realized losses or gains on the derivative instruments generally are offset by corresponding gains or losses in the Partnership's sales or purchases of physical product. While
management largely expects realized derivative gains and losses to be offset by increases or decreases in the value of physical sales and purchases, the Partnership will experience volatility in
reported earnings due to the recording of unrealized gains and losses on derivative positions that will have no offset. The Partnership's commodity derivative instruments are recorded at fair value in
the Condensed Consolidated Balance Sheets. Accordingly, the volatility in any given period related to unrealized gains or losses reported in the Condensed Consolidated Statements of Operations can be
significant to the overall financial results of the Partnership; however, management generally expects those gains and losses to be offset when they become realized. The Partnership does not have any
trading derivative financial instruments.
To
mitigate its cash flow exposure to fluctuations in the price of NGLs, the Partnership has entered into derivative financial instruments relating to the future price of NGLs and crude
oil. To
10
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
4. Derivative Financial Instruments (Continued)
mitigate
its cash flow exposure to fluctuations in the price of natural gas, the Partnership primarily utilizes derivative financial instruments relating to the future price of natural gas. As a
result of these transactions, the Partnership has mitigated a significant portion of its expected commodity price risk with agreements expiring at various times through the fourth quarter of 2012. The
Partnership has a
committee comprised of the senior management team that oversees risk management activity and continually monitors the risk management program and expects to continue to adjust its derivative positions
as conditions warrant.
To
manage its commodity price risk, the Partnership utilizes a combination of swaps, options and fixed price forward contracts available on the OTC market. The Partnership enters into
OTC derivatives with financial institutions and other energy company counterparties. Management conducts a standard credit review on counterparties and has agreements containing collateral
requirements when deemed necessary. The Partnership uses standardized agreements that allow for offset of positive and negative exposures (master netting arrangements).
The
use of derivative instruments may create exposure to the risk of financial loss in certain circumstances, including instances when (i) NGLs do not trade at historical levels
relative to crude oil, (ii) physical sales volumes are less than expected or (iii) OTC counterparties fail to purchase or deliver the contracted quantities of natural gas, NGLs or crude
oil or otherwise fail to perform. To the extent that the Partnership engages in derivative activities, it may be prevented from realizing the benefits of favorable price changes in the physical
market; however, it may be insulated against unfavorable changes in such prices.
The
Partnership's amended credit agreement (the "Partnership Credit Agreement") limits its ability to enter into financial derivative transactions with parties that require margin calls
and prevents members of the participating bank group from requiring margin calls. As of March 31, 2010 approximately 5% of the Partnership's financial derivative positions, measured
volumetrically, are with non-bank group counterparties and are subject to margin deposit requirements under OTC agreements that it meets with letters of credit, if necessary. In the
unlikely event that the Partnership was unable to meet these margin calls with letters of credit, it would be forced to terminate the corresponding contracts.
The senior notes issued in 2009 contain two contingent written put options. The written put options are considered embedded derivatives
and are not considered clearly and closely related to the indenture governing the notes. When a hybrid contract contains more than one embedded derivative requiring separate accounting, the embedded
derivatives must be aggregated and accounted for as one compound embedded derivative. The initial fair value of the compound embedded derivative in the indenture was recorded as a component of Long-term debt in the Condensed Consolidated Balance Sheets with a corresponding increase in the recorded balance of the original issue
discount.
During the first quarter of 2010, the Partnership terminated all of its outstanding interest rate swap contracts. The financial
statement impact is disclosed in the tables below.
11
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
4. Derivative Financial Instruments (Continued)
See Note 5 for a description of how the Partnership values its derivative instruments. There were no material changes to its
policy regarding the accounting for these instruments as previously disclosed in the Partnership's 2009 Annual Report on Form 10-K. The impact of the Partnership's derivative
instruments on its Condensed Consolidated Balance Sheets is summarized below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives |
|
Liability Derivatives |
|
Derivative contracts not designated as hedging
instruments and their balance sheet location
|
|
Fair Value at
March 31, 2010 |
|
Fair Value at
December 31, 2009 |
|
Fair Value at
March 31, 2010 |
|
Fair Value at
December 31, 2009 |
|
Commodity contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of derivative instrumentscurrent |
|
$ |
8,002 |
|
$ |
8,312 |
|
$ |
(63,544 |
) |
$ |
(60,464 |
) |
|
Fair value of derivative instrumentslong-term |
|
|
9,968 |
|
|
15,810 |
|
|
(55,103 |
) |
|
(62,519 |
) |
Interest rate contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of derivative instrumentscurrent |
|
|
|
|
|
509 |
|
|
|
|
|
|
|
Embedded derivative in debt contract |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
|
|
|
|
|
|
(134 |
) |
|
(190 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
17,970 |
|
$ |
24,631 |
|
$ |
(118,781 |
) |
$ |
(123,173 |
) |
|
|
|
|
|
|
|
|
|
|
12
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
4. Derivative Financial Instruments (Continued)
The
impact of the Partnership's derivative instruments on its Condensed Consolidated Statements of Operations is summarized below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
March 31, |
|
Derivative contracts not designated as hedging instruments
and the location of gain or (loss) recognized in income
|
|
2010 |
|
2009 |
|
Revenue: Derivative (loss) gain |
|
|
|
|
|
|
|
|
Realized (loss) gain |
|
$ |
(13,129 |
) |
$ |
61,114 |
|
|
Unrealized gain (loss) |
|
|
5,893 |
|
|
(52,810 |
) |
|
|
|
|
|
|
|
|
Total Revenue: derivative (loss) gain |
|
|
(7,236 |
) |
|
8,304 |
|
|
|
|
|
|
|
Derivative loss related to purchased product costs |
|
|
|
|
|
|
|
|
Realized loss |
|
|
(5,438 |
) |
|
(16,250 |
) |
|
Unrealized loss |
|
|
(7,951 |
) |
|
(13,263 |
) |
|
|
|
|
|
|
|
|
Total derivative loss related to purchased product costs |
|
|
(13,389 |
) |
|
(29,513 |
) |
|
|
|
|
|
|
Derivative gain related to facility expenses |
|
|
|
|
|
|
|
|
Unrealized gain |
|
|
806 |
|
|
371 |
|
Derivative gain related to interest expense |
|
|
|
|
|
|
|
|
Realized gain |
|
|
2,380 |
|
|
|
|
|
Unrealized loss |
|
|
(509 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total derivative gain related to interest expense |
|
|
1,871 |
|
|
|
|
|
|
|
|
|
|
Miscellaneous income (expense), net |
|
|
|
|
|
|
|
|
Unrealized gain |
|
|
56 |
|
|
|
|
|
|
|
|
|
|
|
|
Total loss |
|
$ |
(17,892 |
) |
$ |
(20,838 |
) |
|
|
|
|
|
|
At
March 31, 2010, the fair value of the Partnership's commodity derivative contracts is inclusive of premium payments of $7.1 million, net of amortization. For the three
months ended March 31, 2010 and 2009, the Realized (loss) gainrevenue includes amortization of premium payments of
$0.6 million and $1.2 million, respectively.
During
the first quarter of 2009, the Partnership settled a portion of its derivative positions covering 2009, 2010, and 2011 for $15.2 million of net realized gains. The
settlement was completed prior to the contractual settlement to improve liquidity and to mitigate credit risk with certain counterparties, and as such did not represent trading activity. The
settlement was recorded as a $26.5 million realized gain in Realized (loss) gainrevenue and an $11.3 million realized loss
included in Derivative loss related to purchased product costs in the accompanying Condensed Consolidated Statements of Operations.
The Partnership has a contractual arrangement with one non-bank group counterparty that contains a credit risk contingent
feature. The Partnership has OTC swap and put positions with this counterparty. This arrangement contains provisions that if the Partnership's credit rating for its
13
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
4. Derivative Financial Instruments (Continued)
long-term
senior unsecured debt, as announced by Moody's Investors Service, Inc. and Standard & Poor's Corporation were to decline below B3 or B-, respectively,
the Partnership would be required to post additional collateral in the amount of 15% of all outstanding transactions if the contract value of all outstanding transactions was in a net liability
position. The Partnership has a standard master netting arrangement with this counterparty. As of March 31, 2010 the Partnership has a net liability position of $1.1 million with this
counterparty. The Partnership has posted additional collateral with the counterparty through a letter of credit due to a restriction in the Partnership Credit Agreement which does not allow cash
collateral.
The following tables provide information on the volume of the Partnership's derivative activity for positions related to long liquids
and keep-whole price risk at March 31, 2010, including the weighted average prices ("WAVG"):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI Crude Collars
|
|
Volumes
(Bbl/d) |
|
WAVG Floor
(Per Bbl) |
|
WAVG Cap
(Per Bbl) |
|
Fair Value
(in thousands) |
|
2010 |
|
|
1,297 |
|
$ |
66.48 |
|
$ |
74.49 |
|
$ |
(4,033 |
) |
2011 |
|
|
2,495 |
|
|
70.06 |
|
|
86.95 |
|
|
(4,880 |
) |
2012 |
|
|
822 |
|
|
60.00 |
|
|
85.87 |
|
|
(2,944 |
) |
|
|
|
|
|
|
|
|
|
|
|
WTI Crude Puts
|
|
Volumes
(Bbl/d) |
|
WAVG Floor
(Per Bbl) |
|
Fair Value
(in thousands) |
|
2010 |
|
|
1,288 |
|
$ |
80.00 |
|
$ |
1,525 |
|
2011 |
|
|
1,818 |
|
|
80.00 |
|
|
5,229 |
|
|
|
|
|
|
|
|
|
|
|
|
WTI Crude Swaps
|
|
Volumes
(Bbl/d) |
|
WAVG Price
(Per Bbl) |
|
Fair Value
(in thousands) |
|
2010 |
|
|
3,290 |
|
$ |
70.68 |
|
$ |
(12,358 |
) |
2011 |
|
|
1,570 |
|
|
78.54 |
|
|
(4,166 |
) |
2012 |
|
|
1,221 |
|
|
78.50 |
|
|
(3,463 |
) |
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Swaps
|
|
Volumes
(MMBtu/d) |
|
WAVG Price
(Per MMBtu) |
|
Fair Value
(in thousands) |
|
2010 |
|
|
5,186 |
|
$ |
5.68 |
|
$ |
(2,138 |
) |
|
|
|
|
|
|
|
|
|
|
|
IsoButane Swaps
|
|
Volumes
(Gal/d) |
|
WAVG Price
(Per Gal) |
|
Fair Value
(in thousands) |
|
2010 |
|
|
5,525 |
|
$ |
1.35 |
|
$ |
(271 |
) |
|
|
|
|
|
|
|
|
|
|
|
Natural Gasoline Swaps
|
|
Volumes
(Gal/d) |
|
WAVG Price
(Per Gal) |
|
Fair Value
(in thousands) |
|
2010 |
|
|
10,898 |
|
$ |
1.66 |
|
$ |
(582 |
) |
14
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
4. Derivative Financial Instruments (Continued)
|
|
|
|
|
|
|
|
|
|
|
Normal Butane Swaps
|
|
Volumes
(Gal/d) |
|
WAVG Price
(Per Gal) |
|
Fair Value
(in thousands) |
|
2010 |
|
|
8,983 |
|
$ |
1.29 |
|
$ |
(215 |
) |
|
|
|
|
|
|
|
|
|
|
|
Propane Swaps
|
|
Volumes
(Gal/d) |
|
WAVG Price
(Per Gal) |
|
Fair Value
(in thousands) |
|
2010 |
|
|
27,374 |
|
$ |
1.04 |
|
$ |
(578 |
) |
The
following tables provide information on the volume of the Partnership's taxable subsidiary's commodity derivative activity for positions related to keep-whole price risk
at March 31, 2010, including the WAVG:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI Crude Collars
|
|
Volumes
(Bbl/d) |
|
WAVG Floor
(Per Bbl) |
|
WAVG Cap
(Per Bbl) |
|
Fair Value
(in thousands) |
|
2012 |
|
|
648 |
|
$ |
70.00 |
|
$ |
91.85 |
|
$ |
(1,158 |
) |
|
|
|
|
|
|
|
|
|
|
|
WTI Crude Swaps
|
|
Volumes
(Bbl/d) |
|
WAVG Price
(Per Bbl) |
|
Fair Value
(in thousands) |
|
2010 |
|
|
2,782 |
|
$ |
74.47 |
|
$ |
(7,761 |
) |
2011 |
|
|
3,150 |
|
|
87.27 |
|
|
1,267 |
|
2012 (Jan) |
|
|
2,142 |
|
|
91.50 |
|
|
306 |
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Swaps
|
|
Volumes
(MMBtu/d) |
|
WAVG Price
(Per MMBtu) |
|
Fair Value
(in thousands) |
|
2010 |
|
|
9,992 |
|
$ |
9.39 |
|
$ |
(13,754 |
) |
2011 |
|
|
15,429 |
|
|
8.79 |
|
|
(18,056 |
) |
2012 |
|
|
4,225 |
|
|
7.08 |
|
|
(1,786 |
) |
The Partnership has a commodity contract with a producer in the Appalachia region that creates a floor on the frac spread for gas
purchases of 9,000 Dth/d. The primary term of the commodity contract, a component of a broader regional arrangement, expired on December 31, 2009 but the producer exercised its right to extend
the processing agreement and the commodity contract through the first quarter of 2015. The fair value of the commodity contract is marked based on an index price through Derivative loss related to purchased product
costs. As of March 31, 2010, the estimated fair value of this contract was a liability of
$31.4 million.
