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TABLE OF CONTENTS
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
ý | QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the quarterly period ended September 30, 2010 | ||
OR | ||
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the transition period from to |
Commission File Number 001-31239
MARKWEST ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
Delaware (State or other jurisdiction of incorporation or organization) | 27-0005456 (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 No o
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 ý 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.
Large accelerated filer ý | Accelerated filer o | Non-accelerated filer o (Do not check if a smaller reporting company) | 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 November 2, 2010, was 71,439,687.
PART I—FINANCIAL INFORMATION | ||||||
Item 1. | Financial Statements | 2 | ||||
Unaudited Condensed Consolidated Balance Sheets at September 30, 2010 and December 31, 2009 | 2 | |||||
Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2010 and 2009 | 3 | |||||
Unaudited Condensed Consolidated Statements of Changes in Equity for the nine months ended September 30, 2010 and 2009 | 4 | |||||
Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2010 and 2009 | 5 | |||||
Unaudited Notes to the Condensed Consolidated Financial Statements | 6 | |||||
Item 2. | Management's Discussion and Analysis of Financial Condition and Results of Operations | 40 | ||||
Item 3. | Quantitative and Qualitative Disclosures about Market Risk | 61 | ||||
Item 4. | Controls and Procedures | 64 | ||||
PART II—OTHER INFORMATION | ||||||
Item 1. | Legal Proceedings | 65 | ||||
Item 1A. | Risk Factors | 65 | ||||
Item 6. | Exhibits | 65 | ||||
| 67 |
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.
Glossary of Terms
Bbl | Barrel | |
Bbl/d | Barrels per day | |
Btu | One British thermal unit, an energy measurement | |
Dth/d | Dekatherms per day | |
ERCOT | Electric Reliability Council of Texas | |
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 | |
OTC | Over-the-Counter | |
SEC | Securities and Exchange Commission | |
TUR | Total unitholder return | |
WTI | West Texas Intermediate | |
2002 LTIP | 2002 Long-Term Incentive Plan | |
2006 Hydrocarbon Plan | 2006 Hydrocarbon Stock Incentive Plan | |
2008 LTIP | 2008 Long-Term Incentive Plan |
1
MARKWEST ENERGY PARTNERS, L.P.
Condensed Consolidated Balance Sheets
(unaudited, in thousands)
| September 30, 2010 | December 31, 2009 | |||||||
---|---|---|---|---|---|---|---|---|---|
ASSETS | |||||||||
Current assets: | |||||||||
Cash and cash equivalents ($35,792 and $21,942, respectively) | $ | 98,495 | $ | 97,752 | |||||
Receivables, net ($37,228 and $22,033, respectively) | 176,341 | 140,969 | |||||||
Inventories ($4,283 and $3,343, respectively) | 28,499 | 29,075 | |||||||
Fair value of derivative instruments | 12,427 | 8,821 | |||||||
Deferred income taxes | 12,228 | 12,228 | |||||||
Other current assets ($603 and $327, respectively) | 8,648 | 10,674 | |||||||
Total current assets | 336,638 | 299,519 | |||||||
Property, plant and equipment ($775,086 and $494,918, respectively) | 2,518,924 | 2,154,644 | |||||||
Less: accumulated depreciation ($29,898 and $11,324, respectively) | (261,242 | ) | (173,000 | ) | |||||
Total property, plant and equipment, net | 2,257,682 | 1,981,644 | |||||||
Other long-term assets: | |||||||||
Investment in unconsolidated affiliate | 28,642 | 29,633 | |||||||
Intangibles, net of accumulated amortization of $114,314 and $83,735, respectively | 623,832 | 654,411 | |||||||
Goodwill | 9,421 | 9,421 | |||||||
Deferred financing costs, net of accumulated amortization of $11,753 and $6,990, respectively | 27,494 | 21,027 | |||||||
Deferred contract cost, net of accumulated amortization of $1,872 and $1,638, respectively | 1,378 | 1,612 | |||||||
Fair value of derivative instruments | 7,062 | 15,810 | |||||||
Other long-term assets ($288 and $314, respectively) | 2,169 | 1,660 | |||||||
Total assets | $ | 3,294,318 | $ | 3,014,737 | |||||
LIABILITIES AND EQUITY | |||||||||
Current liabilities: | |||||||||
Accounts payable ($8,673 and $2,745, respectively) | $ | 100,209 | $ | 87,832 | |||||
Accrued liabilities ($53,610 and $44,615, respectively) | 141,021 | 137,687 | |||||||
Fair value of derivative instruments | 52,084 | 60,464 | |||||||
Total current liabilities | 293,314 | 285,983 | |||||||
Deferred income taxes | 10,996 | 11,034 | |||||||
Fair value of derivative instruments | 54,033 | 62,519 | |||||||
Long-term debt, net of discounts of $35,634 and $39,417, respectively | 1,216,194 | 1,170,072 | |||||||
Other long-term liabilities ($386 and $365, respectively) | 106,997 | 105,736 | |||||||
Commitments and contingencies (Note 9) | |||||||||
Equity: | |||||||||
MarkWest Energy Partners, L.P. partners' capital (71,440 and 66,275 common units outstanding, respectively) | 1,167,098 | 1,096,654 | |||||||
Non-controlling interest in consolidated subsidiaries | 445,686 | 282,739 | |||||||
Total equity | 1,612,784 | 1,379,393 | |||||||
Total liabilities and equity | $ | 3,294,318 | $ | 3,014,737 | |||||
Asset and liability amounts in parentheses represent the portion of the consolidated balance attributable to variable interest entities.
The accompanying notes are an integral part of these condensed consolidated financial statements.
2
MARKWEST ENERGY PARTNERS, L.P.
Condensed Consolidated Statements of Operations
(unaudited, in thousands, except per unit amounts)
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | 2010 | 2009 | |||||||||||
Revenue: | |||||||||||||||
Revenue | $ | 292,370 | $ | 207,933 | $ | 884,933 | $ | 576,300 | |||||||
Derivative (loss) gain | (36,959 | ) | 9,758 | 2,707 | (65,173 | ) | |||||||||
Total revenue | 255,411 | 217,691 | 887,640 | 511,127 | |||||||||||
Operating expenses: | |||||||||||||||
Purchased product costs | 136,700 | 91,086 | 409,119 | 274,052 | |||||||||||
Derivative loss related to purchased product costs | 19,996 | 7,816 | 24,993 | 39,954 | |||||||||||
Facility expenses | 37,934 | 30,165 | 113,266 | 93,945 | |||||||||||
Derivative (gain) loss related to facility expenses | (564 | ) | 1,347 | (436 | ) | 122 | |||||||||
Selling, general and administrative expenses | 17,137 | 15,477 | 55,064 | 46,265 | |||||||||||
Depreciation | 31,362 | 25,264 | 89,367 | 69,621 | |||||||||||
Amortization of intangible assets | 10,193 | 10,193 | 30,579 | 30,638 | |||||||||||
Loss on disposal of property, plant and equipment | 1,937 | 633 | 2,116 | 1,432 | |||||||||||
Accretion of asset retirement obligations | 70 | 56 | 282 | 147 | |||||||||||
Impairment of long-lived assets | — | — | — | 5,855 | |||||||||||
Total operating expenses | 254,765 | 182,037 | 724,350 | 562,031 | |||||||||||
Income (loss) from operations | 646 | 35,654 | 163,290 | (50,904 | ) | ||||||||||
Other income (expense): | |||||||||||||||
Earnings from unconsolidated affiliates | — | 169 | 1,517 | 1,260 | |||||||||||
Interest income | 422 | 100 | 1,185 | 201 | |||||||||||
Interest expense | (26,433 | ) | (23,440 | ) | (75,970 | ) | (63,964 | ) | |||||||
Amortization of deferred financing costs and discount (a component of interest expense) | (3,625 | ) | (3,091 | ) | (8,517 | ) | (6,528 | ) | |||||||
Derivative gain related to interest expense | — | 2,265 | 1,871 | 2,265 | |||||||||||
Miscellaneous income, net | 76 | 825 | 1,129 | 2,546 | |||||||||||
(Loss) income before provision for income tax | (28,914 | ) | 12,482 | 84,505 | (115,124 | ) | |||||||||
Provision for income tax (benefit) expense: | |||||||||||||||
Current | 3,533 | (46 | ) | 10,254 | 6,530 | ||||||||||
Deferred | (13,771 | ) | 624 | (45 | ) | (34,693 | ) | ||||||||
Total provision for income tax | (10,238 | ) | 578 | 10,209 | (28,163 | ) | |||||||||
Net (loss) income | (18,676 | ) | 11,904 | 74,296 | (86,961 | ) | |||||||||
Net income attributable to non-controlling interest | (8,475 | ) | (3,624 | ) | (19,720 | ) | (1,914 | ) | |||||||
Net (loss) income attributable to the Partnership | $ | (27,151 | ) | $ | 8,280 | $ | 54,576 | $ | (88,875 | ) | |||||
Net (loss) income attributable to the Partnership's common unitholders per common unit (Note 12): | |||||||||||||||
Basic | $ | (0.39 | ) | $ | 0.13 | $ | 0.77 | $ | (1.52 | ) | |||||
Diluted | $ | (0.39 | ) | $ | 0.13 | $ | 0.77 | $ | (1.52 | ) | |||||
Weighted average number of outstanding common units: | |||||||||||||||
Basic | 71,438 | 63,026 | 69,685 | 59,168 | |||||||||||
Diluted | 71,438 | 63,026 | 69,831 | 59,168 | |||||||||||
Cash distribution declared per common unit | $ | 0.64 | $ | 0.64 | $ | 1.92 | $ | 1.92 | |||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
3
MARKWEST ENERGY PARTNERS, L.P.
Condensed Consolidated Statements of Changes in Equity
(unaudited, in thousands)
| MarkWest Energy Partners, L.P. Unitholders | | | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 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 | 278 | 8,465 | — | 8,465 | |||||||||
Excess tax benefits related to share-based compensation | — | 97 | — | 97 | |||||||||
Distributions paid | — | (134,949 | ) | (4,830 | ) | (139,779 | ) | ||||||
Issuance of units in public offering, net of offering costs | 4,887 | 142,255 | — | 142,255 | |||||||||
Contributions to MarkWest Liberty Midstream joint venture, net | — | — | 148,057 | 148,057 | |||||||||
Net income | — | 54,576 | 19,720 | 74,296 | |||||||||
September 30, 2010 | 71,440 | $ | 1,167,098 | $ | 445,686 | $ | 1,612,784 | ||||||
| MarkWest Energy Partners, L.P. Unitholders | | | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 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 | 266 | 4,043 | — | 4,043 | |||||||||
Distributions paid | — | (112,525 | ) | (80 | ) | (112,605 | ) | ||||||
Issuance of units in public offerings, net of offering costs | 9,360 | 178,632 | — | 178,632 | |||||||||
Contributions to MarkWest Liberty Midstream joint venture, net | — | (5,464 | ) | 150,000 | 144,536 | ||||||||
Proceeds from sale of equity interest in joint venture, net | — | (1,847 | ) | 62,500 | 60,653 | ||||||||
Transfer to non-controlling interest from sale of equity interest in joint venture, net of tax | — | (14,928 | ) | 16,316 | 1,388 | ||||||||
Net (loss) income | — | (88,875 | ) | 1,914 | (86,961 | ) | |||||||
September 30, 2009 | 66,266 | $ | 1,163,494 | $ | 233,951 | $ | 1,397,445 | ||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
4
MARKWEST ENERGY PARTNERS, L.P.
Condensed Consolidated Statements of Cash Flows
(unaudited, in thousands)
| Nine months ended September 30, | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | ||||||||
Cash flows from operating activities: | ||||||||||
Net income (loss) | $ | 74,296 | $ | (86,961 | ) | |||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||
Depreciation | 89,367 | 69,621 | ||||||||
Amortization of intangible assets | 30,579 | 30,638 | ||||||||
Impairment of long-lived assets | — | 5,855 | ||||||||
Amortization of deferred financing costs and discount | 8,517 | 6,528 | ||||||||
Accretion of asset retirement obligations | 282 | 147 | ||||||||
Amortization of deferred contract cost | 234 | 234 | ||||||||
Phantom unit compensation expense | 11,430 | 5,755 | ||||||||
Equity in earnings of unconsolidated affiliates | (1,517 | ) | (1,260 | ) | ||||||
Distributions from unconsolidated affiliate | 2,508 | — | ||||||||
Unrealized (gain) loss on derivative instruments | (11,885 | ) | 149,991 | |||||||
Loss on disposal of property, plant and equipment | 2,116 | 1,432 | ||||||||
Deferred income taxes | (45 | ) | (34,693 | ) | ||||||
Gain on sale of trading securities | — | (40 | ) | |||||||
Net sales of trading securities | — | 552 | ||||||||
Other | — | (2,740 | ) | |||||||
Changes in operating assets and liabilities: | ||||||||||
Receivables | (35,072 | ) | (7,320 | ) | ||||||
Inventories | 576 | 4,611 | ||||||||
Other current assets | 2,026 | (1,835 | ) | |||||||
Accounts payable and accrued liabilities | 23,042 | 14,465 | ||||||||
Other long-term assets | (509 | ) | (10,543 | ) | ||||||
Other long-term liabilities | 1,293 | 3,428 | ||||||||
Net cash provided by operating activities | 197,238 | 147,865 | ||||||||
Cash flows from investing activities: | ||||||||||
Capital expenditures | (374,173 | ) | (388,502 | ) | ||||||
Equity investments | — | (6,435 | ) | |||||||
Proceeds from disposal of property, plant and equipment | 524 | 275 | ||||||||
Change in restricted cash | — | (10,025 | ) | |||||||
Net cash flows used in investing activities | (373,649 | ) | (404,687 | ) | ||||||
Cash flows from financing activities: | �� | |||||||||
Proceeds from revolving credit facility | 421,304 | 568,000 | ||||||||
Payments of revolving credit facility | (378,804 | ) | (700,900 | ) | ||||||
Proceeds from long-term debt | — | 117,000 | ||||||||
Payments for debt issuance costs, deferred financing costs and registration costs | (11,230 | ) | (8,381 | ) | ||||||
Contributions to MarkWest Liberty Midstream joint venture, net | 148,057 | 144,536 | ||||||||
Proceeds from sale of equity interest in joint venture, net | — | 60,653 | ||||||||
Payments of SMR liability | (912 | ) | — | |||||||
Proceeds from SMR transaction | — | 73,129 | ||||||||
Proceeds from public offerings, net | 142,255 | 178,632 | ||||||||
Cash paid for taxes related to net settlement of share-based payment awards | (3,834 | ) | (1,257 | ) | ||||||
Excess tax benefits related to share-based compensation | 97 | — | ||||||||
Payments of distributions to common unitholders | (134,949 | ) | (112,525 | ) | ||||||
Payments of distributions to non-controlling interest | (4,830 | ) | (80 | ) | ||||||
Net cash flows provided by financing activities | 177,154 | 318,807 | ||||||||
Net increase in cash | 743 | 61,985 | ||||||||
Cash and cash equivalents at beginning of year | 97,752 | 3,321 | ||||||||
Cash and cash equivalents at end of period | $ | 98,495 | $ | 65,306 | ||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
5
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, results for the three and nine months ended September 30, 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, or is not the primary beneficiary, are accounted for using the equity method.
2. Recent Accounting Pronouncements
In June 2009, the FASB amended the variable interest entity ("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 will not have a material effect on the Partnership's existing revenue arrangements and is not expected to have a material effect on the Partnership's condensed consolidated financial statements.
6
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
2. Recent Accounting Pronouncements (Continued)
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 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 a scope 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 was effective for the Partnership on July 1, 2010. The amended guidance had no effect on the Partnership's condensed consolidated financial statements.
3. Variable Interest Entities
MarkWest Liberty Midstream
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, 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 required 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 September 30, 2010, the capital contributed to MarkWest Liberty Midstream is disproportionate to each member's respective ownership interest. The cumulative capital contributed by M&R exceeded its ownership interest by $124.3 million. Under the terms of the joint venture agreement, M&R received a special $8.3 million non-cash allocation of net income from MarkWest
7
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
3. Variable Interest Entities (Continued)
Liberty Midstream during the nine months ended September 30, 2010 due to its excess contributions. The non-cash allocation is recorded inNet income attributable to non-controlling interest.
MarkWest Pioneer
MarkWest Pioneer is the owner and operator of the Arkoma Connector Pipeline, a 50-mile FERC-regulated pipeline that was placed in service in mid-July 2009. The Arkoma Connector Pipeline is designed to provide approximately 638,000 Dth/d of Arkoma Basin takeaway capacity and interconnects with the Midcontinent Express Pipeline and the Gulf Crossing Pipeline. 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 September 30, 2010, the carrying value of the Partnership's ownership interest exceeds its stated ownership interest in MarkWest Pioneer by approximately $1.9 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.
Significant Judgments Regarding VIEs
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.
Financial Statement Impact of VIEs
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
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 September 30, 2010 and December 31, 2009 (in thousands):
| As of September 30, 2010 | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| MarkWest Liberty Midstream | MarkWest Pioneer | Total | ||||||||
ASSETS | |||||||||||
Cash and cash equivalents | $ | 32,946 | $ | 2,846 | $ | 35,792 | |||||
Accounts receivable | 35,366 | 1,862 | 37,228 | ||||||||
Inventories | 4,283 | — | 4,283 | ||||||||
Other current assets | 499 | 104 | 603 | ||||||||
Property, plant and equipment, net of accumulated depreciation of $22,149 and $7,749, respectively | 596,384 | 148,804 | 745,188 | ||||||||
Other long-term assets | 288 | — | 288 | ||||||||
Total assets | $ | 669,766 | $ | 153,616 | $ | 823,382 | |||||
LIABILITIES | |||||||||||
Accounts payable | $ | 8,663 | $ | 10 | $ | 8,673 | |||||
Accrued liabilities | 51,944 | 1,666 | 53,610 | ||||||||
Other long-term liabilities | 85 | 301 | 386 | ||||||||
Total liabilities | $ | 60,692 | $ | 1,977 | $ | 62,669 | |||||
| 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 | |||||
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).
9
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
3. Variable Interest Entities (Continued)
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 nine months ended September 30, 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 and nine months ended September 30, 2010 and 2009 (in thousands).
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | 2010 | 2009 | |||||||||||
Net (loss) income attributable to the Partnership | $ | (27,151 | ) | $ | 8,280 | $ | 54,576 | $ | (88,875 | ) | |||||
Transfers to the non-controlling interest: | |||||||||||||||
Decrease in Partners' Capital for transaction costs related to sale of equity interest in MarkWest Liberty Midstream and MarkWest Pioneer | — | — | — | (7,311 | ) | ||||||||||
Decrease in Partners' Capital for transfer to non-controlling interest from sale of equity interest in MarkWest Pioneer | — | (9,039 | ) | — | (14,928 | ) | |||||||||
Net (loss) income attributable to the Partnership and transfers to the non-controlling interest | $ | (27,151 | ) | $ | (759 | ) | $ | 54,576 | $ | (111,114 | ) | ||||
4. Derivative Financial Instruments
Commodity Contracts
NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty, availability of NGL transportation and fractionation capacity and a variety of additional factors that are beyond the Partnership's control. The Partnership's profitability is directly affected by prevailing commodity prices primarily as a result of processing or conditioning at its processing plants or third-party processing plants, purchasing and selling or gathering and transporting volumes of natural gas at index-related prices and the cost of third-party transportation and fractionation services. To the extent that commodity prices influence the level of drilling activity, such prices also affect profitability. To protect itself financially against adverse price movements and to maintain more stable and predictable earnings so that the Partnership can meet its cash distribution objectives, debt service and capital expenditures, the Partnership executes a hedging strategy governed by the risk management policy approved by the General Partner's board of directors (the "Board"). The Partnership has a committee comprised of senior management that oversees risk management activities, continually monitors the risk management program and adjusts its strategy as
10
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
4. Derivative Financial Instruments (Continued)
conditions warrant. The Partnership enters into certain derivative contracts to reduce the risks associated with unfavorable changes in the prices of natural gas, NGLs and crude oil. Derivative contracts utilized are swaps, options and fixed price forward contracts traded on the OTC market. The risk management policy does not allow speculative derivative contracts.
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. Generally the Partnership hedges its NGL price risk using crude oil as NGL financial markets lack adequate liquidity and historically there has been a strong relationship between changes in NGL and crude oil prices. The pricing relationship between NGLs and crude oil may vary in certain periods due to various market conditions. In periods where NGL prices and crude oil prices are not consistent with the historical relationship, the Partnership incurs increased risk and additional gains or losses. The Partnership enters into NGL derivative contracts when adequate market liquidity exists.
To 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 and takes into account the partial offset of its long and short gas positions resulting from normal operating activities.
As a result of its current derivative positions, the Partnership has mitigated a significant portion of its expected commodity price risk through the fourth quarter of 2013. For entities that are not wholly owned by the Partnership, commodity risk is mitigated only for the Partnership's ownership interest. The Partnership would be exposed to additional commodity risk in certain situations such as if producers under deliver or over deliver product or when processing facilities are operated in different recovery modes. In the event the Partnership has derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions may be terminated.
The Partnership enters into derivative contracts primarily with financial institutions that are participating members of the amended and restated credit agreement as collateral is not posted by the Partnership as the participating members have a collateral position in substantially all the wholly-owned assets of the Partnership. All of the Partnership's financial derivative positions are currently with participating bank group members. Management conducts a standard credit review on counterparties and the Partnership has agreements containing collateral requirements. For all participating bank group members, collateral requirements do not exist when a derivative contract favors the Partnership. The Partnership uses standardized agreements that allow for offset of positive and negative exposures (master netting arrangements).
The Partnership records derivative contracts at fair value in the Condensed Consolidated Balance Sheets and has not elected hedge accounting or the normal purchases and normal sales designation which may cause volatility in the Condensed Statement of Operations as the Partnership recognizes in current earnings all unrealized gains and losses from the mark to market on derivative activity.
Embedded Derivative in Debt Contract
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
11
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
4. Derivative Financial Instruments (Continued)
requiring separate accounting, the embedded derivatives must be aggregated and accounted for as one compound embedded derivative. The fair value of the compound embedded derivative in the indenture is recorded as a component ofLong-term debt in the Condensed Consolidated Balance Sheets.
Interest Rate Contracts
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.
Financial Statement Impact of Derivative Contracts
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):
| Assets | Liabilities | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Derivative contracts not designated as hedging instruments and their balance sheet location | Fair Value at September 30, 2010 | Fair Value at December 31, 2009 | Fair Value at September 30, 2010 | Fair Value at December 31, 2009 | |||||||||||
Commodity contracts(1) | |||||||||||||||
Fair value of derivative instruments—current | $ | 12,427 | $ | 8,312 | $ | (52,084 | ) | $ | (60,464 | ) | |||||
Fair value of derivative instruments—long-term | 7,062 | 15,810 | (54,033 | ) | (62,519 | ) | |||||||||
Interest rate contracts | |||||||||||||||
Fair value of derivative instruments—current | — | 509 | — | — | |||||||||||
Embedded derivative in debt contract | |||||||||||||||
Long-term debt | — | — | (28 | ) | (190 | ) | |||||||||
Total | $ | 19,489 | $ | 24,631 | $ | (106,145 | ) | $ | (123,173 | ) | |||||
- (1)
- IncludesEmbedded Derivatives in Commodity Contracts as discussed below.
12
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 September 30, | Nine months ended September 30, | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Derivative contracts not designated as hedging instruments and the location of gain or (loss) recognized in income | 2010 | 2009 | 2010 | 2009 | |||||||||||
Revenue: Derivative (loss) gain | |||||||||||||||
Realized (loss) gain | $ | (1,732 | ) | $ | 9,254 | $ | (20,551 | ) | $ | 85,667 | |||||
Unrealized (loss) gain | (35,227 | ) | 504 | 23,258 | (150,840 | ) | |||||||||
Total Revenue: derivative (loss) gain | (36,959 | ) | 9,758 | 2,707 | (65,173 | ) | |||||||||
Derivative loss related to purchased product costs | |||||||||||||||
Realized loss | (3,946 | ) | (15,271 | ) | (15,117 | ) | (42,530 | ) | |||||||
Unrealized (loss) gain | (16,050 | ) | 7,455 | (9,876 | ) | 2,576 | |||||||||
Total derivative loss related to purchased product costs | (19,996 | ) | (7,816 | ) | (24,993 | ) | (39,954 | ) | |||||||
Derivative gain (loss) related to facility expenses | |||||||||||||||
Unrealized gain (loss) | 564 | (1,347 | ) | 436 | (122 | ) | |||||||||
Derivative gain related to interest expense | |||||||||||||||
Realized gain | — | — | 2,380 | — | |||||||||||
Unrealized gain (loss) | — | 2,265 | (509 | ) | 2,265 | ||||||||||
Total derivative gain related to interest expense | — | 2,265 | 1,871 | 2,265 | |||||||||||
Miscellaneous income, net | |||||||||||||||
Unrealized gain | 103 | 189 | 162 | 280 | |||||||||||
Total (loss) gain | $ | (56,288 | ) | $ | 3,049 | $ | (19,817 | ) | $ | (102,704 | ) | ||||
At September 30, 2010, the fair value of the Partnership's commodity derivative contracts is inclusive of premium payments of $6.1 million, net of amortization. For the three months ended September 30, 2010 and 2009,Realized (loss) gain—revenue includes amortization of premium payments of $0.5 million and $1.5 million, respectively. For the nine months ended September 30, 2010 and 2009,Realized (loss) gain—revenue includes amortization of premium payments of $1.6 million and $4.2 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 inRealized (loss) gain—revenue and an $11.3 million realized loss included inDerivative loss related to purchased product costs in the accompanying Condensed Consolidated Statements of Operations.