The
Partnership has a commodity contract that gives it an option to fix a component of the utilities cost to an index price on electricity at one of its plant locations. The value of the
derivative component of this contract is marked to market through Derivative gain related to facility expenses. As of March 31, 2010, the
estimated fair value of this contract was an asset of $0.6 million.
15
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
5. Fair Value
Fair value measurements and disclosures relate primarily to the Partnership's derivative instruments discussed in Note 4. The derivative contracts are measured at fair value on a
recurring basis and classified within Level 2 and Level 3 of the valuation hierarchy. The Level 2 and Level 3 measurements are obtained using a market approach. LIBOR rates
are an observable input for the measurement of all derivative contracts. The measurements for all commodity contracts contain observable inputs in the form of forward prices based on WTI crude oil
prices; Columbia Appalachia, Henry Hub and Houston Ship Channel natural gas prices; Mont Belvieu and Conway NGL prices; and ERCOT electricity prices. Level 2 instruments include crude oil and
natural gas swap contracts; the valuations are based on the appropriate commodity prices and contain no significant unobservable inputs. Level 3 instruments include crude oil options, all NGL
transactions, embedded derivatives in commodity contracts and the embedded put options. The significant unobservable inputs for crude oil options, NGL transactions and embedded derivatives in
commodity contracts include option volatilities and commodity prices interpolated and extrapolated due to inactive markets. The significant unobservable inputs for the embedded put options are option
volatilities and management's assumptions about the probability of specific events occurring in the future.
The
methods and assumptions described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Furthermore,
while the Partnership believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of
certain financial instruments could result in a different estimate of fair value at the reporting date.
The
following table presents the derivative instruments carried at fair value as of March 31, 2010 and December 31, 2009 (in thousands):
|
|
|
|
|
|
|
|
|
As of March 31, 2010
|
|
Assets |
|
Liabilities |
|
Significant other observable inputs (Level 2) |
|
|
|
|
|
|
|
|
Commodity contracts |
|
$ |
8,010 |
|
$ |
(69,919 |
) |
Significant unobservable inputs (Level 3) |
|
|
|
|
|
|
|
|
Commodity contracts |
|
|
9,413 |
|
|
(17,320 |
) |
|
Embedded derivatives in commodity contracts |
|
|
547 |
|
|
(31,408 |
) |
|
Embedded derivative in debt contract |
|
|
|
|
|
(134 |
) |
|
|
|
|
|
|
Total carrying value in Condensed Consolidated Balance Sheet |
|
$ |
17,970 |
|
$ |
(118,781 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009
|
|
Assets |
|
Liabilities |
|
Significant other observable inputs (Level 2) |
|
|
|
|
|
|
|
|
Commodity contracts |
|
$ |
9,920 |
|
$ |
(63,242 |
) |
Significant unobservable inputs (Level 3) |
|
|
|
|
|
|
|
|
Commodity contracts |
|
|
14,202 |
|
|
(25,542 |
) |
|
Embedded derivatives in commodity contracts |
|
|
|
|
|
(34,199 |
) |
|
Interest rate contracts |
|
|
509 |
|
|
|
|
|
Embedded derivative in debt contract |
|
|
|
|
|
(190 |
) |
|
|
|
|
|
|
Total carrying value in Condensed Consolidated Balance Sheet |
|
$ |
24,631 |
|
$ |
(123,173 |
) |
|
|
|
|
|
|
16
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
5. Fair Value (Continued)
Changes in Level 3 Fair Value Measurements
The table below includes a rollforward of the balance sheet amounts for the three months ended March 31, 2010 and 2009 for
assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, 2010 |
|
March 31, 2009 |
|
|
|
Commodity
Derivative
Contracts
(net) |
|
Embedded
Derivatives in
Commodity
Contracts
(net) |
|
Interest
Rate
Contracts |
|
Embedded
Derivative
in Debt
Contract |
|
Commodity
Derivative
Contracts
(net) |
|
Embedded
Derivatives in
Commodity
Contracts
(net) |
|
Fair value at beginning of period |
|
$ |
(11,340 |
) |
$ |
(34,199 |
) |
$ |
509 |
|
$ |
(190 |
) |
$ |
72,478 |
|
$ |
(22 |
) |
Total gain or loss (realized and unrealized) included in earnings(1) |
|
|
(2,758 |
) |
|
936 |
|
|
1,871 |
|
|
56 |
|
|
1,430 |
|
|
(2,455 |
) |
Purchases, sales, issuances and settlements (net) |
|
|
6,191 |
|
|
2,402 |
|
|
(2,380 |
) |
|
|
|
|
(19,967 |
) |
|
208 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value at end of period |
|
$ |
(7,907 |
) |
$ |
(30,861 |
) |
$ |
|
|
$ |
(134 |
) |
$ |
53,941 |
|
$ |
(2,269 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still
held at March 31(1) |
|
$ |
(3,521 |
) |
$ |
3,338 |
|
$ |
|
|
$ |
56 |
|
$ |
(5,063 |
) |
$ |
(2,247 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- (1)
- Gains
and losses on Commodity Derivative Contracts classified as Level 3 are recorded in Derivative (loss) gain related to
revenue. Gains and losses on Embedded Derivatives in Commodity Contracts are recorded in purchased product costs and facility expenses. Gains on Embedded Derivatives in Debt
Contracts are recorded in Miscellaneous income (expense), net. Gains and losses on Interest Rate Contracts are recorded in Derivative gain related to interest
expense.
6. Inventories
Inventories consist of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
March 31, 2010 |
|
December 31, 2009 |
|
Natural gas and natural gas liquids |
|
$ |
13,095 |
|
$ |
20,939 |
|
Spare parts |
|
|
6,831 |
|
|
8,136 |
|
|
|
|
|
|
|
|
Total inventories |
|
$ |
19,926 |
|
$ |
29,075 |
|
|
|
|
|
|
|
17
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
7. Long-Term Debt
Debt is summarized below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2010 |
|
December 31, 2009 |
|
Credit Facility |
|
|
|
|
|
|
|
|
Revolving credit facility, 5.25% interest at March 31, 2010 and December 31, 2009, due February 2012 |
|
$ |
53,000 |
|
$ |
59,300 |
|
Senior Notes(1) |
|
|
|
|
|
|
|
|
Senior Notes, 6.875% interest, net of discount of $7,685 and $8,089, respectively, issued October 2004 and due November 2014 |
|
|
217,315 |
|
|
216,911 |
|
|
Senior Notes, 6.875% interest, net of discount of $28,392 and $29,515, respectively, issued May 2009 and due November 2014(2) |
|
|
121,742 |
|
|
120,674 |
|
|
Senior Notes, 8.5% interest, net of discount of $732 and $762, respectively, issued July 2006 and due July 2016 |
|
|
274,268 |
|
|
274,238 |
|
|
Senior Notes, 8.75% interest, net of discount of $1,019 and $1,051, respectively, issued April and May 2008 and due April 2018 |
|
|
498,981 |
|
|
498,949 |
|
|
|
|
|
|
|
|
|
Total long-term debt |
|
$ |
1,165,306 |
|
$ |
1,170,072 |
|
|
|
|
|
|
|
- (1)
- The
estimated aggregate fair value of the Senior Notes was approximately $1,158.2 million and $1,152.9 million as of March 31, 2010 and
December 31, 2009, respectively, based on quoted market prices.
- (2)
- Includes
fair value of written put options of approximately $0.1 million (see Note 4).
Under the provisions of the Partnership Credit Agreement, the Partnership is subject to a number of restrictions and covenants. These
covenants are used to calculate the available borrowing capacity on a quarterly basis. The credit facility is guaranteed and collateralized by substantially all of the Partnership's assets and those
of its wholly-owned subsidiaries. As of March 31, 2010, the Partnership had $53.0 million of borrowings outstanding and $37.5 million of letters of credit outstanding under the
revolving credit facility, leaving approximately $345.1 million available for borrowing.
8. Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
Distribution Per
Common Unit |
|
Declaration Date |
|
Ex-Dividend Date |
|
Record Date |
|
Payment Date |
|
March 31, 2010 |
|
$ |
0.64 |
|
|
April 22, 2010 |
|
|
April 29, 2010 |
|
|
May 3, 2010 |
|
|
May 14, 2010 |
|
December 31, 2009 |
|
$ |
0.64 |
|
|
January 26, 2010 |
|
|
February 3, 2010 |
|
|
February 5, 2010 |
|
|
February 12, 2010 |
|
18
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
9. Commitments and Contingencies
The Partnership is subject to a variety of risks and disputes, and is a party to various legal proceedings in the normal course of its
business. The Partnership maintains insurance policies in amounts and with coverage and deductibles as it believes reasonable and prudent. However, the Partnership cannot assure that the insurance
companies will promptly honor their policy obligations or that the coverage or levels of insurance will be adequate to protect the Partnership from all material expenses related to future claims for
property loss or business interruption to the Partnership, or for third-party claims of personal and property damage, or that the coverages or levels of insurance it currently has will be available in
the future at economical prices. While it is not possible to predict the outcome of the legal actions with certainty, management is of the opinion that appropriate provisions and accruals for
potential losses associated with all legal actions have been made in the condensed consolidated financial statements.
In
June 2006, the Office of Pipeline Safety ("OPS") issued a Notice of Probable Violation and Proposed Civil Penalty ("NOPV") (CPF No. 2-2006-5001) to both
MarkWest Hydrocarbon and Equitable Production Company ("Equitable"). The NOPV is associated with the pipeline leak and an ensuing explosion and fire that occurred on November 8, 2004 in Ivel,
Kentucky on an NGL pipeline owned by Equitable and leased and operated by a subsidiary, MarkWest Energy Appalachia, L.L.C. The NOPV sets forth six counts of violations of applicable regulations, and a
proposed civil penalty in the aggregate amount of $1.1 million. An administrative hearing on the matter, previously set for the last week of March 2007, was postponed to allow the
administrative record to be produced and to allow OPS an opportunity to respond to MarkWest's and Equitable's motions to dismiss count one of the NOPV, which involves $0.8 million of the
$1.1 million proposed penalty. This count arises out of alleged activity in 1982 and 1987, which predates MarkWest's leasing and operation of the pipeline. MarkWest believes it has viable and
mitigating defenses to the remaining counts and will vigorously defend all applicable assertions of violations. The administrative hearing request was withdrawn by MarkWest and Equitable in October
2009, and the parties are waiting for
initial resolution on the briefs, exhibits and other documents filed or submitted by the parties in the matter.
MarkWest
Javelina Company, L.L.C. is a party to an action styled Esmerejilda G. Valasquez, et al. v. Occidental Chemical Corp., et al.,
Case No. A-060352-C, 128th Judicial District, Orange County, Texas, original petition filed July 10, 2006; as refiled from previously
dismissed petition captioned Jesus Villarreal v. Koch Refining Co. et al., Cause No. 05-01977-F,
214th Judicial Dist. Ct., County of Nueces, Texas, originally filed April 27, 2005, which sets forth claims for wrongful death, personal injury or property damage, and
nuisance type claims, allegedly incurred as a result of operations and emissions from MarkWest Javelina's gas processing plant and from various petroleum, petrochemical and metal processing and
refining operations located in the area, which were also named as defendants in the action. The action has been and is being vigorously defended, and management does not believe that this action will
have a material adverse impact on the Partnership's financial position or results of operations.
In
the ordinary course of business, the Partnership is a party to various other legal and regulatory actions. In the opinion of management, none of these actions, either individually or
in the aggregate, will have a material adverse effect on the Partnership's financial condition, liquidity or results of operations.
19
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
10. Incentive Compensation Plans
Compensation Expense
Total compensation expense recorded for share-based pay arrangements is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
Three months ended
March 31, |
|
|
|
2010 |
|
2009 |
|
Phantom units |
|
$ |
6,285 |
|
$ |
2,703 |
|
Distribution equivalent rights |
|
|
311 |
|
|
338 |
|
|
|
|
|
|
|
Total compensation expense |
|
$ |
6,596 |
|
$ |
3,041 |
|
|
|
|
|
|
|
As
of March 31, 2010, total compensation expense not yet recognized related to the unvested awards under the 2008 LTIP and 2006 Hydrocarbon Plan was approximately
$16.1 million, with a weighted-average remaining vesting period of approximately 1.1 years. Total compensation expense not yet recognized related to unvested awards under the 2002 LTIP
was approximately $0.3 million, with a weighted-average remaining vesting period of approximately 0.8 years. The actual compensation expense recognized for awards under the 2002 LTIP may
differ as they qualify as liability awards, which are affected by changes in the fair value.