13
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
4. Derivative Financial Instruments (Continued)
Credit Risk Contingent Feature
The Partnership had a contractual arrangement with one non-bank group counterparty that contained a credit risk contingent feature related to margin requirements as discussed in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2009. On July 29, 2010, the Partnership executed a joinder agreement to include the counterparty in the bank group. As a result, all of the Partnership's financial derivative positions are currently with participating bank group members, and the credit risk contingent feature related to margin requirements no longer exists.
Volume of Derivative Activity
As of September 30, 2010, the Partnership had the following outstanding commodity contracts that were entered into to economically hedge future sales of NGLs or future purchases of natural gas:
Derivative contracts not designated as hedging instruments | Notional Quantity (net) | |||
---|---|---|---|---|
Crude Oil (bbl) | 8,486,757 | |||
Natural Gas Liquids (gal) | 5,422,034 | |||
Natural Gas (MMBtu) | 15,401,359 |
Embedded Derivatives in Commodity Contracts
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 throughDerivative loss related to purchased product costs. As of September 30, 2010, the estimated fair value of this contract was a liability of $33.5 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 throughDerivative (gain) loss related to facility expenses. As of September 30, 2010, the estimated fair value of this contract was an asset of $0.2 million.
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
14
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
5. Fair Value (Continued)
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 September 30, 2010 and December 31, 2009 (in thousands).
As of September 30, 2010 | Assets | Liabilities | ||||||
---|---|---|---|---|---|---|---|---|
Significant other observable inputs (Level 2) | ||||||||
Commodity contracts | $ | 12,468 | $ | (62,242 | ) | |||
Significant unobservable inputs (Level 3) | ||||||||
Commodity contracts | 6,784 | (10,323 | ) | |||||
Embedded derivatives in commodity contracts | 237 | (33,552 | ) | |||||
Embedded derivative in debt contract | — | (28 | ) | |||||
Total carrying value in Condensed Consolidated Balance Sheet | $ | 19,489 | $ | (106,145 | ) | |||
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 | ) | |||
15
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 and nine months ended September 30, 2010 and 2009 for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands).
| Three Months Ended September 30, 2010 | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Commodity Derivative Contracts (net) | Embedded Derivatives in Commodity Contracts (net) | Interest Rate Contracts | Embedded Derivative in Debt Contract | |||||||||
Fair value at beginning of period | $ | 5,348 | $ | (23,636 | ) | $ | — | $ | (131 | ) | |||
Total gain or loss (realized and unrealized) included in earnings(1) | (8,952 | ) | (11,977 | ) | — | 103 | |||||||
Purchases, sales, issuances and settlements (net) | 65 | 2,298 | — | — | |||||||||
Fair value at end of period | $ | (3,539 | ) | $ | (33,315 | ) | $ | — | $ | (28 | ) | ||
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 September 30(1) | $ | (8,592 | ) | $ | (11,345 | ) | $ | — | $ | 103 | |||
| Three Months Ended September 30, 2009 | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Commodity Derivative Contracts (net) | Embedded Derivatives in Commodity Contracts (net) | Interest Rate Contracts | Embedded Derivative in Debt Contract | |||||||||
Fair value at beginning of period | $ | 12,636 | $ | (2,167 | ) | $ | — | $ | (435 | ) | |||
Total gain or loss (realized and unrealized) included in earnings(1) | 3,771 | (11,729 | ) | 2,265 | 189 | ||||||||
Purchases, sales, issuances and settlements (net) | (3,428 | ) | 1,591 | — | — | ||||||||
Fair value at end of period | $ | 12,979 | $ | (12,305 | ) | $ | 2,265 | $ | (246 | ) | |||
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 September 30(1) | $ | 2,446 | $ | (10,137 | ) | $ | 2,265 | $ | 189 | ||||
16
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
5. Fair Value (Continued)
| Nine Months Ended September 30, 2010 | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Commodity Derivative Contracts (net) | Embedded Derivatives in Commodity Contracts (net) | Interest Rate Contracts | Embedded Derivative in Debt Contract | |||||||||
Fair value at beginning of period | $ | (11,340 | ) | $ | (34,199 | ) | $ | 509 | $ | (190 | ) | ||
Total gain or loss (realized and unrealized) included in earnings(1) | 1,319 | (6,857 | ) | 1,871 | 162 | ||||||||
Purchases, sales, issuances and settlements (net) | 6,482 | 7,741 | (2,380 | ) | — | ||||||||
Fair value at end of period | $ | (3,539 | ) | $ | (33,315 | ) | $ | — | $ | (28 | ) | ||
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 September 30(1) | $ | (2,712 | ) | $ | (4,703 | ) | $ | — | $ | 162 | |||
| Nine Months Ended September 30, 2009 | |||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Commodity Derivative Contracts (net) | Embedded Derivatives in Commodity Contracts (net) | Interest Rate Contracts | Embedded Derivative in Debt Contract | Trading Securities | |||||||||||
Fair value at beginning of period | $ | 72,478 | $ | (22 | ) | $ | — | $ | — | $ | 512 | |||||
Total gain or loss (realized and unrealized) included in earnings(1) | (27,177 | ) | (15,301 | ) | 2,265 | 280 | 40 | |||||||||
Purchases, sales, issuances and settlements (net) | (32,322 | ) | 3,018 | — | (526 | ) | (552 | ) | ||||||||
Fair value at end of period | $ | 12,979 | $ | (12,305 | ) | $ | 2,265 | $ | (246 | ) | $ | — | ||||
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 September 30(1) | $ | (32,733 | ) | $ | (12,283 | ) | $ | 2,265 | $ | 280 | $ | — | ||||
- (1)
- Gains and losses on Commodity Derivative Contracts classified as Level 3 are recorded inDerivative (loss) gain related to revenue. Gains and losses on Embedded Derivatives in Commodity Contracts are recorded inPurchased product costs,Derivative loss related to purchased product costs andDerivative (gain) loss related to facility expenses. Gains on Embedded Derivative in Debt Contract are recorded inMiscellaneous income, net. Gains and losses on Interest Rate Contracts are recorded inDerivative gain related to interest expense.
17
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
6. Inventories
Inventories consist of the following (in thousands):
| September 30, 2010 | December 31, 2009 | |||||
---|---|---|---|---|---|---|---|
Natural gas and natural gas liquids | $ | 21,728 | $ | 20,939 | |||
Spare parts | 6,771 | 8,136 | |||||
Total inventories | $ | 28,499 | $ | 29,075 | |||
7. Long-Term Debt
Debt is summarized below (in thousands):
| September 30, 2010 | December 31, 2009 | |||||
---|---|---|---|---|---|---|---|
Credit Facility | |||||||
Revolving credit facility, 5.0% and 5.25% interest at September 30, 2010 and December 31, 2009, respectively, due July 2015 | $ | 101,800 | $ | 59,300 | |||
Senior Notes(1) | |||||||
Senior Notes, 6.875% interest, net of discount of $6,747 and $8,089, respectively, issued October 2004 and due November 2014(2) | 218,253 | 216,911 | |||||
Senior Notes, 6.875% interest, net of discount of $27,259 and $29,515, respectively, issued May 2009 and due November 2014(2)(3) | 122,769 | 120,674 | |||||
Senior Notes, 8.5% interest, net of discount of $672 and $762, respectively, issued July 2006 and due July 2016 | 274,328 | 274,238 | |||||
Senior Notes, 8.75% interest, net of discount of $956 and $1,051, respectively, issued April and May 2008 and due April 2018 | 499,044 | 498,949 | |||||
Total long-term debt | $ | 1,216,194 | $ | 1,170,072 | |||
- (1)
- The estimated aggregate fair value of the Senior Notes was approximately $1,208.6 million and $1,152.9 million as of September 30, 2010 and December 31, 2009, respectively, based on quoted market prices.
- (2)
- On November 2, 2010, the Partnership repurchased 94% of the Senior Notes due November 2014 ("2014 Senior Notes") (see Note 16).
- (3)
- Includes fair value of written put options of less than $0.1 million (see Note 4).
Credit Facility
On July 1, 2010, the Partnership entered into an amended and restated credit agreement that initially provided for a revolving credit facility (the "Credit Facility") of up to $700 million, with an uncommitted accordion feature of up to $200 million. The Credit Facility replaced the Partnership's prior credit agreement in its entirety.
18
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
7. Long-Term Debt (Continued)
On July 29, 2010, the Partnership executed a joinder agreement to include an additional member in the bank group participating in the Credit Facility and to exercise a portion of the accordion feature under the Credit Facility, thereby increasing the borrowing capacity to $705 million and reducing the uncommitted accordion feature to $195 million.
The borrowings under the Credit Facility continue to bear interest at a variable interest rate, plus basis points. The variable interest rate is based either on LIBOR ("LIBOR Loans") or the higher of (a) the prime rate set by the Credit Facility's administrative agent, (b) the Federal Funds Rate plus 0.5% and (c) the rate for LIBOR for a one month interest period plus 1% ("Alternate Base Rate Loans"). The basis points correspond to the ratio of the Partnership's Consolidated Funded Debt (as defined in the Credit Facility) to the Partnership's Adjusted Consolidated EBITDA (as defined in the Credit Facility), ranging from 1.5% to 2.5% for Alternate Base Rate Loans and from 2.5% to 3.5% for LIBOR Loans. The Partnership may utilize up to $150 million of the Credit Facility for the issuance of letters of credit and $10 million for shorter term swingline loans.
The Credit Facility matures on July 1, 2015; however, if the Partnership does not refinance or repay all the 2014 Senior Notes by May 1, 2014, the Credit Facility will mature on May 1, 2014. Subsequent to September 30, 2010, 94% of the 2014 Senior Notes were repurchased (see Note 16). The Credit Facility is guaranteed by all of the Partnership's wholly-owned subsidiaries and is collateralized by substantially all of the Partnership's assets and those of its wholly-owned subsidiaries.
The Partnership incurred approximately $11.2 million of deferred financing costs associated with the Credit Facility.
Under the provisions of the Credit Facility, 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 September 30, 2010, the Partnership had $101.8 million of borrowings outstanding and $21.4 million of letters of credit outstanding under the Credit Facility, leaving approximately $581.8 million available for borrowing.
8. Equity
Equity Offering
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 $142.3 million were used to repay borrowings under the revolving credit facility and to partially fund the Partnership's ongoing capital expenditure program.
19
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
8. Equity (Continued)
Distributions of Available Cash
Quarter Ended | Distribution Per Common Unit | Declaration Date | Record Date | Payment Date | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
September 30, 2010 | $ | 0.64 | October 27, 2010 | November 8, 2010 | November 12, 2010 | ||||||||
June 30, 2010 | $ | 0.64 | July 22, 2010 | August 2, 2010 | August 13, 2010 | ||||||||
March 31, 2010 | $ | 0.64 | April 22, 2010 | May 3, 2010 | May 14, 2010 | ||||||||
December 31, 2009 | $ | 0.64 | January 26, 2010 | February 5, 2010 | February 12, 2010 |
9. Commitments and Contingencies
Legal
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. was a party to an action styledEsmerejilda 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 captionedJesus 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 set forth claims for wrongful death, personal injury or
20
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
9. Commitments and Contingencies (Continued)
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 was dismissed on September 23, 2010 without prejudice for want of prosecution by the plaintiff.
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.
10. Incentive Compensation Plans
In April 2010, the Board granted 282,000 performance phantom units ("TUR Performance Units") under the 2008 LTIP to senior executives and other key employees. The TUR Performance Units are classified as equity awards and do not contain distribution equivalent rights. The TUR Performance Units vest in two equal installments on January 31, 2011 and January 31, 2012, subject to the Partnership's relative total unitholder return (unit price appreciation and distribution performance) over the three-year calendar period prior to the scheduled vesting date compared to the total unitholder return of a defined group of peer companies over the same period ("Market Criteria"). The TUR Performance Units will vest in accordance with the Partnership's relative ranking compared to the peer companies. Zero TUR Performance Units will vest if the Partnership's relative ranking is less than the 40th percentile; 50% of the TUR Performance Units will vest if the Partnership's relative ranking is in the 40th to 60th percentile; 75% of the TUR Performance Units will vest if the Partnership's relative ranking is in the 60th to 80th percentile; and 100% of the TUR Performance Units will vest if the Partnership's relative ranking is in the 80th to 100th percentile.
Additionally, the Board can increase or decrease the number of units to vest by up to 25% of the number of units that would otherwise vest based solely on the Market Criteria based on other performance criteria to be determined at the Board's discretion ("Performance Criteria"). The effect of these conditions is that vesting of 75%, or 211,500, of the TUR Performance Units will be determined solely by the Partnership's actual performance with regards to the Market Criteria. The remaining 25%, or 70,500, of the TUR Performance Units will vest based on a combination of the Market Criteria and the Performance Criteria.
The fair value of the TUR Performance Units is estimated using a Monte Carlo simulation model that determines the most likely outcome based on the terms of the award. The key inputs in the model include the market price of the Partnership's common units as of the valuation date, the historical volatility of the market price of the Partnership's common units, the historical volatility of the market price of the common units or common stock of the peer companies, and the correlation between changes in the market price of the Partnership's common units and those of the peer companies. Compensation expense related to 211,500 of the TUR Performance Units is recognized over the requisite service period based on the fair value of the units as of the grant date. However, a grant date, as defined by GAAP, has not been established for the other 70,500 TUR Performance Units because the Performance Criteria prevents a mutual understanding of the key terms of the award. Therefore, compensation expense related to 70,500 of the TUR Performance Units is recognized over the requisite
21
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
10. Incentive Compensation Plans (Continued)
service period based on the fair value of the units as of the current reporting date. The requisite service period for all TUR Performance Units began in April 2010 when the Board approved the awards. Compensation expense for the 70,500 TUR Performance Units may increase or decrease based on the probability of achieving the Performance Criteria.
Compensation Expense
Total compensation expense recorded for share-based pay arrangements is as follows (in thousands):
| Three months ended September 30, | Nine months ended September 30, | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | 2010 | 2009 | |||||||||
Phantom units | $ | 3,177 | $ | 1,583 | $ | 11,430 | $ | 5,755 | |||||
Distribution equivalent rights | 548 | 328 | 1,169 | 996 | |||||||||
Total compensation expense | $ | 3,725 | $ | 1,911 | $ | 12,599 | $ | 6,751 | |||||
As of September 30, 2010, total compensation expense not yet recognized related to the unvested awards under the 2008 LTIP was approximately $23.5 million, with a weighted-average remaining vesting period of approximately 1.0 years. Total compensation expense not yet recognized under the 2008 LTIP includes approximately $3.8 million related to the TUR Performance Units. Total compensation expense not yet recognized related to unvested awards under the 2002 LTIP was approximately $0.1 million, with a weighted-average remaining vesting period of approximately 0.3 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 in each of the Partnership's share-based compensation plans, 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. 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 nine months ended September 30, 2010 and 2009.
22
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
10. Incentive Compensation Plans (Continued)
2008 LTIP and 2006 Hydrocarbon Plan
The following is a summary of phantom unit activity under the 2008 LTIP and 2006 Hydrocarbon Plan, including the TUR Performance Units described above:
| Number of Units | Weighted-average Grant-date Fair Value(4) | ||||||
---|---|---|---|---|---|---|---|---|
Unvested at December 31, 2009(1) | 977,241 | $ | 22.00 | |||||
Granted(2)(3) | 732,188 | 27.97 | ||||||
Vested(2) | (363,502 | ) | 26.85 | |||||
Forfeited | (17,330 | ) | 20.00 | |||||
Unvested at September 30, 2010(1)(3) | 1,328,597 | 23.99 | ||||||
- (1)
- Includes 437,100 performance units granted to senior executives and other key employees that contain performance vesting criteria based on the Partnership's operating results. Compensation expense recognized for performance units expected to vest was zero for the three months ended September 30, 2010 and 2009, respectively, and zero and $0.3 million for the nine months ended September 30, 2010 and 2009, respectively.
- (2)
- In January 2010, the Board 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.
- (3)
- Includes 282,000 TUR Performance Units. Compensation expense recognized related to TUR Performance Units was approximately $1.4 million and $2.4 million for the three and nine months ended September 30, 2010, respectively.
- (4)
- The calculation of the weighted average grant-date fair value for units granted during the nine months ended September 30, 2010 includes the fair value as of September 30, 2010 for 70,500 TUR Performance Units. A grant date, as defined by GAAP, has not been established for these units.
| Three months ended September 30, | Nine months ended September 30, | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | 2010 | 2009 | |||||||||
| (in thousands) | (in thousands) | |||||||||||
Total grant-date fair value of phantom units granted during the period(1) | $ | 6,381 | $ | 47 | $ | 20,477 | $ | 3,705 | |||||
Total fair value of phantom units vested during the period and total intrinsic value of phantom units settled during the period | $ | 255 | $ | 414 | $ | 9,760 | $ | 9,478 |
- (1)
- The calculation of the grant-date fair value for units granted during the nine months ended September 30, 2010 includes the fair value of $1.8 million as of September 30,
23
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
10. Incentive Compensation Plans (Continued)
2010 for 70,500 TUR Performance Units. A grant date, as defined by GAAP, has not been established for these units.
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 | (44,942 | ) | 32.15 | |||||
Forfeited | (709 | ) | 34.00 | |||||
Unvested at September 30, 2010 | 23,904 | 33.83 | ||||||
| Three months ended September 30, | Nine months ended September 30, | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | 2010 | 2009 | |||||||||
| (in thousands) | (in thousands) | |||||||||||
Total fair value of phantom units vested during the period and total intrinsic value of phantom units settled during the period | $ | 57 | $ | 49 | $ | 1,312 | $ | 867 |
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 nine months ended September 30, 2010 and 2009 is as follows (in thousands):
| Nine months ended September 30, 2010 | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Corporation | Partnership | Eliminations | Consolidated | ||||||||||
Income before provision for income tax | $ | 5,303 | $ | 83,603 | $ | (4,401 | ) | $ | 84,505 | |||||
Federal statutory rate | 35 | % | 0 | % | 0 | % | ||||||||
Federal income tax at statutory rate | $ | 1,856 | $ | — | $ | — | $ | 1,856 | ||||||
Permanent items | 6 | — | — | 6 | ||||||||||
State income taxes net of federal benefit | 190 | 474 | — | 664 | ||||||||||
Provision on income from Class A units(1) | 8,251 | — | — | 8,251 | ||||||||||
Other | (568 | ) | — | — | (568 | ) | ||||||||
Provision for income tax | $ | 9,735 | $ | 474 | $ | — | $ | 10,209 | ||||||
24
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
11. Income Taxes (Continued)
| Nine months ended September 30, 2009 | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Corporation | Partnership | Eliminations | Consolidated | ||||||||||
Loss before provision for income tax | $ | (72,819 | ) | $ | (32,505 | ) | $ | (9,800 | ) | $ | (115,124 | ) | ||
Federal statutory rate | 35 | % | 0 | % | 0 | % | ||||||||
Federal income tax at statutory rate | $ | (25,486 | ) | $ | — | $ | — | $ | (25,486 | ) | ||||
Permanent items | (6 | ) | — | — | (6 | ) | ||||||||
State income taxes net of federal benefit | (1,794 | ) | (216 | ) | — | (2,010 | ) | |||||||
Provision on income from Class A units(1) | (1,072 | ) | — | — | (1,072 | ) | ||||||||
Excess book deduction related to equity compensation | 408 | 3 | — | 411 | ||||||||||
Provision for income tax | $ | (27,950 | ) | $ | (213 | ) | $ | — | $ | (28,163 | ) | |||
- (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.
12. (Loss) Earnings Per Common Unit
The following table shows the computation of basic and diluted net (loss) income per common unit for the three and nine months ended September 30, 2010 and 2009, and the weighted-average units used to compute diluted net (loss) income per common unit (in thousands, except per unit data):
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | 2010 | 2009 | |||||||||||
Net (loss) income attributable to the Partnership | $ | (27,151 | ) | $ | 8,280 | $ | 54,576 | $ | (88,875 | ) | |||||
Less: Income allocable to phantom units | 370 | 374 | 921 | 1,146 | |||||||||||
(Loss) income available for common unitholders | $ | (27,521 | ) | $ | 7,906 | $ | 53,655 | $ | (90,021 | ) | |||||
Weighted average common units outstanding—basic | 71,438 | 63,026 | 69,685 | 59,168 | |||||||||||
Effect of dilutive instruments(1) | — | — | 146 | — | |||||||||||
Weighted average common units outstanding—diluted | 71,438 | 63,026 | 69,831 | 59,168 | |||||||||||
Net (loss) income attributable to the Partnership's common unitholders per common unit | |||||||||||||||
Basic | $ | (0.39 | ) | $ | 0.13 | $ | 0.77 | $ | (1.52 | ) | |||||
Diluted | $ | (0.39 | ) | $ | 0.13 | $ | 0.77 | $ | (1.52 | ) |
- (1)
- Dilutive instruments include TUR Phantom Units and are based on the number of units, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period. For the three months ended September 30, 2010, 247 units were excluded from the calculation of diluted units because the impact was anti-dilutive. See Note 10 for further discussion on TUR Phantom Units.
25
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
13. Segment Information
The Partnership prepares segment information in accordance with GAAP. Certain items belowIncome (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.
The tables below present information about operating income for the three and nine months ended September 30, 2010 and 2009 and capital expenditures for the nine months ended September 30, 2010 and 2009 for the reported segments (in thousands).
Three Months Ended September 30, 2010 and 2009
Three months ended September 30, 2010: | Southwest | Northeast | Liberty | Gulf Coast | Total | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Revenue | $ | 159,044 | $ | 83,400 | $ | 28,606 | $ | 21,320 | $ | 292,370 | |||||||
Operating expenses: | |||||||||||||||||
Purchased product costs | 74,835 | 55,879 | 5,986 | — | 136,700 | ||||||||||||
Facility expenses | 20,659 | 5,268 | 5,668 | 8,785 | 40,380 | ||||||||||||
Total operating expenses before items not allocated to segments | 95,494 | 61,147 | 11,654 | 8,785 | 177,080 | ||||||||||||
Portion of operating income attributable to non-controlling interests | 1,906 | — | 6,772 | — | 8,678 | ||||||||||||
Operating income before items not allocated to segments | $ | 61,644 | $ | 22,253 | $ | 10,180 | $ | 12,535 | $ | 106,612 | |||||||
Three months ended September 30, 2009: | Southwest | Northeast | Liberty | Gulf Coast | Total | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Revenue | $ | 123,792 | $ | 55,554 | $ | 12,790 | $ | 15,797 | $ | 207,933 | |||||||
Operating expenses: | |||||||||||||||||
Purchased product costs | 53,425 | 34,506 | 3,155 | — | 91,086 | ||||||||||||
Facility expenses | 17,893 | 4,832 | 3,435 | 3,869 | 30,029 | ||||||||||||
Total operating expenses before items not allocated to segments | 71,318 | 39,338 | 6,590 | 3,869 | 121,115 | ||||||||||||
Portion of operating income attributable to non-controlling interests | 980 | — | 2,470 | — | 3,450 | ||||||||||||
Operating income before items not allocated to segments | $ | 51,494 | $ | 16,216 | $ | 3,730 | $ | 11,928 | $ | 83,368 | |||||||
26
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 (loss) income before provision for income tax for the three months ended September 30, 2010 and 2009 (in thousands).