As
part of a net settlement option, employees may elect to surrender a certain number of phantom units upon vesting, and in exchange, the Partnership will assume the income tax
withholding obligations related to the vesting. During the three months ended March 31, 2010 and 2009, the Partnership was required to pay approximately $3.7 million and
$1.2 million, respectively, for income tax withholdings related to the vesting of phantom unit awards. Other than the amounts paid related to the net
settlement option, there were no cash settlements and the Partnership received no proceeds for issuing phantom units during the three months ended March 31, 2010 and 2009.
2008 LTIP and 2006 Hydrocarbon Plan
The following is a summary of phantom unit activity under the 2008 LTIP and 2006 Hydrocarbon Plan:
|
|
|
|
|
|
|
|
|
|
|
Number of Units |
|
Weighted-average Grant-date
Fair Value |
|
Unvested at December 31, 2009(1) |
|
|
977,241 |
|
$ |
22.00 |
|
|
Granted(2) |
|
|
272,188 |
|
|
29.27 |
|
|
Vested(2) |
|
|
(355,837 |
) |
|
26.71 |
|
|
Forfeited |
|
|
(5,778 |
) |
|
19.13 |
|
|
|
|
|
|
|
|
Unvested at March 31, 2010(1) |
|
|
887,814 |
|
|
22.36 |
|
|
|
|
|
|
|
|
- (1)
- Includes
437,100 performance units granted to senior executives and other key employees that contain performance vesting criteria. Compensation expense
recognized for performance units expected to vest was zero and $0.3 million for the three months ended March 31, 2010 and 2009, respectively.
20
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
10. Incentive Compensation Plans (Continued)
- (2)
- In
January 2010, the General Partner's board of directors granted 166,000 unrestricted units to senior executives and other key employees under the 2008
LTIP. The unrestricted units vested immediately and the Partnership recognized approximately $4.8 million of expense related to these units.
|
|
|
|
|
|
|
|
|
|
Three months ended
March 31, |
|
|
|
2010 |
|
2009 |
|
|
|
(in thousands)
|
|
Total grant-date fair value of phantom units granted during the period |
|
$ |
7,968 |
|
$ |
3,649 |
|
Total fair value of phantom units vested during the period and total intrinsic value of phantom units settled during the period |
|
$ |
9,505 |
|
$ |
9,064 |
|
2002 LTIP
The following is a summary of phantom unit activity under the 2002 LTIP:
|
|
|
|
|
|
|
|
|
|
|
Number of Units |
|
Weighted-average Grant-date
Fair Value |
|
Unvested at December 31, 2009 |
|
|
69,555 |
|
$ |
32.75 |
|
|
Granted |
|
|
|
|
|
|
|
|
Vested |
|
|
(43,308 |
) |
|
32.06 |
|
|
Forfeited |
|
|
(256 |
) |
|
34.00 |
|
|
|
|
|
|
|
|
Unvested at March 31, 2010 |
|
|
25,991 |
|
|
33.87 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
March 31, |
|
|
|
2010 |
|
2009 |
|
|
|
(in thousands)
|
|
Total fair value of phantom units vested during the period and total intrinsic value of phantom units settled during the period |
|
$ |
1,255 |
|
$ |
818 |
|
21
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
11. Income Taxes
A reconciliation of the provision for income tax and the amount computed by applying the federal statutory rate of 35% to the income (loss) before income tax for the three months ended
March 31, 2010 and 2009 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31, 2010 |
|
|
|
Corporation |
|
Partnership |
|
Eliminations |
|
Consolidated |
|
Income before provision for income tax |
|
$ |
3,234 |
|
$ |
27,302 |
|
$ |
(106 |
) |
$ |
30,430 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal statutory rate |
|
|
35 |
% |
|
0 |
% |
|
0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal income tax at statutory rate |
|
$ |
1,132 |
|
$ |
|
|
$ |
|
|
$ |
1,132 |
|
Permanent items |
|
|
1 |
|
|
|
|
|
|
|
|
1 |
|
State income taxes net of federal benefit |
|
|
115 |
|
|
155 |
|
|
|
|
|
270 |
|
Provision on income from Class A units(1) |
|
|
3,023 |
|
|
|
|
|
|
|
|
3,023 |
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income tax |
|
$ |
4,271 |
|
$ |
155 |
|
$ |
|
|
$ |
4,426 |
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate |
|
|
|
|
|
|
|
|
|
|
|
14.54 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31, 2009 |
|
|
|
Corporation |
|
Partnership |
|
Eliminations |
|
Consolidated |
|
Loss before provision for income tax |
|
$ |
(26,817 |
) |
$ |
(7,661 |
) |
$ |
(4,529 |
) |
$ |
(39,007 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal statutory rate |
|
|
35 |
% |
|
0 |
% |
|
0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal income tax at statutory rate |
|
$ |
(9,386 |
) |
$ |
|
|
$ |
|
|
$ |
(9,386 |
) |
Permanent items |
|
|
13 |
|
|
|
|
|
|
|
|
13 |
|
State income taxes net of federal benefit |
|
|
(658 |
) |
|
(48 |
) |
|
|
|
|
(706 |
) |
Provision on income from Class A units(1) |
|
|
3 |
|
|
|
|
|
|
|
|
3 |
|
Excess book deduction related to equity compensation |
|
|
735 |
|
|
3 |
|
|
|
|
|
738 |
|
|
|
|
|
|
|
|
|
|
|
|
Provision for income tax |
|
$ |
(9,293 |
) |
$ |
(45 |
) |
$ |
|
|
$ |
(9,338 |
) |
|
|
|
|
|
|
|
|
|
|
Effective tax rate |
|
|
|
|
|
|
|
|
|
|
|
23.94 |
% |
- (1)
- The
Corporation and the General Partner of the Partnership own Class A units of the Partnership that were received in the merger. For further
discussion, see Item 1. Business in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2009.
22
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
12. Earnings (Loss) Per Common Unit
The following table shows the computation of basic and diluted net income (loss) per common unit for the three months ended March 31, 2010 and 2009, and the weighted-average units
used to compute diluted net income (loss) per common unit (in thousands, except per unit data):
|
|
|
|
|
|
|
|
|
|
|
Three months ended
March 31, |
|
|
|
2010 |
|
2009 |
|
Net income (loss) attributable to the Partnership |
|
$ |
21,510 |
|
$ |
(29,649 |
) |
Less: Income allocable to phantom units |
|
|
277 |
|
|
390 |
|
|
|
|
|
|
|
Income (loss) available for common unitholders |
|
$ |
21,233 |
|
$ |
(30,039 |
) |
|
|
|
|
|
|
Weighted average common units outstandingbasic |
|
|
66,453 |
|
|
56,806 |
|
|
|
|
|
|
|
Weighted average common units outstandingdiluted |
|
|
66,453 |
|
|
56,806 |
|
|
|
|
|
|
|
Net income (loss) attributable to the Partnership's common unitholders per common unit |
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.32 |
|
$ |
(0.53 |
) |
|
Diluted |
|
$ |
0.32 |
|
$ |
(0.53 |
) |
13. Segment Information
The Partnership prepares segment information in accordance with GAAP. Certain items below Income (loss) from operations in the
accompanying Condensed Consolidated Statements of Operations, certain compensation expense, certain other non-cash items and any unrealized gains (losses) from derivative instruments are
not allocated to individual segments. Management does not consider these items allocable to or controllable by any individual segment and therefore excludes these items when evaluating segment
performance. Segment results are also adjusted to exclude the portion of operating income attributable to the non-controlling interests.
23
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
13. Segment Information (Continued)
The
tables below present information about operating income and capital expenditures for the reported segments for the three months ended March 31, 2010 and 2009 (in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31, 2010:
|
|
Southwest |
|
Northeast |
|
Liberty |
|
Gulf Coast |
|
Total |
|
Revenue |
|
$ |
164,964 |
|
$ |
111,848 |
|
$ |
19,010 |
|
$ |
19,793 |
|
$ |
315,615 |
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased product costs |
|
|
74,625 |
|
|
67,087 |
|
|
2,584 |
|
|
|
|
|
144,296 |
|
|
Facility expenses |
|
|
20,489 |
|
|
4,225 |
|
|
7,313 |
|
|
5,695 |
|
|
37,722 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses before items not allocated to segments |
|
|
95,114 |
|
|
71,312 |
|
|
9,897 |
|
|
5,695 |
|
|
182,018 |
|
|
Portion of operating income attributable to non-controlling interests |
|
|
1,500 |
|
|
|
|
|
3,637 |
|
|
|
|
|
5,137 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income before items not allocated to segments |
|
$ |
68,350 |
|
$ |
40,536 |
|
$ |
5,476 |
|
$ |
14,098 |
|
$ |
128,460 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
$ |
40,133 |
|
$ |
591 |
|
$ |
51,217 |
|
$ |
2,865 |
|
$ |
94,806 |
|
Capital expenditures not allocated to segments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
516 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
95,322 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31, 2009:
|
|
Southwest |
|
Northeast |
|
Liberty |
|
Gulf Coast |
|
Total |
|
Revenue |
|
$ |
104,606 |
|
$ |
61,592 |
|
$ |
6,656 |
|
$ |
10,513 |
|
$ |
183,367 |
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased product costs |
|
|
50,534 |
|
|
50,954 |
|
|
826 |
|
|
|
|
|
102,314 |
|
|
Facility expenses |
|
|
18,125 |
|
|
5,165 |
|
|
2,539 |
|
|
5,271 |
|
|
31,100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses before items not allocated to segments |
|
|
68,659 |
|
|
56,119 |
|
|
3,365 |
|
|
5,271 |
|
|
133,414 |
|
|
Portion of operating income attributable to non-controlling interests |
|
|
28 |
|
|
|
|
|
280 |
|
|
|
|
|
308 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income before items not allocated to segments |
|
$ |
35,919 |
|
$ |
5,473 |
|
$ |
3,011 |
|
$ |
5,242 |
|
$ |
49,645 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
$ |
84,429 |
|
$ |
13,224 |
|
$ |
50,290 |
|
$ |
20,877 |
|
$ |
168,820 |
|
Capital expenditures not allocated to segments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
122 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
168,942 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
13. Segment Information (Continued)
The following is a reconciliation of segment revenue to total revenue and operating income before
items not allocated to segments to income (loss) before provision for income tax for the three months ended March 31, 2010 and 2009 (in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
March 31, |
|
|
|
2010 |
|
2009 |
|
Total segment revenue |
|
$ |
315,615 |
|
$ |
183,367 |
|
|
Derivative (loss) gain not allocated to segments |
|
|
(7,236 |
) |
|
8,304 |
|
|
|
|
|
|
|
|
|
Total revenue |
|
$ |
308,379 |
|
$ |
191,671 |
|
|
|
|
|
|
|
Operating income before items not allocated to segments |
|
$ |
128,460 |
|
$ |
49,645 |
|
|
Portion of operating income attributable to non-controlling interests |
|
|
5,137 |
|
|
308 |
|
|
Derivative loss not allocated to segments |
|
|
(19,819 |
) |
|
(20,838 |
) |
|
Compensation expense included in facility expenses not allocated to segments |
|
|
(722 |
) |
|
(344 |
) |
|
Facility expenses adjustment |
|
|
539 |
|
|
|
|
|
Selling, general and administrative expenses |
|
|
(21,508 |
) |
|
(15,927 |
) |
|
Depreciation |
|
|
(28,187 |
) |
|
(20,943 |
) |
|
Amortization of intangible assets |
|
|
(10,193 |
) |
|
(10,233 |
) |
|
Gain (loss) on disposal of property, plant and equipment |
|
|
9 |
|
|
(729 |
) |
|
Accretion of asset retirement obligations |
|
|
(143 |
) |
|
(47 |
) |
|
|
|
|
|
|
|
|
Income (loss) from operations |
|
|
53,573 |
|
|
(19,108 |
) |
|
Loss from unconsolidated affiliates |
|
|
(68 |
) |
|
(105 |
) |
|
Interest income |
|
|
386 |
|
|
41 |
|
|
Interest expense |
|
|
(23,782 |
) |
|
(17,782 |
) |
|
Amortization of deferred financing costs and discount (a component of interest expense) |
|
|
(2,612 |
) |
|
(1,391 |
) |
|
Derivative gain related to interest expense |
|
|
1,871 |
|
|
|
|
|
Miscellaneous income (expense), net |
|
|
1,062 |
|
|
(662 |
) |
|
|
|
|
|
|
|
|
Income (loss) before provision for income tax |
|
$ |
30,430 |
|
$ |
(39,007 |
) |
|
|
|
|
|
|
25
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
13. Segment Information (Continued)
The
tables below present information about segment assets as of March 31, 2010 and December 31, 2009 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of March 31, 2010:
|
|
Southwest |
|
Northeast |
|
Liberty |
|
Gulf Coast |
|
Total |
|
Total segment assets |
|
$ |
1,652,732 |
|
$ |
228,021 |
|
$ |
464,673 |
|
$ |
590,000 |
|
$ |
2,935,426 |
|
Assets not allocated to segments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Certain cash and cash equivalents |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
48,145 |
|
|
Fair value of derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,970 |
|
|
Investment in unconsolidated affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,565 |
|
|
Other(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30,024 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
3,061,130 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- (1)
- Includes
corporate fixed assets, receivables, deferred financing costs and other corporate assets not allocated to segments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009:
|
|
Southwest |
|
Northeast |
|
Liberty |
|
Gulf Coast |
|
Total |
|
Total segment assets |
|
$ |
1,637,749 |
|
$ |
249,804 |
|
$ |
373,127 |
|
$ |
587,830 |
|
$ |
2,848,510 |
|
Assets not allocated to segments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Certain cash and cash equivalents |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
73,184 |
|
|
Fair value of derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24,631 |
|
|
Investment in unconsolidated affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,633 |
|
|
Other(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38,779 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
3,014,737 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- (1)
- Includes
corporate fixed assets, deferred financing costs, income tax receivable and other corporate assets not allocated to segments.