| Three months ended September 30, | ||||||||
---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | |||||||
Total segment revenue | $ | 292,370 | $ | 207,933 | |||||
Derivative (loss) gain not allocated to segments | (36,959 | ) | 9,758 | ||||||
Total revenue | $ | 255,411 | $ | 217,691 | |||||
Operating income before items not allocated to segments | $ | 106,612 | $ | 83,368 | |||||
Portion of operating income attributable to non-controlling interests | 8,678 | 3,450 | |||||||
Derivative (loss) gain not allocated to segments | (56,391 | ) | 595 | ||||||
Compensation expense included in facility expenses not allocated to segments | (404 | ) | (243 | ) | |||||
Facility expenses adjustments | 2,850 | 107 | |||||||
Selling, general and administrative expenses | (17,137 | ) | (15,477 | ) | |||||
Depreciation | (31,362 | ) | (25,264 | ) | |||||
Amortization of intangible assets | (10,193 | ) | (10,193 | ) | |||||
Loss on disposal of property, plant and equipment | (1,937 | ) | (633 | ) | |||||
Accretion of asset retirement obligations | (70 | ) | (56 | ) | |||||
Income from operations | 646 | 35,654 | |||||||
Earnings from unconsolidated affiliates | — | 169 | |||||||
Interest income | 422 | 100 | |||||||
Interest expense | (26,433 | ) | (23,440 | ) | |||||
Amortization of deferred financing costs and discount (a component of interest expense) | (3,625 | ) | (3,091 | ) | |||||
Derivative gain related to interest expense | — | 2,265 | |||||||
Miscellaneous income, net | 76 | 825 | |||||||
(Loss) income before provision for income tax | $ | (28,914 | ) | $ | 12,482 | ||||
27
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
13. Segment Information (Continued)
Nine Months Ended September 30, 2010 and 2009
Nine months ended September 30, 2010: | Southwest | Northeast | Liberty | Gulf Coast | Total | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Revenue | $ | 479,051 | $ | 276,570 | $ | 66,354 | $ | 62,958 | $ | 884,933 | ||||||||
Operating expenses: | ||||||||||||||||||
Purchased product costs | 220,849 | 179,700 | 8,570 | — | 409,119 | |||||||||||||
Facility expenses | 60,543 | 14,555 | 19,121 | 23,875 | 118,094 | |||||||||||||
Total operating expenses before items not allocated to segments | 281,392 | 194,255 | 27,691 | 23,875 | 527,213 | |||||||||||||
Portion of operating income attributable to non-controlling interests | 4,962 | — | 15,617 | — | 20,579 | |||||||||||||
Operating income before items not allocated to segments | $ | 192,697 | $ | 82,315 | $ | 23,046 | $ | 39,083 | $ | 337,141 | ||||||||
Capital expenditures | $ | 89,949 | $ | 1,918 | $ | 275,620 | $ | 3,418 | $ | 370,905 | ||||||||
Capital expenditures not allocated to segments | 3,268 | |||||||||||||||||
Total capital expenditures | $ | 374,173 | ||||||||||||||||
Nine months ended September 30, 2009: | Southwest | Northeast | Liberty | Gulf Coast | Total | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Revenue | $ | 339,967 | $ | 165,765 | $ | 29,510 | $ | 41,058 | $ | 576,300 | ||||||||
Operating expenses: | ||||||||||||||||||
Purchased product costs | 150,456 | 117,540 | 6,056 | — | 274,052 | |||||||||||||
Facility expenses | 55,703 | 14,796 | 10,557 | 12,303 | 93,359 | |||||||||||||
Total operating expenses before items not allocated to segments | 206,159 | 132,336 | 16,613 | 12,303 | 367,411 | |||||||||||||
Portion of operating income attributable to non-controlling interests | 1,007 | — | 4,113 | — | 5,120 | |||||||||||||
Operating income before items not allocated to segments | $ | 132,801 | $ | 33,429 | $ | 8,784 | $ | 28,755 | $ | 203,769 | ||||||||
Capital expenditures | $ | 197,977 | $ | 20,447 | $ | 131,315 | $ | 36,227 | $ | 385,966 | ||||||||
Capital expenditures not allocated to segments | 2,536 | |||||||||||||||||
Total capital expenditures | $ | 388,502 | ||||||||||||||||
28
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 nine months ended September 30, 2010 and 2009 (in thousands).
| Nine months ended September 30, | ||||||||
---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | |||||||
Total segment revenue | $ | 884,933 | $ | 576,300 | |||||
Derivative gain (loss) not allocated to segments | 2,707 | (65,173 | ) | ||||||
Total revenue | $ | 887,640 | $ | 511,127 | |||||
Operating income before items not allocated to segments | $ | 337,141 | $ | 203,769 | |||||
Portion of operating income attributable to non-controlling interests | 20,579 | 5,120 | |||||||
Derivative loss not allocated to segments | (21,850 | ) | (105,249 | ) | |||||
Compensation expense included in facility expenses not allocated to segments | (1,412 | ) | (801 | ) | |||||
Facility expenses adjustments | 6,240 | 215 | |||||||
Selling, general and administrative expenses | (55,064 | ) | (46,265 | ) | |||||
Depreciation | (89,367 | ) | (69,621 | ) | |||||
Amortization of intangible assets | (30,579 | ) | (30,638 | ) | |||||
Loss on disposal of property, plant and equipment | (2,116 | ) | (1,432 | ) | |||||
Accretion of asset retirement obligations | (282 | ) | (147 | ) | |||||
Impairment of long-lived assets | — | (5,855 | ) | ||||||
Income (loss) from operations | 163,290 | (50,904 | ) | ||||||
Earnings from unconsolidated affiliates | 1,517 | 1,260 | |||||||
Interest income | 1,185 | 201 | |||||||
Interest expense | (75,970 | ) | (63,964 | ) | |||||
Amortization of deferred financing costs and discount (a component of interest expense) | (8,517 | ) | (6,528 | ) | |||||
Derivative gain related to interest expense | 1,871 | 2,265 | |||||||
Miscellaneous income, net | 1,129 | 2,546 | |||||||
Income (loss) before provision for income tax | $ | 84,505 | $ | (115,124 | ) | ||||
29
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 September 30, 2010 and December 31, 2009 (in thousands):
| September 30, 2010 | December 31, 2009 | ||||||
---|---|---|---|---|---|---|---|---|
Southwest | $ | 1,657,548 | $ | 1,637,749 | ||||
Northeast | 236,558 | 249,804 | ||||||
Liberty | 669,766 | 373,127 | ||||||
Gulf Coast | 589,169 | 587,830 | ||||||
Total segment assets | 3,153,041 | 2,848,510 | ||||||
Assets not allocated to segments: | ||||||||
Certain cash and cash equivalents | 59,884 | 73,184 | ||||||
Fair value of derivatives | 19,489 | 24,631 | ||||||
Investment in unconsolidated affiliate | 28,642 | 29,633 | ||||||
Other(1) | 33,262 | 38,779 | ||||||
Total assets | $ | 3,294,318 | $ | 3,014,737 | ||||
- (1)
- As of September 30, 2010, includes corporate fixed assets, deferred financing costs, receivables and other corporate assets not allocated to segments. As of December 31, 2009, 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 September 30, 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 September 30,
30
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
14. Supplemental Condensed Consolidating Financial Information (Continued)
2010 and December 31, 2009 and for the three and nine months ended September 30, 2010 and 2009 is as follows (in thousands):
Condensed Consolidating Balance Sheets
| As of September 30, 2010 | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | Consolidated | |||||||||||||
ASSETS | ||||||||||||||||||
Current assets: | ||||||||||||||||||
Cash and cash equivalents | $ | — | $ | 62,268 | $ | 36,227 | $ | — | $ | 98,495 | ||||||||
Receivables and other current assets | 1,159 | 182,111 | 42,464 | (18 | ) | 225,716 | ||||||||||||
Intercompany receivables | 1,512,364 | 761 | 9,689 | (1,522,814 | ) | — | ||||||||||||
Fair value of derivative instruments | — | 12,427 | — | — | 12,427 | |||||||||||||
Total current assets | 1,513,523 | 257,567 | 88,380 | (1,522,832 | ) | 336,638 | ||||||||||||
Total property, plant and equipment, net | 3,723 | 1,517,832 | 746,308 | (10,181 | ) | 2,257,682 | ||||||||||||
Other long-term assets: | ||||||||||||||||||
Investment in unconsolidated affiliate | — | 28,642 | — | — | 28,642 | |||||||||||||
Investment in consolidated affiliates | 685,782 | 326,978 | — | (1,012,760 | ) | — | ||||||||||||
Intangibles, net of accumulated amortization | — | 623,245 | 587 | — | 623,832 | |||||||||||||
Fair value of derivative instruments | — | 7,062 | — | — | 7,062 | |||||||||||||
Intercompany notes receivable | 211,610 | — | — | (211,610 | ) | — | ||||||||||||
Other long-term assets | 27,037 | 13,138 | 287 | — | 40,462 | |||||||||||||
Total assets | $ | 2,441,675 | $ | 2,774,464 | $ | 835,562 | $ | (2,757,383 | ) | $ | 3,294,318 | |||||||
LIABILITIES AND EQUITY | ||||||||||||||||||
Current liabilities: | ||||||||||||||||||
Intercompany payables | $ | 683 | $ | 1,522,053 | $ | 78 | $ | (1,522,814 | ) | $ | — | |||||||
Fair value of derivative instruments | — | 52,084 | — | — | 52,084 | |||||||||||||
Other current liabilities | 42,230 | 136,607 | 62,411 | (18 | ) | 241,230 | ||||||||||||
Total current liabilities | 42,913 | 1,710,744 | 62,489 | (1,522,832 | ) | 293,314 | ||||||||||||
Deferred income taxes | 1,902 | 9,094 | — | — | 10,996 | |||||||||||||
Intercompany notes payable | — | 211,610 | — | (211,610 | ) | — | ||||||||||||
Fair value of derivative instruments | — | 54,033 | — | — | 54,033 | |||||||||||||
Long-term debt, net of discounts | 1,216,194 | — | — | — | 1,216,194 | |||||||||||||
Other long-term liabilities | 3,387 | 103,201 | 409 | — | 106,997 | |||||||||||||
Equity: | ||||||||||||||||||
MarkWest Energy Partners, L.P. partners' capital | 1,177,279 | 685,782 | 772,664 | (1,468,627 | ) | 1,167,098 | ||||||||||||
Non-controlling interest in consolidated subsidiaries | — | — | — | 445,686 | 445,686 | |||||||||||||
Total equity | 1,177,279 | 685,782 | 772,664 | (1,022,941 | ) | 1,612,784 | ||||||||||||
Total liabilities and equity | $ | 2,441,675 | $ | 2,774,464 | $ | 835,562 | $ | (2,757,383 | ) | $ | 3,294,318 | |||||||
31
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 | |||||||
32
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 September 30, 2010 | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | Consolidated | |||||||||||||
Total revenue | $ | — | $ | 222,004 | $ | 33,407 | $ | — | $ | 255,411 | ||||||||
Operating expenses: | ||||||||||||||||||
Purchased product costs | — | 150,689 | 6,007 | — | 156,696 | |||||||||||||
Facility expenses | — | 30,931 | 6,602 | (163 | ) | 37,370 | ||||||||||||
Selling, general and administrative expenses | 12,203 | 4,842 | 1,354 | (1,262 | ) | 17,137 | ||||||||||||
Depreciation and amortization | 147 | 34,400 | 7,117 | (109 | ) | 41,555 | ||||||||||||
Other operating expenses | 730 | 1,269 | 8 | — | 2,007 | |||||||||||||
Total operating expenses | 13,080 | 222,131 | 21,088 | (1,534 | ) | 254,765 | ||||||||||||
(Loss) income from operations | (13,080 | ) | (127 | ) | 12,319 | 1,534 | 646 | |||||||||||
Earnings from consolidated affiliates | 9,249 | 4,256 | — | (13,505 | ) | — | ||||||||||||
Other (expense) income, net | (21,539 | ) | (5,097 | ) | 412 | (3,336 | ) | (29,560 | ) | |||||||||
(Loss) income before provision for income tax | (25,370 | ) | (968 | ) | 12,731 | (15,307 | ) | (28,914 | ) | |||||||||
Provision for income tax benefit | (21 | ) | (10,217 | ) | — | — | (10,238 | ) | ||||||||||
Net (loss) income | (25,349 | ) | 9,249 | 12,731 | (15,307 | ) | (18,676 | ) | ||||||||||
Net income attributable to non-controlling interest | — | — | — | (8,475 | ) | (8,475 | ) | |||||||||||
Net (loss) income attributable to the Partnership | $ | (25,349 | ) | $ | 9,249 | $ | 12,731 | $ | (23,782 | ) | $ | (27,151 | ) | |||||
33
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
14. Supplemental Condensed Consolidating Financial Information (Continued)
| Three Months Ended September 30, 2009 | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | Consolidated | |||||||||||||
Total revenue | $ | — | $ | 202,183 | $ | 15,508 | $ | — | $ | 217,691 | ||||||||
Operating expenses: | ||||||||||||||||||
Purchased product costs | — | 95,726 | 3,176 | — | 98,902 | |||||||||||||
Facility expenses | — | 27,570 | 4,049 | (107 | ) | 31,512 | ||||||||||||
Selling, general and administrative expenses | 10,732 | 5,102 | 700 | (1,057 | ) | 15,477 | ||||||||||||
Depreciation and amortization | 137 | 31,579 | 3,793 | (52 | ) | 35,457 | ||||||||||||
Other operating expenses | — | 687 | 2 | — | 689 | |||||||||||||
Total operating expenses | 10,869 | 160,664 | 11,720 | (1,216 | ) | 182,037 | ||||||||||||
(Loss) income from operations | (10,869 | ) | 41,519 | 3,788 | 1,216 | 35,654 | ||||||||||||
Earnings from consolidated affiliates | 39,900 | 877 | — | (40,777 | ) | — | ||||||||||||
Other (expense) income, net | (20,186 | ) | (2,049 | ) | 713 | (1,650 | ) | (23,172 | ) | |||||||||
Income before provision for income tax | 8,845 | 40,347 | 4,501 | (41,211 | ) | 12,482 | ||||||||||||
Provision for income tax expense | 131 | 447 | — | — | 578 | |||||||||||||
Net income | 8,714 | 39,900 | 4,501 | (41,211 | ) | 11,904 | ||||||||||||
Net income attributable to non-controlling interest | — | — | — | (3,624 | ) | (3,624 | ) | |||||||||||
Net income attributable to the Partnership | $ | 8,714 | $ | 39,900 | $ | 4,501 | $ | (44,835 | ) | $ | 8,280 | |||||||
34
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
14. Supplemental Condensed Consolidating Financial Information (Continued)
| Nine Months Ended September 30, 2010 | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | Consolidated | |||||||||||||
Total revenue | $ | — | $ | 807,585 | $ | 80,055 | $ | — | $ | 887,640 | ||||||||
Operating expenses: | ||||||||||||||||||
Purchased product costs | — | 425,469 | 8,643 | — | 434,112 | |||||||||||||
Facility expenses | — | 91,074 | 22,245 | (489 | ) | 112,830 | ||||||||||||
Selling, general and administrative expenses | 35,243 | 19,370 | 4,141 | (3,690 | ) | 55,064 | ||||||||||||
Depreciation and amortization | 438 | 101,034 | 18,739 | (265 | ) | 119,946 | ||||||||||||
Other operating expenses | 730 | 1,364 | 304 | — | 2,398 | |||||||||||||
Total operating expenses | 36,411 | 638,311 | 54,072 | (4,444 | ) | 724,350 | ||||||||||||
(Loss) income from operations | (36,411 | ) | 169,274 | 25,983 | 4,444 | 163,290 | ||||||||||||
Earnings from consolidated affiliates | 156,634 | 7,521 | — | (164,155 | ) | — | ||||||||||||
Other (expense) income, net | (60,675 | ) | (10,427 | ) | 1,258 | (8,941 | ) | (78,785 | ) | |||||||||
Income before provision for income tax | 59,548 | 166,368 | 27,241 | (168,652 | ) | 84,505 | ||||||||||||
Provision for income tax expense | 475 | 9,734 | — | — | 10,209 | |||||||||||||
Net income | 59,073 | 156,634 | 27,241 | (168,652 | ) | 74,296 | ||||||||||||
Net income attributable to non-controlling interest | — | — | — | (19,720 | ) | (19,720 | ) | |||||||||||
Net income attributable to the Partnership | $ | 59,073 | $ | 156,634 | $ | 27,241 | $ | (188,372 | ) | $ | 54,576 | |||||||
35
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
14. Supplemental Condensed Consolidating Financial Information (Continued)
| Nine Months Ended September 30, 2009 | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | Consolidated | |||||||||||||
Total revenue | $ | — | $ | 482,222 | $ | 28,905 | $ | — | $ | 511,127 | ||||||||
Operating expenses: | ||||||||||||||||||
Purchased product costs | — | 307,901 | 6,105 | — | 314,006 | |||||||||||||
Facility expenses | — | 83,783 | 10,499 | (215 | ) | 94,067 | ||||||||||||
Selling, general and administrative expenses | 33,861 | 13,076 | 1,697 | (2,369 | ) | 46,265 | ||||||||||||
Depreciation and amortization | 423 | 93,432 | 6,498 | (94 | ) | 100,259 | ||||||||||||
Other operating expenses | — | 1,576 | 3 | — | 1,579 | |||||||||||||
Impairment of long-lived assets | — | — | 5,855 | — | 5,855 | |||||||||||||
Total operating expenses | 34,284 | 499,768 | 30,657 | (2,678 | ) | 562,031 | ||||||||||||
Loss from operations | (34,284 | ) | (17,546 | ) | (1,752 | ) | 2,678 | (50,904 | ) | |||||||||
(Loss) earnings from consolidated affiliates | (313 | ) | 186 | — | 127 | — | ||||||||||||
Other (expense) income, net | (49,976 | ) | (10,904 | ) | 3,852 | (7,192 | ) | (64,220 | ) | |||||||||
(Loss) income before provision for income tax | (84,573 | ) | (28,264 | ) | 2,100 | (4,387 | ) | (115,124 | ) | |||||||||
Provision for income tax benefit | (212 | ) | (27,951 | ) | — | — | (28,163 | ) | ||||||||||
Net (loss) income | (84,361 | ) | (313 | ) | 2,100 | (4,387 | ) | (86,961 | ) | |||||||||
Net income attributable to non-controlling interest | — | — | — | (1,914 | ) | (1,914 | ) | |||||||||||
Net (loss) income attributable to the Partnership | $ | (84,361 | ) | $ | (313 | ) | $ | 2,100 | $ | (6,301 | ) | $ | (88,875 | ) | ||||
36
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
| Nine Months Ended September 30, 2010 | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | Consolidated | |||||||||||||
Net cash (used in) provided by operating activities | $ | (63,740 | ) | $ | 230,279 | $ | 35,460 | $ | (4,761 | ) | $ | 197,238 | ||||||
Cash flows from investing activities: | ||||||||||||||||||
Capital expenditures | (569 | ) | (97,039 | ) | (281,326 | ) | 4,761 | (374,173 | ) | |||||||||
Equity investments | (32,442 | ) | (130,074 | ) | — | 162,516 | — | |||||||||||
Distributions from consolidated affiliates | 33,237 | 14,512 | — | (47,749 | ) | — | ||||||||||||
Payments for intercompany notes, net | (1,550 | ) | — | — | 1,550 | — | ||||||||||||
Proceeds from disposal of property, plant and equipment | — | 524 | — | — | 524 | |||||||||||||
Net cash flows used in investing activities | (1,324 | ) | (212,077 | ) | (281,326 | ) | 121,078 | (373,649 | ) | |||||||||
Cash flows from financing activities: | ||||||||||||||||||
Proceeds from revolving credit facility | 421,304 | — | — | — | 421,304 | |||||||||||||
Payments of revolving credit facility | (378,804 | ) | — | — | — | (378,804 | ) | |||||||||||
Proceeds from intercompany notes, net | — | 1,550 | — | (1,550 | ) | — | ||||||||||||
Payments for debt issuance costs, deferred financing costs and registration costs | (11,230 | ) | — | — | — | (11,230 | ) | |||||||||||
Contributions from parent, net | — | 32,442 | — | (32,442 | ) | — | ||||||||||||
Contributions to joint ventures, net | — | — | 278,131 | (130,074 | ) | 148,057 | ||||||||||||
Payments of SMR liability | — | (912 | ) | — | — | (912 | ) | |||||||||||
Proceeds from public offering, net | 142,255 | — | — | — | 142,255 | |||||||||||||
Share-based payment activity | (3,834 | ) | 97 | — | — | (3,737 | ) | |||||||||||
Payment of distributions | (134,949 | ) | (33,237 | ) | (19,342 | ) | 47,749 | (139,779 | ) | |||||||||
Intercompany advances, net | 30,322 | (30,322 | ) | — | — | — | ||||||||||||
Net cash flows provided by (used in) financing activities | 65,064 | (30,382 | ) | 258,789 | (116,317 | ) | 177,154 | |||||||||||
Net (decrease) increase in cash | — | (12,180 | ) | 12,923 | — | 743 | ||||||||||||
Cash and cash equivalents at beginning of year | — | 74,448 | 23,304 | — | 97,752 | |||||||||||||
Cash and cash equivalents at end of period | $ | — | $ | 62,268 | $ | 36,227 | $ | — | $ | 98,495 | ||||||||
37
MARKWEST ENERGY PARTNERS, L.P.
Notes to the Condensed Consolidated Financial Statements (Continued)
(unaudited)
14. Supplemental Condensed Consolidating Financial Information (Continued)
| Nine Months Ended September 30, 2009 | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Consolidating Adjustments | Consolidated | |||||||||||||
Net cash (used in) provided by operating activities | $ | (61,492 | ) | $ | 210,814 | $ | 3,151 | $ | (4,608 | ) | $ | 147,865 | ||||||
Cash flows from investing activities: | ||||||||||||||||||
Capital expenditures | (738 | ) | (164,282 | ) | (228,090 | ) | 4,608 | (388,502 | ) | |||||||||
Equity investments | (39,038 | ) | (129,871 | ) | — | 162,474 | (6,435 | ) | ||||||||||
Proceeds from disposal of property, plant and equipment | — | 275 | — | — | 275 | |||||||||||||
Change in restricted cash | — | — | (10,025 | ) | — | (10,025 | ) | |||||||||||
Distributions from consolidated affiliates | 10,803 | 31,152 | — | (41,955 | ) | — | ||||||||||||
Collection of intercompany notes, net | 7,790 | — | — | (7,790 | ) | — | ||||||||||||
Proceeds from sale of equity interest in consolidated subsidiary | — | 62,500 | — | (62,500 | ) | — | ||||||||||||
Net cash flows used in investing activities | (21,183 | ) | (200,226 | ) | (238,115 | ) | 54,837 | (404,687 | ) | |||||||||
Cash flows from financing activities: | ||||||||||||||||||
Proceeds from revolving credit facility | 568,000 | — | — | — | 568,000 | |||||||||||||
Payments of revolving credit facility | (700,900 | ) | — | — | — | (700,900 | ) | |||||||||||
Proceeds from long-term debt | 117,000 | — | — | — | 117,000 | |||||||||||||
Payments of intercompany notes, net | — | (7,790 | ) | — | 7,790 | — | ||||||||||||
Payments for debt issuance costs, deferred financing costs and registration costs | (7,881 | ) | (500 | ) | — | — | (8,381 | ) | ||||||||||
Proceeds from SMR transaction | — | 73,129 | — | — | 73,129 | |||||||||||||
Proceeds from public offerings, net | 178,632 | — | — | — | 178,632 | |||||||||||||
Contributions from parent, net | — | 39,038 | — | (39,038 | ) | — | ||||||||||||
Contributions to joint ventures, net | (5,464 | ) | — | 273,436 | (123,436 | ) | 144,536 | |||||||||||
Proceeds from sale of equity interest in joint venture, net | (1,847 | ) | — | — | 62,500 | 60,653 | ||||||||||||
Share-based payment activity | (1,257 | ) | — | — | — | (1,257 | ) | |||||||||||
Payment of distributions | (112,525 | ) | (10,803 | ) | (31,232 | ) | 41,955 | (112,605 | ) | |||||||||
Intercompany advances, net | 48,917 | (48,917 | ) | — | — | — | ||||||||||||
Net cash flows provided by financing activities | 82,675 | 44,157 | 242,204 | (50,229 | ) | 318,807 | ||||||||||||
Net increase in cash | — | 54,745 | 7,240 | — | 61,985 | |||||||||||||
Cash and cash equivalents at beginning of year | — | — | 3,321 | — | 3,321 | |||||||||||||
Cash and cash equivalents at end of period | $ | — | $ | 54,745 | $ | 10,561 | $ | — | $ | 65,306 | ||||||||
38
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).
| Nine months ended September 30, | ||||||
---|---|---|---|---|---|---|---|
| 2010 | 2009 | |||||
Supplemental disclosures of cash flow information: | |||||||
Cash paid for interest, net of amounts capitalized | $ | 64,448 | $ | 51,514 | |||
Cash paid for income taxes, net of refunds | 8,760 | 4,529 | |||||
Supplemental schedule of non-cash investing and financing activities: | |||||||
Accrued property, plant and equipment | $ | 53,381 | $ | 24,322 | |||
Interest capitalized on construction in progress | 2,719 | 9,262 | |||||
Property, plant and equipment asset retirement obligation | 749 | 821 | |||||
Issuance of common units for vesting of share-based payment awards | 7,238 | 9,088 |
16. Subsequent Events
Senior Notes
On November 2, 2010, the Partnership and its subsidiary MarkWest Energy Finance Corporation completed a public offering of $500 million in aggregate principal amount of 6.75% senior unsecured notes due 2020 (the "2020 Senior Notes"). The Partnership received proceeds of approximately $491 million, net of expenses. Under the indenture governing the 2020 Senior Notes, the Partnership is subject to a number of restrictions and covenants, which are substantially the same as the restrictions and covenants governing the Partnership's other Senior Notes.