14. Supplemental Condensed Consolidating Financial Information
MarkWest Energy Partners has no significant operations independent of its subsidiaries. As of March 31, 2010, the Partnership's obligations under the outstanding Senior Notes (see
Note 7) were fully and unconditionally guaranteed, jointly and severally, by all of its wholly-owned subsidiaries. MarkWest Liberty Midstream and MarkWest Pioneer, together with certain of the
Partnership's other subsidiaries that do not guarantee the outstanding Senior Notes, have significant assets and operations in aggregate. For the purpose of the following financial information, the
Partnership's investments in its subsidiaries and the guarantor subsidiaries' investments in their subsidiaries are presented in accordance with the equity method of accounting. The financial
information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities. The operations, cash flows and
financial position of the co-issuer of the Senior Notes, MarkWest Energy Finance Corporation, are minor and therefore have been included with the Parent's financial information. Condensed
consolidating financial information for MarkWest Energy Partners and its combined guarantor and combined non-guarantor subsidiaries as of March 31, 2010
26
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
14. Supplemental Condensed Consolidating Financial Information (Continued)
and
December 31, 2009 and for the three months ended March 31, 2010 and 2009 is as follows (in thousands):
Condensed Consolidating Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of March 31, 2010 |
|
|
|
Parent |
|
Guarantor
Subsidiaries |
|
Non-Guarantor
Subsidiaries |
|
Consolidating
Adjustments |
|
Consolidated |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
|
|
$ |
48,739 |
|
$ |
56,436 |
|
$ |
|
|
$ |
105,175 |
|
|
Receivables and other current assets |
|
|
1,378 |
|
|
151,846 |
|
|
30,745 |
|
|
|
|
|
183,969 |
|
|
Intercompany receivables |
|
|
1,503,076 |
|
|
1,342 |
|
|
|
|
|
(1,504,418 |
) |
|
|
|
|
Fair value of derivative instruments |
|
|
|
|
|
8,002 |
|
|
|
|
|
|
|
|
8,002 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
1,504,454 |
|
|
209,929 |
|
|
87,181 |
|
|
(1,504,418 |
) |
|
297,146 |
|
Total property, plant and equipment, net |
|
|
3,214 |
|
|
1,514,211 |
|
|
536,638 |
|
|
(6,393 |
) |
|
2,047,670 |
|
Other long-term assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in unconsolidated affiliate |
|
|
|
|
|
29,565 |
|
|
|
|
|
|
|
|
29,565 |
|
|
Investment in consolidated affiliates |
|
|
581,187 |
|
|
237,997 |
|
|
|
|
|
(819,184 |
) |
|
|
|
|
Intangibles, net of accumulated amortization |
|
|
|
|
|
643,613 |
|
|
605 |
|
|
|
|
|
644,218 |
|
|
Fair value of derivative instruments |
|
|
|
|
|
9,968 |
|
|
|
|
|
|
|
|
9,968 |
|
|
Intercompany notes receivable |
|
|
188,910 |
|
|
|
|
|
|
|
|
(188,910 |
) |
|
|
|
|
Other long-term assets |
|
|
19,501 |
|
|
12,762 |
|
|
300 |
|
|
|
|
|
32,563 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
2,297,266 |
|
$ |
2,658,045 |
|
$ |
624,724 |
|
$ |
(2,518,905 |
) |
$ |
3,061,130 |
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany payables |
|
$ |
|
|
$ |
1,503,007 |
|
$ |
1,411 |
|
$ |
(1,504,418 |
) |
$ |
|
|
|
Fair value of derivative instruments |
|
|
|
|
|
63,544 |
|
|
|
|
|
|
|
|
63,544 |
|
|
Other current liabilities |
|
|
40,603 |
|
|
154,487 |
|
|
56,739 |
|
|
|
|
|
251,829 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
40,603 |
|
|
1,721,038 |
|
|
58,150 |
|
|
(1,504,418 |
) |
|
315,373 |
|
Deferred income taxes |
|
|
2,448 |
|
|
7,214 |
|
|
|
|
|
|
|
|
9,662 |
|
Intercompany notes payable |
|
|
|
|
|
188,910 |
|
|
|
|
|
(188,910 |
) |
|
|
|
Fair value of derivative instruments |
|
|
|
|
|
55,103 |
|
|
|
|
|
|
|
|
55,103 |
|
Long-term debt, net of discounts |
|
|
1,165,306 |
|
|
|
|
|
|
|
|
|
|
|
1,165,306 |
|
Other long-term liabilities |
|
|
3,499 |
|
|
104,593 |
|
|
394 |
|
|
|
|
|
108,486 |
|
Equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MarkWest Energy Partners, L.P. partners' capital |
|
|
1,085,410 |
|
|
581,187 |
|
|
566,180 |
|
|
(1,153,760 |
) |
|
1,079,017 |
|
|
Non-controlling interest in consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
328,183 |
|
|
328,183 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equity |
|
|
1,085,410 |
|
|
581,187 |
|
|
566,180 |
|
|
(825,577 |
) |
|
1,407,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and equity |
|
$ |
2,297,266 |
|
$ |
2,658,045 |
|
$ |
624,724 |
|
$ |
(2,518,905 |
) |
$ |
3,061,130 |
|
|
|
|
|
|
|
|
|
|
|
|
|
27
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
14. Supplemental Condensed Consolidating Financial Information (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009 |
|
|
|
Parent |
|
Guarantor
Subsidiaries |
|
Non-Guarantor
Subsidiaries |
|
Consolidating
Adjustments |
|
Consolidated |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
|
|
$ |
74,448 |
|
$ |
23,304 |
|
$ |
|
|
$ |
97,752 |
|
|
Receivables and other current assets |
|
|
870 |
|
|
165,421 |
|
|
26,655 |
|
|
|
|
|
192,946 |
|
|
Intercompany receivables |
|
|
1,543,169 |
|
|
2,091 |
|
|
88 |
|
|
(1,545,348 |
) |
|
|
|
|
Fair value of derivative instruments |
|
|
246 |
|
|
8,575 |
|
|
|
|
|
|
|
|
8,821 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
1,544,285 |
|
|
250,535 |
|
|
50,047 |
|
|
(1,545,348 |
) |
|
299,519 |
|
Total property, plant and equipment, net |
|
|
3,307 |
|
|
1,499,233 |
|
|
484,788 |
|
|
(5,684 |
) |
|
1,981,644 |
|
Other long-term assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in unconsolidated affiliate |
|
|
|
|
|
29,633 |
|
|
|
|
|
|
|
|
29,633 |
|
|
Investment in consolidated affiliates |
|
|
529,846 |
|
|
203,895 |
|
|
|
|
|
(733,741 |
) |
|
|
|
|
Intangibles, net of accumulated amortization |
|
|
|
|
|
653,797 |
|
|
614 |
|
|
|
|
|
654,411 |
|
|
Fair value of derivative instruments |
|
|
|
|
|
15,810 |
|
|
|
|
|
|
|
|
15,810 |
|
|
Intercompany notes receivable |
|
|
210,060 |
|
|
|
|
|
|
|
|
(210,060 |
) |
|
|
|
|
Other long-term assets |
|
|
20,538 |
|
|
13,182 |
|
|
|
|
|
|
|
|
33,720 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
2,308,036 |
|
$ |
2,666,085 |
|
$ |
535,449 |
|
$ |
(2,494,833 |
) |
$ |
3,014,737 |
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany payables |
|
$ |
1,195 |
|
$ |
1,543,257 |
|
$ |
896 |
|
$ |
(1,545,348 |
) |
$ |
|
|
|
Fair value of derivative instruments |
|
|
|
|
|
60,464 |
|
|
|
|
|
|
|
|
60,464 |
|
|
Other current liabilities |
|
|
28,673 |
|
|
149,319 |
|
|
47,527 |
|
|
|
|
|
225,519 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
29,868 |
|
|
1,753,040 |
|
|
48,423 |
|
|
(1,545,348 |
) |
|
285,983 |
|
Deferred income taxes |
|
|
2,694 |
|
|
8,340 |
|
|
|
|
|
|
|
|
11,034 |
|
Intercompany notes payable |
|
|
|
|
|
210,060 |
|
|
|
|
|
(210,060 |
) |
|
|
|
Fair value of derivative instruments |
|
|
|
|
|
62,519 |
|
|
|
|
|
|
|
|
62,519 |
|
Long-term debt, net of discounts |
|
|
1,170,072 |
|
|
|
|
|
|
|
|
|
|
|
1,170,072 |
|
Other long-term liabilities |
|
|
3,064 |
|
|
102,280 |
|
|
392 |
|
|
|
|
|
105,736 |
|
Equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MarkWest Energy Partners, L.P. partners' capital |
|
|
1,102,338 |
|
|
529,846 |
|
|
486,634 |
|
|
(1,022,164 |
) |
|
1,096,654 |
|
|
Non-controlling interest in consolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
282,739 |
|
|
282,739 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equity |
|
|
1,102,338 |
|
|
529,846 |
|
|
486,634 |
|
|
(739,425 |
) |
|
1,379,393 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and equity |
|
$ |
2,308,036 |
|
$ |
2,666,085 |
|
$ |
535,449 |
|
$ |
(2,494,833 |
) |
$ |
3,014,737 |
|
|
|
|
|
|
|
|
|
|
|
|
|
28
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
14. Supplemental Condensed Consolidating Financial Information (Continued)
Condensed Consolidating Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2010 |
|
|
|
Parent |
|
Guarantor
Subsidiaries |
|
Non-Guarantor
Subsidiaries |
|
Consolidating
Adjustments |
|
Consolidated |
|
Total revenue |
|
$ |
|
|
$ |
285,144 |
|
$ |
23,235 |
|
$ |
|
|
$ |
308,379 |
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased product costs |
|
|
|
|
|
155,073 |
|
|
2,612 |
|
|
|
|
|
157,685 |
|
|
Facility expenses |
|
|
|
|
|
28,793 |
|
|
8,469 |
|
|
(163 |
) |
|
37,099 |
|
|
Selling, general and administrative expenses |
|
|
11,781 |
|
|
9,635 |
|
|
1,310 |
|
|
(1,218 |
) |
|
21,508 |
|
|
Depreciation and amortization |
|
|
147 |
|
|
32,710 |
|
|
5,597 |
|
|
(74 |
) |
|
38,380 |
|
|
Other operating expenses |
|
|
|
|
|
(155 |
) |
|
289 |
|
|
|
|
|
134 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses |
|
|
11,928 |
|
|
226,056 |
|
|
18,277 |
|
|
(1,455 |
) |
|
254,806 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from operations |
|
|
(11,928 |
) |
|
59,088 |
|
|
4,958 |
|
|
1,455 |
|
|
53,573 |
|
Earnings from consolidated affiliates |
|
|
53,853 |
|
|
829 |
|
|
|
|
|
(54,682 |
) |
|
|
|
Other (expense) income, net |
|
|
(19,551 |
) |
|
(1,793 |
) |
|
365 |
|
|
(2,164 |
) |
|
(23,143 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before provision for income tax |
|
|
22,374 |
|
|
58,124 |
|
|
5,323 |
|
|
(55,391 |
) |
|
30,430 |
|
Provision for income tax expense |
|
|
155 |
|
|
4,271 |
|
|
|
|
|
|
|
|
4,426 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
22,219 |
|
|
53,853 |
|
|
5,323 |
|
|
(55,391 |
) |
|
26,004 |
|
Net income attributable to non-controlling interest |
|
|
|
|
|
|
|
|
|
|
|
(4,494 |
) |
|
(4,494 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to the Partnership |
|
$ |
22,219 |
|
$ |
53,853 |
|
$ |
5,323 |
|
$ |
(59,885 |
) |
$ |
21,510 |
|
|
|
|
|
|
|
|
|
|
|
|
|
29
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
14. Supplemental Condensed Consolidating Financial Information (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2009(1) |
|
|
|
Parent |
|
Guarantor
Subsidiaries |
|
Non-Guarantor
Subsidiaries |
|
Consolidating
Adjustments |
|
Consolidated |
|
Total revenue |
|
$ |
|
|
$ |
188,844 |
|
$ |
2,827 |
|
$ |
|
|
$ |
191,671 |
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased product costs |
|
|
|
|
|
130,989 |
|
|
838 |
|
|
|
|
|
131,827 |
|
|
Facility expenses |
|
|
|
|
|
29,655 |
|
|
1,418 |
|
|
|
|
|
31,073 |
|
|
Selling, general and administrative expenses |
|
|
11,810 |
|
|
4,397 |
|
|
161 |
|
|
(441 |
) |
|
15,927 |
|
|
Depreciation and amortization |
|
|
143 |
|
|
30,473 |
|
|
560 |
|
|
|
|
|
31,176 |
|
|
Other operating expenses |
|
|
|
|
|
776 |
|
|
|
|
|
|
|
|
776 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses |
|
|
11,953 |
|
|
196,290 |
|
|
2,977 |
|
|
(441 |
) |
|
210,779 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from operations |
|
|
(11,953 |
) |
|
(7,446 |
) |
|
(150 |
) |
|
441 |
|
|
(19,108 |
) |
Loss from consolidated affiliates |
|
|
(3,593 |
) |
|
(117 |
) |
|
|
|
|
3,710 |
|
|
|
|
Other (expense) income, net |
|
|
(13,631 |
) |
|
(5,323 |
) |
|
13 |
|
|
(958 |
) |
|
(19,899 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before provision for income tax |
|
|
(29,177 |
) |
|
(12,886 |
) |
|
(137 |
) |
|
3,193 |
|
|
(39,007 |
) |
Provision for income tax benefit |
|
|
(45 |
) |
|
(9,293 |
) |
|
|
|
|
|
|
|
(9,338 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
|
(29,132 |
) |
|
(3,593 |
) |
|
(137 |
) |
|
3,193 |
|
|
(29,669 |
) |
Net loss attributable to non-controlling interest |
|
|
|
|
|
|
|
|
|
|
|
20 |
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss attributable to the Partnership |
|
$ |
(29,132 |
) |
$ |
(3,593 |
) |
$ |
(137 |
) |
$ |
3,213 |
|
$ |
(29,649 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
- (1)
- The
condensed consolidating information has been revised to reflect a change in the guarantor structure. MarkWest Pioneer is no longer a guarantor
subsidiary due to the Partnership's sale of a 50% equity interest in the entity in May 2009.