The Partnership used a portion of the net proceeds from the 2020 Senior Notes offering to repurchase 94% of the outstanding $225 million aggregate principal amount of its 6.875% Senior Notes due 2014 and $150 million aggregate principal amount of its 6.875% Senior Notes due 2014. The remaining proceeds will be used to repurchase the remaining outstanding 2014 Senior Notes, to repay all borrowings outstanding under the Partnership's Credit Facility, and to provide working capital for general partnership purposes.
The Partnership will record a pre-tax loss on redemption of debt of approximately $46 million in the fourth quarter of 2010, which consists of approximately $37 million for the non-cash write-off of the unamortized discount and deferred finance costs associated with the 2014 Senior Notes and approximately $9 million for the payment of the related call and tender premiums.
39
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Forward-Looking Statements
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. Statements that are not historical facts are forward-looking statements. We use words such as "could," "may," "predict," "should," "expect," "hope," "continue," "potential," "plan," "intend," "anticipate," "project," "believe," "estimate," and similar expressions to identify forward-looking statements. These statements are based on current expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. Forward-looking statements are not guarantees and actual results could differ materially from those expressed or implied in the forward-looking statements as a result of a number of factors. We do not update publicly any forward-looking statement with new information or future events. Undue reliance should not be placed on forward-looking statements as many of these factors are beyond our ability to control or predict.
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
Significant financial and other highlights for the three months ended September 30, 2010 are listed below. Refer toResults of Operations andLiquidity and Capital Resources for further details.
- •
- Total segment operating income before items not allocated to segments increased approximately $23.2 million, or 28%, for the three months ended September 30, 2010 compared to the same period in 2009 (seeResults of Operations for a reconciliation of segment operating income before items not allocated to segments to our consolidated (loss) income before provision for income tax). The increase is due primarily to higher commodity prices in 2010, expanding operations in our Liberty segment, increased volumes from the Granite Wash formation and increased volumes from a large producer in the Woodford system.
- •
- In July 2010, we entered into the Credit Facility, which currently provides a committed borrowing capacity of up to $705 million, with an uncommitted accordion feature of up to $195 million. Additionally, as a result of adding a new member to the bank group, all of our financial derivative positions are currently with participating bank group members and we are not subject to any margin requirements.
- •
- During the three months ended September 30, 2010, we received $27.5 million of contributions to MarkWest Liberty Midstream from M&R.
Net Operating Margin (a non-GAAP financial measure)
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
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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.
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 September 30, | Nine months ended September 30, | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | 2010 | 2009 | ||||||||||
Revenue | $ | 292,370 | $ | 207,933 | $ | 884,933 | $ | 576,300 | ||||||
Purchased product costs | 136,700 | 91,086 | 409,119 | 274,052 | ||||||||||
Net operating margin | 155,670 | 116,847 | 475,814 | 302,248 | ||||||||||
Facility expenses | 37,934 | 30,165 | 113,266 | 93,945 | ||||||||||
Derivative loss (gain) | 56,391 | (595 | ) | 21,850 | 105,249 | |||||||||
Selling, general and administrative expenses | 17,137 | 15,477 | 55,064 | 46,265 | ||||||||||
Depreciation | 31,362 | 25,264 | 89,367 | 69,621 | ||||||||||
Amortization of intangible assets | 10,193 | 10,193 | 30,579 | 30,638 | ||||||||||
Loss on disposal of property, plant and equipment | 1,937 | 633 | 2,116 | 1,432 | ||||||||||
Accretion of asset retirement obligations | 70 | 56 | 282 | 147 | ||||||||||
Impairment of long-lived assets | — | — | — | 5,855 | ||||||||||
Income (loss) from operations | $ | 646 | $ | 35,654 | $ | 163,290 | $ | (50,904 | ) | |||||
Our Contracts
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.Business—Our 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 nine months ended September 30, 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 | 20 | % | 39 | % | 4 | % | 37 | % | 100 | % | ||||||
Net operating margin(4) | 39 | % | 31 | % | 0 | % | 30 | % | 100 | % |
- (1)
- Includes condensate sales and other types of arrangements tied to NGL prices.
- (2)
- Includes arrangements tied to natural gas prices.
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- (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.
Seasonality
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
Segment Reporting
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.
- •
- 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. For natural gas that is processed in this area, 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. Natural gas gathered in the Woodford system is processed by Centrahoma, our equity investment discussed below.
Southwest
- •
- 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,
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.
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- •
- 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. The Appalachia operations include fractionation and marketing services on behalf of the Liberty segment.
- •
- Michigan. We own and operate a FERC-regulated crude oil pipeline in Michigan that provides transportation services for three shippers.
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.
Northeast
- •
- 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 155 MMcf/d of cryogenic processing capacity 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 also plan to complete a 60,000 Bbl/d fractionation facility at our Houston complex in 2011. We commenced operation 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 at our Majorsville site to approximately 270 MMcf/d by the third quarter of 2011. We expect the total planned processing capacity to be supported by long-term agreements with our producer customers. Until we have completed construction of our Houston fractionation facility substantially all of the raw NGLs produced at our Liberty facilities are fractionated at the Siloam NGL fractionation plant in our Northeast segment, although certain volumes of propane and raw NGLs produced at the Liberty facilities are sold without fractionation at Siloam. We have completed construction of an interconnect with a key interstate NGL pipeline providing an additional market outlet for the propane. In addition, we are developing a market outlet for the ethane produced in the Marcellus Shale through a combined pipeline and marine project ("Mariner Project") to deliver purity ethane to Gulf Coast markets. The Mariner Project is a joint project with Sunoco Logistics that is anticipated to have initial capacity to transport up to 50,000 Bbl/d of ethane by mid-2012 and may be expanded to support additional Marcellus production.
Liberty
MarkWest Liberty Midstream and NiSource Gas Transmission & Storage ("NGT&S") intend to jointly develop natural gas gathering, processing, and transmission projects to support increased Marcellus production volumes in the northern West Virginia area of the Appalachian Basin. It is anticipated that the joint project would initially include existing and new pipelines that deliver gas to NGT&S' Smithfield, West Virginia compressor station where MarkWest Liberty Midstream would install a 120 MMcf/d cryogenic processing facility. MarkWest Liberty Midstream would complement these processing facilities with fractionation services provided at its Houston, Pennsylvania NGL fractionation, storage, and marketing complex to take advantage of the premium regional markets and to maximize the value of the producers' gas.
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- •
- Javelina. We own and operate the Javelina processing facility, a natural gas processing facility in Corpus Christi, Texas that 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 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.
Gulf Coast
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 nine months ended September 30, 2010:
| Southwest | Northeast | Liberty | Gulf Coast | Total | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Revenue | 54 | % | 31 | % | 8 | % | 7 | % | 100 | % | ||||||
Net operating margin | 54 | % | 21 | % | 12 | % | 13 | % | 100 | % |
Equity Investment in Unconsolidated Affiliate
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 long-term agreements to dedicate our processing rights in certain acreage in the Woodford Shale to Centrahoma. The financial results for Centrahoma are included inEarnings from unconsolidated affiliates and are not included in our segment results.
Three months ended September 30, 2010 compared to three months ended September 30, 2009
Items belowIncome (loss) from operations in our Condensed Consolidated Statements of Operations, certain compensation expense, certain other non-cash items and any 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 September 30, 2010 and 2009.
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| Three months ended September 30, | | | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | $ Change | % Change | ||||||||||
| (in thousands) | | ||||||||||||
Revenue | $ | 159,044 | $ | 123,792 | $ | 35,252 | 28 | % | ||||||
Operating expenses: | ||||||||||||||
Purchased product costs | 74,835 | 53,425 | 21,410 | 40 | % | |||||||||
Facility expenses | 20,659 | 17,893 | 2,766 | 15 | % | |||||||||
Total operating expenses before items not allocated to segments | 95,494 | 71,318 | 24,176 | 34 | % | |||||||||
Portion of operating income attributable to non-controlling interests | 1,906 | 980 | 926 | 94 | % | |||||||||
Operating income before items not allocated to segments | $ | 61,644 | $ | 51,494 | $ | 10,150 | 20 | % | ||||||
Revenue. Revenue increased primarily due to higher commodity prices. Revenue from NGL, natural gas and condensate sales increased approximately $28.3 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 $5.5 million due to the start of the Arkoma Connector Pipeline in mid-July 2009 and higher gathered volumes in the Woodford Shale and Stiles Ranch. The increase in revenue was partially offset by a decrease in gathered volumes in the Foss Lake, East Texas and the Other Southwest areas. The decline in gathered volumes in these conventional natural gas formations is expected to continue until natural gas prices improve.
Purchased Product Costs. Purchased product costs increased primarily due to higher overall commodity prices and increased volumes in the Woodford Shale and Stiles Ranch, which was partially offset by a decrease in gathered volumes in East Texas and the Other Southwest areas.
Facility Expenses. Facility expenses increased primarily due to higher operating expenses in Southeast Oklahoma resulting from the start of the Arkoma Connector Pipeline in mid-July 2009 and increased volumes. The increase was partially offset by a reduction in repairs and maintenance expense related to environmental costs in 2009 in East Texas that did not recur in 2010.
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 growth in the Arkoma Connector Pipeline operations.
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Northeast
| Three months ended September 30, | | | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | $ Change | % Change | ||||||||||
| (in thousands) | | ||||||||||||
Revenue | $ | 83,400 | $ | 55,554 | $ | 27,846 | 50 | % | ||||||
Operating expenses: | ||||||||||||||
Purchased product costs | 55,879 | 34,506 | 21,373 | 62 | % | |||||||||
Facility expenses | 5,268 | 4,832 | 436 | 9 | % | |||||||||
Total operating expenses before items not allocated to segments | 61,147 | 39,338 | 21,809 | 55 | % | |||||||||
Operating income before items not allocated to segments | $ | 22,253 | $ | 16,216 | $ | 6,037 | 37 | % | ||||||
Revenue. Revenue increased primarily due to higher commodity prices realized on NGL sales, as well as an increase in volumes from a significant customer under a percent-of-proceeds arrangement. The increase in revenue was partially offset by a decrease in volumes processed under keep-whole arrangements primarily due to the temporary closure of a significant transmission pipeline. The pipeline closure's overall impact on future volumes is uncertain.
Purchased Product Costs. Purchased product costs increased due to higher prices and higher volumes for the natural gas that is purchased to satisfy the keep-whole arrangements.
Facility Expenses. Facility expenses increased primarily due to higher repairs and maintenance expense.
| Three months ended September 30, | | | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | $ Change | % Change | ||||||||||
| (in thousands) | | ||||||||||||
Revenue | $ | 28,606 | $ | 12,790 | $ | 15,816 | 124 | % | ||||||
Operating expenses: | ||||||||||||||
Purchased product costs | 5,986 | 3,155 | 2,831 | 90 | % | |||||||||
Facility expenses | 5,668 | 3,435 | 2,233 | 65 | % | |||||||||
Total operating expenses before items not allocated to segments | 11,654 | 6,590 | 5,064 | 77 | % | |||||||||
Portion of operating income attributable to non-controlling interests | 6,772 | 2,470 | 4,302 | 174 | % | |||||||||
Operating income before items not allocated to segments | $ | 10,180 | $ | 3,730 | $ | 6,450 | 173 | % | ||||||
Revenue. Revenue increased due to ongoing expansion of the Liberty operations and higher NGL prices. Revenue increased approximately $8.3 million related to gathering and compression fees and approximately $7.6 million related to NGL sales.
Purchased Product Costs. Purchased product costs increased primarily due to the purchase of product from certain producers. On June 30 and during the third quarter of 2010, the Liberty segment agreed to purchase certain NGLs from the producers' inventory at the end of each month, whereas prior to this agreement the Liberty segment did not purchase any NGLs and acted solely as the
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producers' agent providing processing, storage and marketing services. In 2009, purchased product costs related to an interim plant that ceased operations in January 2010.