30
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
14. Supplemental Condensed Consolidating Financial Information (Continued)
Condensed Consolidating Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2010 |
|
|
|
Parent |
|
Guarantor
Subsidiaries |
|
Non-Guarantor
Subsidiaries |
|
Consolidating
Adjustments |
|
Consolidated |
|
Net cash (used in) provided by operating activities |
|
$ |
(9,729 |
) |
$ |
112,836 |
|
$ |
12,036 |
|
$ |
(783 |
) |
$ |
114,360 |
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(53 |
) |
|
(42,925 |
) |
|
(53,127 |
) |
|
783 |
|
|
(95,322 |
) |
|
Equity investments |
|
|
(10,101 |
) |
|
(34,543 |
) |
|
|
|
|
44,644 |
|
|
|
|
|
Distributions from consolidated affiliates |
|
|
12,710 |
|
|
1,270 |
|
|
|
|
|
(13,980 |
) |
|
|
|
|
Collection of intercompany notes receivable, net |
|
|
21,150 |
|
|
|
|
|
|
|
|
(21,150 |
) |
|
|
|
|
Proceeds from disposal of property, plant and equipment |
|
|
|
|
|
292 |
|
|
|
|
|
|
|
|
292 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flows provided by (used in) investing activities |
|
|
23,706 |
|
|
(75,906 |
) |
|
(53,127 |
) |
|
10,297 |
|
|
(95,030 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from revolving credit facility |
|
|
135,604 |
|
|
|
|
|
|
|
|
|
|
|
135,604 |
|
|
Payments of revolving credit facility |
|
|
(141,904 |
) |
|
|
|
|
|
|
|
|
|
|
(141,904 |
) |
|
Payments of intercompany notes receivable, net |
|
|
|
|
|
(21,150 |
) |
|
|
|
|
21,150 |
|
|
|
|
|
Contributions to wholly-owned subsidiaries, net |
|
|
|
|
|
10,101 |
|
|
|
|
|
(10,101 |
) |
|
|
|
|
Contributions to joint ventures, net |
|
|
|
|
|
|
|
|
76,763 |
|
|
(34,543 |
) |
|
42,220 |
|
|
Payments of SMR liability |
|
|
|
|
|
(58 |
) |
|
|
|
|
|
|
|
(58 |
) |
|
Share-based payment activity |
|
|
(3,730 |
) |
|
97 |
|
|
|
|
|
|
|
|
(3,633 |
) |
|
Payment of distributions |
|
|
(42,866 |
) |
|
(12,710 |
) |
|
(2,540 |
) |
|
13,980 |
|
|
(44,136 |
) |
|
Intercompany advances, net |
|
|
38,919 |
|
|
(38,919 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flows (used in) provided by financing activities |
|
|
(13,977 |
) |
|
(62,639 |
) |
|
74,223 |
|
|
(9,514 |
) |
|
(11,907 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash |
|
|
|
|
|
(25,709 |
) |
|
33,132 |
|
|
|
|
|
7,423 |
|
Cash and cash equivalents at beginning of year |
|
|
|
|
|
74,448 |
|
|
23,304 |
|
|
|
|
|
97,752 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
|
|
$ |
48,739 |
|
$ |
56,436 |
|
$ |
|
|
$ |
105,175 |
|
|
|
|
|
|
|
|
|
|
|
|
|
31
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
14. Supplemental Condensed Consolidating Financial Information (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2009(1) |
|
|
|
Parent |
|
Guarantor
Subsidiaries |
|
Non-Guarantor
Subsidiaries |
|
Consolidating
Adjustments |
|
Consolidated |
|
Net cash (used in) provided by operating activities |
|
$ |
(11,096 |
) |
$ |
97,651 |
|
$ |
5,782 |
|
$ |
(517 |
) |
$ |
91,820 |
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(294 |
) |
|
(103,180 |
) |
|
(65,985 |
) |
|
517 |
|
|
(168,942 |
) |
|
Equity investments |
|
|
(14,400 |
) |
|
(4,984 |
) |
|
|
|
|
14,400 |
|
|
(4,984 |
) |
|
Change in restricted cash |
|
|
|
|
|
|
|
|
(1,125 |
) |
|
|
|
|
(1,125 |
) |
|
Distributions from consolidated affiliates |
|
|
|
|
|
36,267 |
|
|
|
|
|
(36,267 |
) |
|
|
|
|
Collection of intercompany notes receivable, net |
|
|
28,085 |
|
|
|
|
|
|
|
|
(28,085 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flows provided by (used in) investing activities |
|
|
13,391 |
|
|
(71,897 |
) |
|
(67,110 |
) |
|
(49,435 |
) |
|
(175,051 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from revolving credit facility |
|
|
234,700 |
|
|
|
|
|
|
|
|
|
|
|
234,700 |
|
|
Payments of revolving credit facility |
|
|
(125,000 |
) |
|
|
|
|
|
|
|
|
|
|
(125,000 |
) |
|
Payments of intercompany notes receivable, net |
|
|
|
|
|
(28,085 |
) |
|
|
|
|
28,085 |
|
|
|
|
|
Payments for debt issuance costs, deferred financing costs and registration costs |
|
|
(4,323 |
) |
|
|
|
|
|
|
|
|
|
|
(4,323 |
) |
|
Contributions to wholly-owned subsidiaries, net |
|
|
|
|
|
14,400 |
|
|
|
|
|
(14,400 |
) |
|
|
|
|
Contributions to joint ventures, net |
|
|
(5,464 |
) |
|
|
|
|
50,000 |
|
|
|
|
|
44,536 |
|
|
Share-based payment activity |
|
|
(1,199 |
) |
|
|
|
|
|
|
|
|
|
|
(1,199 |
) |
|
Payment of distributions |
|
|
(36,803 |
) |
|
|
|
|
(36,267 |
) |
|
36,267 |
|
|
(36,803 |
) |
|
Intercompany advances, net |
|
|
(64,206 |
) |
|
16,360 |
|
|
47,698 |
|
|
148 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flows (used in) provided by financing activities |
|
|
(2,295 |
) |
|
2,675 |
|
|
61,431 |
|
|
50,100 |
|
|
111,911 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash |
|
|
|
|
|
28,429 |
|
|
103 |
|
|
148 |
|
|
28,680 |
|
Cash and cash equivalents at beginning of year |
|
|
|
|
|
|
|
|
3,321 |
|
|
|
|
|
3,321 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
|
|
$ |
28,429 |
|
$ |
3,424 |
|
$ |
148 |
|
$ |
32,001 |
|
|
|
|
|
|
|
|
|
|
|
|
|
- (1)
- The
condensed consolidating information has been revised to reflect a change in the guarantor structure. MarkWest Pioneer is no longer a guarantor
subsidiary due to the Partnership's sale of a 50% equity interest in the entity in May 2009.
32
Table of Contents
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
15. Supplemental Cash Flow Information
The following table provides information regarding supplemental cash flow information (in thousands).
|
|
|
|
|
|
|
|
|
|
Three months ended
March 31, |
|
|
|
2010 |
|
2009 |
|
Supplemental disclosures of cash flow information: |
|
|
|
|
|
|
|
Cash paid for interest, net of amounts capitalized |
|
$ |
12,244 |
|
$ |
8,240 |
|
Cash paid for income taxes |
|
|
28 |
|
|
190 |
|
Supplemental schedule of non-cash investing and financing activities: |
|
|
|
|
|
|
|
Accrued property, plant and equipment |
|
$ |
59,861 |
|
$ |
53,445 |
|
Interest capitalized on construction in progress |
|
|
2,557 |
|
|
4,893 |
|
Property, plant and equipment asset retirement obligation |
|
|
727 |
|
|
321 |
|
Issuance of common units for vesting of share-based payment awards |
|
|
7,030 |
|
|
8,683 |
|
16. Subsequent Events
On April 6, 2010, the Partnership completed a public offering of approximately 4.9 million newly issued common units representing limited partner interests, which includes
the full exercise of the underwriters' over-allotment option, at a price of $30.43 per common unit. Net proceeds of approximately $142.0 million will be used to partially fund the
Partnership's ongoing capital expenditure program and to repay borrowings under the revolving credit facility.
33
Table of Contents
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Management's Discussion and Analysis ("MD&A") contains statements that are forward-looking and should be read
in conjunction with our condensed consolidated financial statements and accompanying notes included elsewhere in this report and our December 31, 2009 Annual Report on
Form 10-K. These statements are based on current expectations and assumptions that are subject to risks and uncertainties. Actual results could differ materially from those
expressed or implied in the forward-looking statements as a result of a number of factors.
Overview
We are a master limited partnership engaged in the gathering, transportation and processing of natural gas; the transportation,
fractionation, marketing and storage of NGLs; and the gathering and transportation of crude oil. We have extensive natural gas gathering, processing and transmission operations in the southwest, Gulf
Coast and northeast regions of the United States, including the Marcellus Shale, and are the largest natural gas processor in the Appalachian region.
Significant financial and other highlights for the three months ended March 31, 2010 are listed below. Refer to Results of Operations
and Liquidity and Capital Resources for further details.
Management evaluates contract performance on the basis of net operating margin (a non-GAAP financial measure) which is
defined as revenue, excluding any derivative gain (loss), less purchased product costs, excluding any derivative gain (loss). These charges have been excluded for the purpose of enhancing the
understanding by both management and investors
of the underlying baseline operating performance of our contractual arrangements, which management uses to evaluate our financial performance for purposes of planning and forecasting. Net operating
margin does not have any standardized definition and therefore is unlikely to be comparable to similar measures presented by other reporting companies. Net operating margin results should not be
evaluated in isolation of, or as a substitute for, our financial results prepared in accordance with GAAP. Our use of net operating margin and the underlying methodology in excluding certain charges
is not necessarily an indication of the results of operations expected in the future, or that we will not, in fact, incur such charges in future periods.
34
Table of Contents
The
following is a reconciliation to income (loss) from operations, the most comparable GAAP financial measure of this non-GAAP financial measure (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three months ended
March 31, |
|
|
|
2010 |
|
2009 |
|
Revenue |
|
$ |
315,615 |
|
$ |
183,367 |
|
Purchased product costs |
|
|
144,296 |
|
|
102,314 |
|
|
|
|
|
|
|
|
Net operating margin |
|
|
171,319 |
|
|
81,053 |
|
Facility expenses |
|
|
37,905 |
|
|
31,444 |
|
Total derivative loss |
|
|
19,819 |
|
|
20,838 |
|
Selling, general and administrative expenses |
|
|
21,508 |
|
|
15,927 |
|
Depreciation |
|
|
28,187 |
|
|
20,943 |
|
Amortization of intangible assets |
|
|
10,193 |
|
|
10,233 |
|
(Gain) loss on disposal of property, plant and equipment |
|
|
(9 |
) |
|
729 |
|
Accretion of asset retirement obligations |
|
|
143 |
|
|
47 |
|
|
|
|
|
|
|
|
Income (loss) from operations |
|
$ |
53,573 |
|
$ |
(19,108 |
) |
|
|
|
|
|
|
We generate the majority of our revenue and net operating margin (a non-GAAP measure, see above for discussion and
reconciliation of net operating margin) from natural gas gathering, transportation and processing; NGL transportation, fractionation, marketing and storage; and crude oil gathering and transportation.
We enter into a variety of contract types. In many cases, we provide services under contracts that contain a combination of more than one of the following types of arrangements: fee-based,
percent-of-proceeds, percent-of-index and keep-whole. See Item 1. BusinessOur Contracts in our 2009 Annual Report on Form 10-K for further
discussion of each of these types of arrangements.
The
following table is prepared as if we did not have an active commodity risk management program in place. For further discussion of how we have reduced the downside volatility to the
portion of our net operating margin that is not fee-based, see Note 4 of the accompanying Notes to the Condensed Consolidated Financial Statements. For the three months ended
March 31, 2010, we calculated the following approximate percentages of our revenue and net operating margin from the following types of contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fee-Based |
|
Percent-of-Proceeds(1) |
|
Percent-of-Index(2) |
|
Keep-Whole(3) |
|
Total |
|
Revenue |
|
|
17 |
% |
|
39 |
% |
|
5 |
% |
|
39 |
% |
|
100 |
% |
Net operating margin(4) |
|
|
31 |
% |
|
42 |
% |
|
0 |
% |
|
27 |
% |
|
100 |
% |
- (1)
- Includes
condensate sales and other types of arrangements tied to NGL prices.
- (2)
- Includes
arrangements tied to natural gas prices.
- (3)
- Includes
condensate sales and other types of arrangements tied to both NGL and natural gas prices.
- (4)
- We
manage our business by taking into account the partial offset of short natural gas positions by long positions primarily in our Southwest segment. The
calculated percentages for the net operating margin for percent-of-proceeds, percent-of-index and keep-whole contracts reflect the partial
offset of our natural gas positions.
35
Table of Contents
Our business is affected by seasonal fluctuations in commodity prices. Sales volumes also are affected by various other factors such as
fluctuating and seasonal demands for products, changes in transportation and travel patterns and variations in weather patterns from year to year. Our Northeast segment is particularly impacted by
seasonality. In the Appalachia area, we store a portion of the propane that is produced in the summer to be sold in the winter months. As a result of our seasonality, we generally expect the sales
volumes in our Northeast and Liberty segments to be higher in the first quarter and fourth quarter.
Results of Operations
We classify our business in four reportable segments: Southwest, Northeast, Liberty and Gulf Coast. We present information in this MD&A
by segment. The segment information appearing in Note 13 of the accompanying Notes to the Condensed Consolidated Financial Statements is presented on a basis consistent with our internal
management reporting.
Southwest
-
- East Texas. We own a system that consists of natural gas
gathering pipelines, centralized compressor stations, a natural gas processing facility and an NGL pipeline. The East Texas system is located in Panola, Harrison and Rusk Counties and services the
Carthage Field. Producing formations in Panola County consist of the Cotton Valley, Pettit, Travis Peak and Haynesville formations, which collectively form one of the largest natural gas producing
regions in the United States. For natural gas that is processed in this segment, we purchase the NGLs from the producers primarily under percent-of-proceeds arrangements, or we
transport volumes for a fee.
-
- Oklahoma. We own a Foss Lake natural gas gathering system
and the Arapaho I and II natural gas processing plants, all located in Roger Mills, Custer and Ellis Counties of western Oklahoma. The gathering portion consists of a pipeline system that is connected
to natural gas wells and associated compression facilities. The majority of the gathered gas ultimately is compressed and delivered to the processing plants. We also own and operate a gathering system
in the Granite Wash formation in the Texas panhandle that is connected to our Foss Lake processing plants and our Grimes gathering system that is located in Roger Mills and Beckham Counties in western
Oklahoma. In addition, we own a natural gas gathering system in the Woodford Shale in the Arkoma Basin of southeast Oklahoma.
Through
our joint venture MarkWest Pioneer, we operate the Arkoma Connector Pipeline, a 50-mile FERC-regulated pipeline that interconnects with Midcontinent Express Pipeline
and Gulf Crossing Pipeline at Bennington, Oklahoma and is designed to provide approximately 638,000 Dth/d of Arkoma Basin takeaway capacity.
-
- Other Southwest. We own a number of natural gas gathering
systems in Texas, Louisiana, Mississippi and New Mexico, including the Appleby gathering system in Nacogdoches County, Texas. We gather a significant portion of the natural gas produced from fields
adjacent to our gathering systems, including from wells targeting the Haynesville formation. In many areas we are the primary gatherer, and in some of the areas served by our smaller systems we are
the sole gatherer. In addition, we own four lateral pipelines in Texas and New Mexico.
36
Table of Contents
Northeast
-
- Appalachia. We are the largest processor of natural gas in
the Appalachian Basin, with fully integrated processing, fractionation, storage and marketing operations. The Appalachian Basin is a large natural gas producing region characterized by
long-lived reserves and modest decline rates. Our Appalachian assets include the Kenova, Boldman, Cobb and Kermit natural gas processing plants, an NGL pipeline, the Siloam NGL
fractionation plant and two caverns for storing propane.
-
- Michigan. We own and operate a FERC-regulated
crude oil pipeline in Michigan providing transportation service for six shippers.
Liberty
-
- Marcellus Shale. We operate natural gas gathering systems
and processing facilities located primarily in western Pennsylvania and northern West Virginia through MarkWest Liberty Midstream. We have a 35 MMcf/d cryogenic plant and a 120 MMcf/d cryogenic plant
at our Houston, Pennsylvania processing complex and plan to complete the installation of a 200 MMcf/d cryogenic plant in the first half of 2011. We plan to complete the installation of a 120 MMcf/d
cryogenic plant at our Majorsville site in the third quarter of 2010 and expect to increase the cryogenic processing capacity to approximately 270 MMcf/d in the third quarter of 2011. We also plan to
complete a 60,000 Bbl/d fractionation facility at our Houston complex in the first half of 2011. We expect the total planned capacity of 625 MMcf/d to be supported by long-term agreements
with our producer customers. We have also completed construction of an interconnect with a key interstate NGL pipeline providing a market outlet for the propane produced at our Liberty facilities.
Gulf Coast
-
- Javelina. We own and operate the Javelina Processing
Facility, a natural gas processing facility in Corpus Christi, Texas, which treats and processes off-gas from six local refineries operated by three different refinery customers. We have a
hydrogen supply agreement creating a long-term contractual obligation for the payment of processing fees in exchange for all of the hydrogen processed by the steam methane reformer ("SMR")
that is owned and operated by a third party. The hydrogen received under this agreement will be sold to a refinery customer pursuant to a corresponding long-term agreement.
The
following summarizes the percentage of our revenue and net operating margin (a non-GAAP financial measure, see above) generated by our assets, by segment, for the three
months ended March 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southwest |
|
Northeast |
|
Liberty |
|
Gulf Coast |
|
Total |
|
Revenue |
|
|
52 |
% |
|
36 |
% |
|
6 |
% |
|
6 |
% |
|
100 |
% |
Net operating margin |
|
|
53 |
% |
|
26 |
% |
|
10 |
% |
|
11 |
% |
|
100 |
% |
We own a 40% non-operating membership interest in Centrahoma Processing LLC ("Centrahoma"), a joint venture with
Antero Midstream Resources Corporation that is accounted for using the equity method. Centrahoma owns certain processing plants in the Arkoma Basin. We have signed agreements to dedicate our
processing rights in certain acreage in the Woodford Shale to Centrahoma through March 1, 2018. The financial results for Centrahoma are included in Earnings from
unconsolidated affiliates and are not included in our segment results.
37
Table of Contents
Three months ended March 31, 2010 compared to three months ended March 31, 2009
Items below Income (loss) from operations in our Condensed Consolidated Statements of
Operations, certain compensation expense, certain other non-cash items and any unrealized gains (losses) from derivative instruments are not allocated to individual business segments.
Management does not consider these items allocable to or controllable by any individual business segment and therefore excludes these items when evaluating segment performance. The segment results are
also adjusted to exclude the portion of operating income attributable to the non-controlling interests. The tables below present information about operating income for the reported
segments for the three months ended March 31, 2010 and 2009.
Southwest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
March 31, |
|
|
|
|
|
|
|
2010 |
|
2009 |
|
$ Change |
|
% Change |
|
|
|
(in thousands)
|
|
|
|
Revenue |
|
$ |
164,964 |
|
$ |
104,606 |
|
$ |
60,358 |
|
|
58 |
% |
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased product costs |
|
|
74,625 |
|
|
50,534 |
|
|
24,091 |
|
|
48 |
% |
|
Facility expenses |
|
|
20,489 |
|
|
18,125 |
|
|
2,364 |
|
|
13 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses before items not allocated to segments |
|
|
95,114 |
|
|
68,659 |
|
|
26,455 |
|
|
39 |
% |
|
|
|
|
|
|
|
|
|
|
|
Portion of operating income attributable to non-controlling interests |
|
|
1,500 |
|
|
28 |
|
|
1,472 |
|
|
5,257 |
% |
|
|
|
|
|
|
|
|
|
|
|
Operating income before items not allocated to segments |
|
$ |
68,350 |
|
$ |
35,919 |
|
$ |
32,431 |
|
|
90 |
% |
|
|
|
|
|
|
|
|
|
|
|
Revenue. Revenue increased primarily due to higher commodity prices. Revenue from NGL, natural gas and condensate sales increased
approximately
$53.6 million across the segment. An increase in volumes from a large producer in our Woodford Shale operations also contributed to the increase in product sales. Gathering and compression fee
revenue also increased $6.3 million due to the higher volumes in the Woodford Shale and Stiles Ranch, and the start of the Arkoma Connector Pipeline in July 2009. The increase in revenue was
partially offset by a decrease in volumes in the Other Southwest areas and a change from a gas purchase contract to a gas gathering contract with a significant producer in the Other Southwest areas.
Purchased Product Costs. Purchased product costs increased primarily due to higher commodity prices and increased volumes in certain
areas, which was
partially offset by a change from a gas purchase contract to a gas gathering contract with a significant producer in the Other Southwest areas.
Facility Expenses. Facility expenses increased primarily due to higher repairs and maintenance expense at our East Texas processing
facility, the
expansion of our operations in Stiles Ranch and the Arkoma Connector Pipeline.
Portion of Operating Income Attributable to Non-controlling Interests. Portion of operating income attributable to
non-controlling interests represents our partners' share in net operating income of MarkWest Pioneer and Wirth Gathering Partnership. The increase resulted from the Arkoma Connector
Pipeline being placed in service in July 2009.
38
Table of Contents
Northeast
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
March 31, |
|
|
|
|
|
|
|
2010 |
|
2009 |
|
$ Change |
|
% Change |
|
|
|
(in thousands)
|
|
|
|
Revenue |
|
$ |
111,848 |
|
$ |
61,592 |
|
$ |
50,256 |
|
|
82 |
% |
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased product costs |
|
|
67,087 |
|
|
50,954 |
|
|
16,133 |
|
|
32 |
% |
|
Facility expenses |
|
|
4,225 |
|
|
5,165 |
|
|
(940 |
) |
|
(18 |
)% |
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses before items not allocated to segments |
|
|
71,312 |
|
|
56,119 |
|
|
15,193 |
|
|
27 |
% |
|
|
|
|
|
|
|
|
|
|
|
Operating income before items not allocated to segments |
|
$ |
40,536 |
|
$ |
5,473 |
|
$ |
35,063 |
|
|
641 |
% |
|
|
|
|
|
|
|
|
|
|
|
Revenue. Revenue increased primarily due to higher commodity prices realized on NGL sales from the Appalachia region, as well as an
increase in
volumes from a significant customer.
Purchased Product Costs. Purchased product costs increased due to higher prices for the natural gas that is purchased to satisfy the
keep-whole arrangements in the Appalachia area, as well as the increase in volumes.
Facility Expenses. Facility expenses decreased primarily due to ceasing our natural gas gathering and processing operations in Western
Michigan
during the third quarter of 2009.
Liberty
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
March 31, |
|
|
|
|
|
|
|
2010 |
|
2009 |
|
$ Change |
|
% Change |
|
|
|
(in thousands)
|
|
|
|
Revenue |
|
$ |
19,010 |
|
$ |
6,656 |
|
$ |
12,354 |
|
|
186 |
% |
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased product costs |
|
|
2,584 |
|
|
826 |
|
|
1,758 |
|
|
213 |
% |
|
Facility expenses |
|
|
7,313 |
|
|
2,539 |
|
|
4,774 |
|
|
188 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses before items not allocated to segments |
|
|
9,897 |
|
|
3,365 |
|
|
6,532 |
|
|
194 |
% |
|
|
|
|
|
|
|
|
|
|
|
Portion of operating income attributable to non-controlling interests |
|
|
3,637 |
|
|
280 |
|
|
3,357 |
|
|
1,199 |
% |
|
|
|
|
|
|
|
|
|
|
|
Operating income before items not allocated to segments |
|
$ |
5,476 |
|
$ |
3,011 |
|
$ |
2,465 |
|
|
82 |
% |
|
|
|
|
|
|
|
|
|
|
|
Revenue. Revenue increased due to ongoing expansion of the Liberty facilities. Revenue increased approximately $5.8 million
related to
gathering fees and approximately $6.5 million related to NGL product sales under percent-of-proceeds arrangements.
Purchased Product Costs. Purchased product costs increased due to higher prices and increased purchases resulting from the ongoing
expansion of the
Liberty facilities.
Facility Expenses. Facility expenses increased primarily due to the ongoing expansion of the Liberty facilities, as well as an increase
of
approximately $1.1 million related to environmental remediation costs and other repairs and maintenance expense in 2010.
39
Table of Contents
Portion of Operating Income Attributable to Non-controlling Interests. Portion of operating income attributable to
non-controlling interests represents M&R's 40% interest in net operating income of MarkWest Liberty Midstream. The increase is the result of the formation of the joint venture on
February 27, 2009.
Gulf Coast
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
March 31, |
|
|
|
|
|
|
|
2010 |
|
2009 |
|
$ Change |
|
% Change |
|
|
|
(in thousands)
|
|
|
|
Revenue |
|
$ |
19,793 |
|
$ |
10,513 |
|
$ |
9,280 |
|
|
88 |
% |
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Facility expenses |
|
|
5,695 |
|
|
5,271 |
|
|
424 |
|
|
8 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses before items not allocated to segments |
|
|
5,695 |
|
|
5,271 |
|
|
424 |
|
|
8 |
% |
|
|
|
|
|
|
|
|
|
|
|
Operating income before items not allocated to segments |
|
$ |
14,098 |
|
$ |
5,242 |
|
$ |
8,856 |
|
|
169 |
% |
|
|
|
|
|
|
|
|
|
|
|
Revenue. Revenue increased due to higher commodity prices and increased volumes. The volumes were lower in 2009 due to a two-week plant
turnaround. The increase in revenue was partially offset by lower percent-of-proceeds received from one of our refinery customers under a variable
percent-of-proceeds contract.
Facility Expenses. Facility expenses increased primarily due to the operating expenses of the SMR and increased utilities expense. The
increases were
partially offset by a decrease related to the plant turnaround completed in 2009 that did not recur in 2010.
Reconciliation of Segment Operating Income to Consolidated Income (Loss) Before Provision for Income Tax
The following table provides a reconciliation of segment revenue to total revenue and operating income before items not allocated to
segments to our consolidated income (loss) before provision for income tax for the three months ended March 31, 2010 and 2009. The ensuing items listed below the
40
Table of Contents
Total segment revenue and Operating income lines are not allocated to business segments as management does not consider these
items allocable to any individual segment.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
March 31, |
|
|
|
|
|
|
|
2010 |
|
2009 |
|
$ Change |
|
% Change |
|
|
|
(in thousands)
|
|
|
|
Total segment revenue |
|
$ |
315,615 |
|
$ |
183,367 |
|
$ |
132,248 |
|
|
72 |
% |
|
Derivative (loss) gain not allocated to segments |
|
|
(7,236 |
) |
|
8,304 |
|
|
(15,540 |
) |
|
(187 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue |
|
$ |
308,379 |
|
$ |
191,671 |
|
$ |
116,708 |
|
|
61 |
% |
|
|
|
|
|
|
|
|
|
|
|
Operating income before items not allocated to segments |
|
$ |
128,460 |
|
$ |
49,645 |
|
$ |
78,815 |
|
|
159 |
% |
|
Portion of operating income attributable to non-controlling interests |
|
|
5,137 |
|
|
308 |
|
|
4,829 |
|
|
1,568 |
% |
|
Derivative loss not allocated to segments |
|
|
(19,819 |
) |
|
(20,838 |
) |
|
1,019 |
|
|
(5 |
)% |
|
Compensation expense included in facility expenses not allocated to segments |
|
|
(722 |
) |
|
(344 |
) |
|
(378 |
) |
|
110 |
% |
|
Facility expenses adjustment |
|
|
539 |
|
|
|
|
|
539 |
|
|
N/A |
|
|
Selling, general and administrative expenses |
|
|
(21,508 |
) |
|
(15,927 |
) |
|
(5,581 |
) |
|
35 |
% |
|
Depreciation |
|
|
(28,187 |
) |
|
(20,943 |
) |
|
(7,244 |
) |
|
35 |
% |
|
Amortization of intangible assets |
|
|
(10,193 |
) |
|
(10,233 |
) |
|
40 |
|
|
(0 |
)% |
|
Gain (loss) on disposal of property, plant and equipment |
|
|
9 |
|
|
(729 |
) |
|
738 |
|
|
(101 |
)% |
|
Accretion of asset retirement obligations |
|
|
(143 |
) |
|
(47 |
) |
|
(96 |
) |
|
204 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations |
|
|
53,573 |
|
|
(19,108 |
) |
|
72,681 |
|
|
(380 |
)% |
|
Loss from unconsolidated affiliates |
|
|
(68 |
) |
|
(105 |
) |
|
37 |
|
|
(35 |
)% |
|
Interest income |
|
|
386 |
|
|
41 |
|
|
345 |
|
|
841 |
% |
|
Interest expense |
|
|
(23,782 |
) |
|
(17,782 |
) |
|
(6,000 |
) |
|
34 |
% |
|
Amortization of deferred financing costs and discount (a component of interest expense) |
|
|
(2,612 |
) |
|
(1,391 |
) |
|
(1,221 |
) |
|
88 |
% |
|
Derivative gain related to interest expense |
|
|
1,871 |
|
|
|
|
|
1,871 |
|
|
N/A |
|
|
Miscellaneous income (expense), net |
|
|
1,062 |
|
|
(662 |
) |
|
1,724 |
|
|
(260 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before provision for income tax |
|
$ |
30,430 |
|
$ |
(39,007 |
) |
$ |
69,437 |
|
|
(178 |
)% |
|
|
|
|
|
|
|
|
|
|
|
Facility Expenses Adjustment. Facility expenses adjustment consists of the reclassification of the MarkWest Pioneer field services fee
and the
reclassification of the interest expense related to the SMR which is included a facility expenses for the purposes of evaluating the performance of the Gulf Coast segment.
Selling, General and Administrative Expenses. Selling, general and administrative expenses increased primarily due to higher share-based
compensation
expense related to the January 2010 unrestricted unit grant. Increases in headcount, short-term incentive compensation, insurance and corporate office rent also contributed to the
increase.
Depreciation. Depreciation increased due to depreciation on additional projects completed during 2009 and the first quarter of 2010.
Interest Expense. Interest expense increased primarily due to additional borrowings in 2009 to fund our capital plan.
Amortization of Deferred Financing Costs and Discount. Amortization of deferred financing costs and discount increased due primarily to
the
amortization of the financing costs and discount on the Senior Notes issued in May 2009.
41
Table of Contents
Derivative Gain Related to Interest Expense. Derivative gain related to interest expense increased due to the settlement of all the
outstanding
interest rate swaps in January 2010. See Note 4 of the accompanying Notes to the Condensed Consolidated Financial Statements for further details.
Provision for Income Tax. The total provision for income tax expense was $4.4 million, which includes a deferred benefit of
$1.4 million related primarily to MarkWest Hydrocarbon's ownership of Class A units and the net unrealized derivative loss during the period. The current provision for income tax expense
was $5.8 million. Approximately $5.4 million is attributable to MarkWest Hydrocarbon and the remaining $0.4 million is related to taxes payable by the Partnership associated with
the Texas Margin Tax and Michigan Business Taxes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
March 31, |
|
|
|
|
|
2010 |
|
2009 |
|
% Change |
|
Southwest |
|
|
|
|
|
|
|
|
|
|
|
East Texas |
|
|
|
|
|
|
|
|
|
|
|
|
Gathering systems throughput (Mcf/d) |
|
|
429,000 |
|
|
450,900 |
|
|
(4.9 |
)% |
|
|
NGL product sales (gallons) |
|
|
64,195,800 |
|
|
48,370,000 |
|
|
32.7 |
% |
|
Oklahoma |
|
|
|
|
|
|
|
|
|
|
|
|
Foss Lake gathering system throughput (Mcf/d) |
|
|
76,000 |
|
|
92,600 |
|
|
(17.9 |
)% |
|
|
Stiles Ranch gathering system throughput (Mcf/d) |
|
|
115,800 |
|
|
93,300 |
|
|
24.1 |
% |
|
|
Grimes gathering system throughput (Mcf/d) |
|
|
7,900 |
|
|
10,800 |
|
|
(26.9 |
)% |
|
|
Arapaho NGL product sales (gallons) |
|
|
29,443,300 |
|
|
27,432,700 |
|
|
7.3 |
% |
|
|
Southeast Oklahoma gathering system throughput (Mcf/d) |
|
|
496,600 |
|
|
418,600 |
|
|
18.6 |
% |
|
|
Arkoma Connector Pipeline throughput (Mcf/d)(1) |
|
|
357,800 |
|
|
N/A |
|
|
N/A |
|
|
Other Southwest |
|
|
|
|
|
|
|
|
|
|
|
|
Appleby gathering system throughput (Mcf/d) |
|
|
34,600 |
|
|
57,500 |
|
|
(39.8 |
)% |
|
|
Other gathering systems throughput (Mcf/d)(2) |
|
|
9,000 |
|
|
10,700 |
|
|
(15.9 |
)% |
Northeast |
|
|
|
|
|
|
|
|
|
|
|
Appalachia(3) |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas processed (Mcf/d) |
|
|
193,000 |
|
|
198,700 |
|
|
(2.9 |
)% |
|
|
Keep-whole sales (gallons) |
|
|
45,772,400 |
|
|
50,977,900 |
|
|
(10.2 |
)% |
|
|
Percent-of-proceeds sales (gallons) |
|
|
27,005,000 |
|
|
19,363,000 |
|
|
39.5 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total NGL product sales (gallons)(4) |
|
|
72,777,400 |
|
|
70,340,900 |
|
|
3.5 |
% |
|
Michigan |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil transported for a fee (Bbl/d) |
|
|
12,900 |
|
|
12,800 |
|
|
0.8 |
% |
Liberty |
|
|
|
|
|
|
|
|
|
|
|
|
Gathering system throughput (Mcf/d) |
|
|
100,900 |
|
|
33,600 |
|
|
200.3 |
% |
|
|
NGL product sales (gallons) |
|
|
21,530,200 |
|
|
1,383,200 |
|
|
1,456.6 |
% |
Gulf Coast |
|
|
|
|
|
|
|
|
|
|
|
|
Refinery off-gas processed (Mcf/d) |
|
|
113,300 |
|
|
104,200 |
|
|
8.7 |
% |
|
|
Liquids fractionated (Bbl/d) |
|
|
22,500 |
|
|
20,000 |
|
|
12.5 |
% |
- (1)
- We
began commercial operation of the Arkoma Connector Pipeline in July 2009.
- (2)
- Excludes
lateral pipelines where revenue is not based on throughput.
42
Table of Contents
- (3)
- Includes
throughput from the Kenova, Cobb, and Boldman processing plants.
- (4)
- Represents
sales at the Siloam fractionator. The total sales exclude 10,657,200 gallons and 1,383,200 gallons sold by the Northeast on behalf of Liberty for
the three months ended March 31, 2010 and 2009, respectively.
Liquidity and Capital Resources
Our primary strategy is to expand our asset base through organic growth and expansion projects and selective third-party acquisitions
that are accretive to our cash available for
distribution per common unit. In 2009, we spent approximately $487.0 million on internal development and expansion opportunities, of which a significant portion was funded by our joint venture
partners and by our divestiture of the SMR facility.
Our
2010 capital plan includes approximately $490 million to $540 million of capital expenditures for growth projects and approximately $10 million to
$15 million for maintenance capital. Our share of growth capital expenditures is expected to be approximately $300 million to $350 million and the remainder will be funded through
contributions from our joint venture partners and existing cash balances in the joint ventures. As of March 31, 2010 we have spent approximately $95.3 million, including the amounts
funded by our joint venture partners.
During
the three months ended March 31, 2010, we received approximately $42.2 million from M&R to fund capital expenditures at MarkWest Liberty Midstream.
Our
primary sources of liquidity to meet operating expenses, pay distributions to our unitholders and fund capital expenditures are cash flows generated by our operations and access to
debt and equity markets, both public and private. We will also consider the use of alternative financing strategies such as entering into additional joint venture arrangements and the sale of
non-strategic assets.
Management
believes that expenditures for our current capital projects will be funded with cash flows from operations, current cash balances, contributions by our joint venture partners
for capital projects encompassed by the joint venture, and our current borrowing capacity under the revolving credit facility. However, it may be necessary to raise additional funds to finance our
future capital requirements. Our access to capital markets can be impacted by factors outside our control, including economic conditions; however, we believe that our strong cash flows and balance
sheet, our credit facility and our credit rating will provide us with adequate access to funding given our expected cash needs. Any new borrowing cost would be affected by market conditions and
long-term debt ratings assigned by independent rating agencies. As of May 3, 2010, our credit ratings were Ba3 with a Stable outlook by Moody's Investors Service and BB-
with a Stable outlook by Standard & Poor's, which reflect upgrades by both agencies in 2010. Changes in our operating results, cash flows or financial position could impact the ratings assigned
by the various rating agencies. Should our credit ratings be adjusted downward, we may incur higher costs to borrow, which could have a material impact on our financial condition and results of
operations.
Our revolving credit facility, which matures on February 20, 2012, has a borrowing capacity of $435.6 million with an
accordion feature of up to $200.0 million of uncommitted funds. Under the provisions of the Partnership Credit Agreement we are subject to a number of
restrictions and covenants. As of March 31, 2010, we were in compliance with all of our debt covenants. These covenants are used to calculate the available borrowing capacity on a quarterly
basis. As of May 3, 2010, we had no borrowings outstanding and $37.5 million of letters of credit outstanding under the revolving credit facility, leaving approximately
$398.1 million available for borrowing.
43
Table of Contents
As of March 31, 2010, we had four series of Senior Notes outstanding: $225.0 million aggregate principal issued in October 2004 and due November
2014; $150.0 million aggregate principal issued in May 2009 and due November 2014 with terms substantially the same as the 2014 Senior Notes; $275.0 million aggregate principal issued in
July 2006 and due July 2016; and $500.0 million aggregate principal issued in April and May 2008 and due April 2018. For further discussion of the Senior Notes see Note 7 of the
accompanying Notes to the Condensed Consolidated Financial Statements.
The
indentures governing the Senior Notes limit the activity of the Partnership and its restricted subsidiaries. The indentures place limits on the ability of the Partnership and its
restricted subsidiaries to incur additional indebtedness; declare or pay dividends or distributions or redeem, repurchase or retire equity interests or subordinated indebtedness; make investments;
incur liens; create any consensual limitation on the ability of the Partnership's restricted subsidiaries to pay dividends or distributions, make loans or transfer property to the Partnership; engage
in transactions with the Partnership's affiliates; sell assets, including equity interests of the Partnership's subsidiaries; make any payment on or with respect to, or purchase, redeem, defease or
otherwise acquire or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets.
The
Partnership Credit Agreement limits our ability to enter into transactions with parties that require margin calls under certain derivative instruments. The Partnership Credit
Agreement prevents members of the participating bank group from requiring margin calls. As of May 3, 2010, approximately 96% of our derivative positions, measured volumetrically, are with
members of the participating bank group
and are not subject to margin deposit requirements. We believe this arrangement gives us additional liquidity as it allows us to enter into derivative instruments without utilizing cash for margin
calls or requiring the use of letters of credit; however, there is no certainty that the members of our bank group will continue to participate and in such case, a portion of our available credit
could be used for derivative instruments instead of future growth.
On April 6, 2010, we completed a public offering of approximately 4.9 million newly issued common units representing
limited partner interests, which includes the full exercise of the underwriters' over-allotment option, at a price of $30.43 per common unit. Net proceeds of approximately
$142.0 million will be used to partially fund our ongoing capital expenditure program and to repay borrowings under our revolving credit facility.
Our ability to pay distributions to our unitholders, to fund planned capital expenditures and to make acquisitions will depend upon our
future operating performance. That, in turn, will be affected by prevailing economic conditions in our industry, as well as financial, business and other factors, some of which are beyond our control.
The global economic recession had a significant adverse impact on commodity prices during 2009. Although NGL and natural gas prices have improved in the first quarter of 2010 compared to 2009, our
operating performance could be negatively impacted if the improvements in commodity prices are not sustained. Additionally, new legislation currently being considered by Congress could limit our
ability to execute our hedging strategy, which would increase our exposure to adverse changes in commodity prices.
The
prevailing uncertainty that exists in the financial markets has created an increased risk of counterparty default that could impact our liquidity in several ways. During 2010, we
expect that we will be required to borrow additional amounts under our revolving credit facility. However, our ability to access these funds could be adversely impacted by the failure of one or more
of the members of the participating bank group. Although management believes that the participating members are financially sound, an increased risk does exist. Also, because the participating members
of our bank group are the
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counterparties
to most of our derivative instruments, the failure of one of more members could significantly reduce the cash flow from operations related to the settlement of these positions. The cash
flows generated by our operations could also be significantly reduced if any of our major customers defaulted on its obligations to us. The creditworthiness of our trade customers is continuously
monitored, and we believe that our current group of customers are sound and do not represent abnormal credit risk. Additionally, our supply of gas is dependent on a few large producers in each of our
operating segments. If any of these producers were forced to significantly curtail or cease production due to economic adversity, our cash flows from operations could be significantly reduced.
The following table summarizes cash inflows (outflows) (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
March 31, |
|
|
|
|
|
2010 |
|
2009 |
|
$ Change |
|
Net cash provided by operating activities |
|
$ |
114,360 |
|
$ |
91,820 |
|
$ |
22,540 |
|
Net cash flows used in investing activities |
|
|
(95,030 |
) |
|
(175,051 |
) |
|
80,021 |
|
Net cash flows (used in) provided by financing activities |
|
|
(11,907 |
) |
|
111,911 |
|
|
(123,818 |
) |
Net
cash provided by operating activities increased primarily due to a $78.8 million increase in operating income, excluding derivative gains and losses, in our operating
segments, which was partially offset by a $61.1 million decrease in net cash received from the settlement of derivative positions.
Net
cash used in investing activities decreased primarily due to a $74.9 million decrease in capital expenditures across the Southwest, Northeast and Gulf Coast segments, and a
$5.0 million decrease in contributions to equity investments.
Net
cash (used in) provided by financing activities decreased primarily due to a $116.0 million decrease of net borrowings on our revolving credit facility.
Contractual Obligations
We periodically make other commitments and become subject to other contractual obligations that we believe to be routine in nature and
incidental to the operation of the business. Management believes that such routine commitments and contractual obligations do not have a material impact on our business, financial condition or results
of operations. As of March 31, 2010, our purchase obligations for the remainder of 2010 were $102.8 million compared to our 2010 obligations of $16.7 million as of
December 31, 2009. The increase is due to obligations related to the ongoing expansion in our Liberty segment. Purchase obligations represent purchase orders and contracts related to property,
plant and equipment.
Critical Accounting Policies
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. Estimates are used in accounting for, among other items, valuing inventory; valuing identified intangible assets; evaluating
impairments of long-lived assets, goodwill and equity investments; share-based compensation; risk management activities and derivative financial instruments; and variable interest
entities.
There
have not been any material changes during the three months ended March 31, 2010 to the methodology applied by management for critical accounting policies previously
disclosed in Item 7.
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Management's Discussion and Analysis of Financial Condition and Results of OperationsCritical Accounting Policies in our 2009 Annual Report on
Form 10-K, except as noted below.
|
|
|
|
|
Description
|
|
Judgments and Uncertainties |
|
Effect if Actual Results Differ from
Estimates and Assumptions |
Variable Interest Entities |
|
|
|
|
We evaluate all legal entities in which we hold an ownership or other pecuniary interest to determine if the entity is a VIE.
Our interests in a VIE are referred to as variable interests. Variable interests can be contractual, ownership, or other pecuniary interests in an entity that change with changes in the fair value of the VIEs assets.
When we conclude that we hold a variable interest in a VIE we must determine if we are the entity's primary beneficiary. A primary beneficiary is deemed to have a controlling financial interest in a VIE. This controlling financial interest is
evidenced by both (a) the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses that could potentially be significant to the VIE or the right to
receive benefits that could potentially be significant to the VIE.
We consolidate any VIE when we determine that we are the primary beneficiary. We must disclose the nature of any variable interests in a VIE that is not consolidated. |
|
Significant judgment is exercised in determining that a legal entity is a VIE and in evaluating our interests in a VIE.
We use primarily qualitative analysis to determine if an entity is a VIE. We evaluate the entity's need for continuing financial support; the equity holder's lack of a controlling financial interest; and/or if an equity holders voting interests are
disproportionate to its obligation to absorb expected losses or receive residual returns.
We evaluate our variable interests in a VIE to determine whether we are the primary beneficiary. We use primarily qualitative analysis to determine if we are deemed to have a controlling financial interest in the VIE.
We continually monitor our interests in legal entities for changes in the design or activities of an entity and changes in our interests, including our status as the primary beneficiary to determine if the changes require us to revise our previous
conclusions. |
|
MarkWest Liberty Midstream and MarkWest Pioneer are VIEs and we are considered the primary beneficiary; we have a traditional controlling financial interest in the Wirth Gathering Partnership and the Brightstar
Partnership, which are less-than wholly-owned. All of these entities are consolidated subsidiaries. Changes in the design or nature of the activities of any of these entities, or our involvement with an entity may require us to reconsider our
conclusions on the entity's status as a VIE and/or our status as the primary beneficiary. Such reconsideration could result in the deconsolidation of the affected subsidiary. The deconsolidation of a subsidiary would have a significant impact on our
financial statements.
We account for our ownership interest in Centrahoma under the equity method and have determined it is not a VIE. However, changes in the design or nature of the activities of the entity may require us to reconsider our conclusions. Such
reconsideration would require the identification of the variable interests in the entity and a determination on which party is the entity's primary beneficiary. If Centrahoma were considered a VIE and we were determined to be the primary beneficiary,
the change could cause us to consolidate the entity. The consolidation of an entity that is currently accounted for under the equity method could have a significant impact on our financial statements. |
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Table of Contents
Recent Accounting Pronouncements
Refer to Note 2 of the accompanying Notes to the Condensed Consolidated Financial Statements for information regarding recent
accounting pronouncements.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
The information about market risk for the three months ended March 31, 2010 does not differ materially from that discussed in
Note 7 of the Notes to Consolidated Financial Statements of the Partnership's Annual Report on Form 10-K for the year ended December 31, 2009. Refer to Note 4
of the accompanying Notes to the Condensed Consolidated Financial Statements for any updates to our quantitative and qualitative disclosures about market risk.
The
following tables provide information on the volume of our commodity derivative activity for positions related to long liquids and keep-whole price risk entered into
subsequent to March 31, 2010.
|
|
|
|
|
|
|
|
WTI Crude Swaps
|
|
Volumes
(Bbl/d) |
|
WAVG Price
(Per Bbl) |
|
2011 |
|
|
651 |
|
$ |
90.47 |
|
2012 |
|
|
1,443 |
|
|
91.28 |
|
|
|
|
|
|
|
|
|
Natural Gas Swaps
|
|
Volumes
(MMBtu/d) |
|
WAVG Price
(Per MMBtu) |
|
2011 |
|
|
1,210 |
|
$ |
5.38 |
|
2012 |
|
|
3,987 |
|
|
5.74 |
|
The
following tables provide information on the volume of our taxable subsidiary's commodity derivative activity for positions related to keep-whole price risk entered into
subsequent to March 31, 2010.
|
|
|
|
|
|
|
|
WTI Crude Swaps
|
|
Volumes
(Bbl/d) |
|
WAVG Price
(Per Bbl) |
|
2012 |
|
|
287 |
|
$ |
90.80 |
|
|
|
|
|
|
|
|
|
Natural Gas Swaps
|
|
Volumes
(MMBtu/d) |
|
WAVG Price
(Per MMBtu) |
|
2012 |
|
|
2,258 |
|
$ |
5.99 |
|
The information about interest rate risk for the three months ended March 31, 2010 does not differ materially from that
discussed in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of the Partnership's Annual Report on
Form 10-K for the year ended December 31, 2009.
Item 4. Controls and Procedures
An evaluation was performed under the supervision and with the participation of the Partnership's management, including the Chief
Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rule 13a-15(e) of the 1934
Act, as of March 31, 2010. Based on this evaluation, the Partnership's management, including our Chief Executive Officer and Chief Financial Officer, concluded that as of March 31, 2010,
our disclosure controls and procedures were effective to provide reasonable assurance that information
47
Table of Contents
required
to be disclosed by us in the reports that we file or submit under the 1934 Act is recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms
and to provide reasonable assurance that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow
timely decisions regarding required disclosures.
There were no changes in our internal control over financial reporting during the quarter ended March 31, 2010 that materially
affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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Table of Contents
PART IIOTHER INFORMATION
Item 1. Legal Proceedings
Refer to Note 9 of the accompanying Notes to the Condensed Consolidated Financial Statements for information regarding legal
proceedings.
Item 6. Exhibits
|
|
|
|
|
31.1* |
|
Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
31.2* |
|
Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
32.1* |
|
Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
32.2* |
|
Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
49
Table of Contents
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
|
|
|
|
|
|
|
MarkWest Energy Partners, L.P.
(Registrant) |
|
|
By: |
|
MarkWest Energy GP, L.L.C.,
Its General Partner |
Date: May 10, 2010 |
|
/s/ FRANK M. SEMPLE
Frank M. Semple Chairman, President and Chief Executive Officer (Principal Executive Officer) |
Date: May 10, 2010 |
|
/s/ NANCY K. BUESE
Nancy K. Buese Senior Vice President & Chief Financial Officer (Principal Financial Officer and
Principal Accounting Officer) |
50