Facility Expenses. Facility expenses increased primarily due to the ongoing expansion of the Liberty operations.
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 ongoing expansion of the Liberty operations.
| Three months ended September 30, | | | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | $ Change | % Change | ||||||||||
| (in thousands) | | ||||||||||||
Revenue | $ | 21,320 | $ | 15,797 | $ | 5,523 | 35 | % | ||||||
Operating expenses: | ||||||||||||||
Facility expenses | 8,785 | 3,869 | 4,916 | 127 | % | |||||||||
Total operating expenses before items not allocated to segments | 8,785 | 3,869 | 4,916 | 127 | % | |||||||||
Operating income before items not allocated to segments | $ | 12,535 | $ | 11,928 | $ | 607 | 5 | % | ||||||
Revenue. Revenue increased primarily due to $5.0 million related to the SMR and higher commodity prices. The revenue increases were partially offset by lower volumes due to power outages in July caused by Hurricane Alex.
Facility Expenses. Facility expenses increased primarily due to $4.6 million of SMR operating expenses, as well as increased repairs and maintenance expense.
Reconciliation of Segment Operating Income to Consolidated (Loss) Income 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 (loss) income before provision for income tax for the three months ended September 30, 2010 and 2009. The ensuing items listed below
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theTotal segment revenue andOperating income lines are not allocated to business segments as management does not consider these items allocable to any individual segment.
| Three months ended September 30, | | | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | $ Change | % Change | |||||||||||
| (in thousands) | | |||||||||||||
Total segment revenue | $ | 292,370 | $ | 207,933 | $ | 84,437 | 41 | % | |||||||
Derivative (loss) gain not allocated to segments | (36,959 | ) | 9,758 | (46,717 | ) | (479 | )% | ||||||||
Total revenue | $ | 255,411 | $ | 217,691 | $ | 37,720 | 17 | % | |||||||
Operating income before items not allocated to segments | $ | 106,612 | $ | 83,368 | $ | 23,244 | 28 | % | |||||||
Portion of operating income attributable to non-controlling interests | 8,678 | 3,450 | 5,228 | 152 | % | ||||||||||
Derivative (loss) gain not allocated to segments | (56,391 | ) | 595 | (56,986 | ) | (9,577 | )% | ||||||||
Compensation expense included in facility expenses not allocated to segments | (404 | ) | (243 | ) | (161 | ) | 66 | % | |||||||
Facility expenses adjustments | 2,850 | 107 | 2,743 | 2,564 | % | ||||||||||
Selling, general and administrative expenses | (17,137 | ) | (15,477 | ) | (1,660 | ) | 11 | % | |||||||
Depreciation | (31,362 | ) | (25,264 | ) | (6,098 | ) | 24 | % | |||||||
Amortization of intangible assets | (10,193 | ) | (10,193 | ) | — | 0 | % | ||||||||
Loss on disposal of property, plant and equipment | (1,937 | ) | (633 | ) | (1,304 | ) | 206 | % | |||||||
Accretion of asset retirement obligations | (70 | ) | (56 | ) | (14 | ) | 25 | % | |||||||
Income from operations | 646 | 35,654 | (35,008 | ) | (98 | )% | |||||||||
Earnings from unconsolidated affiliates | — | 169 | (169 | ) | (100 | )% | |||||||||
Interest income | 422 | 100 | 322 | 322 | % | ||||||||||
Interest expense | (26,433 | ) | (23,440 | ) | (2,993 | ) | 13 | % | |||||||
Amortization of deferred financing costs and discount (a component of interest expense) | (3,625 | ) | (3,091 | ) | (534 | ) | 17 | % | |||||||
Derivative gain related to interest expense | — | 2,265 | (2,265 | ) | (100 | )% | |||||||||
Miscellaneous income, net | 76 | 825 | (749 | ) | (91 | )% | |||||||||
(Loss) income before provision for income tax | $ | (28,914 | ) | $ | 12,482 | $ | (41,396 | ) | (332 | )% | |||||
Derivative (Loss) Gain Not Allocated to Segments. Unrealized loss from the mark-to-market of our derivative instruments was $50.7 million for the three months ended September 30, 2010 compared to unrealized gain of $6.6 million for the same period in 2009. Realized loss from the settlement of our derivative instruments was $5.7 million for the three months ended September 30, 2010 compared to realized loss of $6.0 million for the same period in 2009. The total change of $57.0 million is primarily due to volatility in commodity prices.
Facility Expenses Adjustments. Facility expenses adjustments consist of the reallocation of the MarkWest Pioneer field services fee and the reallocation of the interest expense related to the SMR which is included in 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 increases in headcount and share-based compensation expenses. These increases were partially offset by a decrease in office-related expenses and professional services.
Depreciation. Depreciation increased due to depreciation on additional projects completed at the end of 2009 through the third quarter of 2010.
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Interest Expense. Interest expense increased primarily due to interest expense related to the SMR.
Amortization of deferred financing costs and discount. Amortization of deferred financing costs and discount increased primarily due to the amortization of the financing costs incurred in July 2010 associated with the Credit Facility.
Provision for Income Tax. The total provision for income tax benefit was $10.2 million, which includes a deferred benefit of $13.8 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 $3.5 million. Approximately $3.2 million is attributable to MarkWest Hydrocarbon and the remaining $0.3 million is related to taxes payable by the Partnership associated with the Texas Margin Tax and Michigan Business Taxes.
Nine months ended September 30, 2010 compared to nine months ended September 30, 2009
Items belowIncome (loss) from operations in our Condensed Consolidated Statements of Operations, certain compensation expense, certain other non-cash items and any 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 nine months ended September 30, 2010 and 2009.
| Nine months ended September 30, | | | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | $ Change | % Change | ||||||||||
| (in thousands) | | ||||||||||||
Revenue | $ | 479,051 | $ | 339,967 | $ | 139,084 | 41 | % | ||||||
Operating expenses: | ||||||||||||||
Purchased product costs | 220,849 | 150,456 | 70,393 | 47 | % | |||||||||
Facility expenses | 60,543 | 55,703 | 4,840 | 9 | % | |||||||||
Total operating expenses before items not allocated to segments | 281,392 | 206,159 | 75,233 | 36 | % | |||||||||
Portion of operating income attributable to non-controlling interests | 4,962 | 1,007 | 3,955 | 393 | % | |||||||||
Operating income before items not allocated to segments | $ | 192,697 | $ | 132,801 | $ | 59,896 | 45 | % | ||||||
Revenue. Revenue increased primarily due to higher NGL prices. Revenue from NGL and condensate sales increased approximately $121.4 million across the segment, partially offset by a $2.7 million decrease in revenue from natural gas sales. 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 $17.6 million due to the growth in the Arkoma Connector Pipeline operations which began in mid-July 2009 and higher volumes in the Woodford Shale and Stiles Ranch. The increase in revenue was partially offset by a decrease in gathered volumes in the Foss Lake, East Texas and 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. The decline in gathered volumes in these conventional natural gas formations is expected to continue until natural gas prices improve.
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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 decrease in gathered volumes in East Texas and 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.
Facility Expenses. Facility expenses increased primarily due to higher operating expenses in Southeast Oklahoma resulting from the start of the Arkoma Connector Pipeline in mid-July 2009 and the increased volumes.The increase was partially offset by a reduction in repairs and maintenance expense related to environmental costs in 2009 in East Texas that did not recur in 2010.
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 mid-July 2009.
| Nine months ended September 30, | | | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | $ Change | % Change | ||||||||||
| (in thousands) | | ||||||||||||
Revenue | $ | 276,570 | $ | 165,765 | $ | 110,805 | 67 | % | ||||||
Operating expenses: | ||||||||||||||
Purchased product costs | 179,700 | 117,540 | 62,160 | 53 | % | |||||||||
Facility expenses | 14,555 | 14,796 | (241 | ) | (2 | )% | ||||||||
Total operating expenses before items not allocated to segments | 194,255 | 132,336 | 61,919 | 47 | % | |||||||||
Operating income before items not allocated to segments | $ | 82,315 | $ | 33,429 | $ | 48,886 | 146 | % | ||||||
Revenue. Revenue increased primarily due to higher commodity prices realized on NGL sales, as well as an increase in volumes from a significant customer under a percent-of-proceeds arrangement.
Purchased Product Costs. Purchased product costs increased due to higher prices for the natural gas that is purchased to satisfy the keep-whole arrangements, as well as the increase in volumes.
| Nine months ended September 30, | | | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | $ Change | % Change | ||||||||||
| (in thousands) | | ||||||||||||
Revenue | $ | 66,354 | $ | 29,510 | $ | 36,844 | 125 | % | ||||||
Operating expenses: | ||||||||||||||
Purchased product costs | 8,570 | 6,056 | 2,514 | 42 | % | |||||||||
Facility expenses | 19,121 | 10,557 | 8,564 | 81 | % | |||||||||
Total operating expenses before items not allocated to segments | 27,691 | 16,613 | 11,078 | 67 | % | |||||||||
Portion of operating income attributable to non-controlling interests | 15,617 | 4,113 | 11,504 | 280 | % | |||||||||
Operating income before items not allocated to segments | $ | 23,046 | $ | 8,784 | $ | 14,262 | 162 | % | ||||||
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Revenue. Revenue increased due to ongoing expansion of the Liberty operations and higher NGL prices. Revenue increased approximately $23.9 million related to gathering fees and approximately $15.6 million related to NGL product sales.
Purchased Product Costs. Purchased product costs increased primarily due to the purchase of product from certain producers. On June 30 and during the third quarter of 2010, the Liberty segment agreed to purchase certain NGLs from the producers' inventory at the end of each month, whereas prior to this agreement the Liberty segment did not purchase any NGLs and acted solely as the producers' agent providing processing, storage and marketing services. In 2009, purchased product costs related to an interim plant that ceased operations in January 2010.
Facility Expenses. Facility expenses increased primarily due to the ongoing expansion of the Liberty operations. The increase in facility expenses was partially offset by a decrease in compressor rental expense as we have purchased certain compressors that had been leased.
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 and the ongoing expansion of the Liberty operations.
| Nine months ended September 30, | | | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | $ Change | % Change | ||||||||||
| (in thousands) | | ||||||||||||
Revenue | $ | 62,958 | $ | 41,058 | $ | 21,900 | 53 | % | ||||||
Operating expenses: | ||||||||||||||
Facility expenses | 23,875 | 12,303 | 11,572 | 94 | % | |||||||||
Total operating expenses before items not allocated to segments | 23,875 | 12,303 | 11,572 | 94 | % | |||||||||
Operating income before items not allocated to segments | $ | 39,083 | $ | 28,755 | $ | 10,328 | 36 | % | ||||||
Revenue. Revenue increased primarily due to $10.8 million related to the SMR and higher commodity prices.
Facility Expenses. Facility expenses increased primarily due to $10.2 million of SMR operating expenses and increased utilities and chemicals 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 nine months ended September 30, 2010 and 2009. The ensuing items listed below
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theTotal segment revenue andOperating income lines are not allocated to business segments as management does not consider these items allocable to any individual segment.
| Nine months ended September 30, | | | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | $ Change | % Change | |||||||||||
| (in thousands) | | |||||||||||||
Total segment revenue | $ | 884,933 | $ | 576,300 | $ | 308,633 | 54 | % | |||||||
Derivative gain (loss) not allocated to segments | 2,707 | (65,173 | ) | 67,880 | (104 | )% | |||||||||
Total revenue | $ | 887,640 | $ | 511,127 | $ | 376,513 | 74 | % | |||||||
Operating income before items not allocated to segments | $ | 337,141 | $ | 203,769 | $ | 133,372 | 65 | % | |||||||
Portion of operating income attributable to non-controlling interests | 20,579 | 5,120 | 15,459 | 302 | % | ||||||||||
Derivative loss not allocated to segments | (21,850 | ) | (105,249 | ) | 83,399 | (79 | )% | ||||||||
Compensation expense included in facility expenses not allocated to segments | (1,412 | ) | (801 | ) | (611 | ) | 76 | % | |||||||
Facility expenses adjustments | 6,240 | 215 | 6,025 | 2,802 | % | ||||||||||
Selling, general and administrative expenses | (55,064 | ) | (46,265 | ) | (8,799 | ) | 19 | % | |||||||
Depreciation | (89,367 | ) | (69,621 | ) | (19,746 | ) | 28 | % | |||||||
Amortization of intangible assets | (30,579 | ) | (30,638 | ) | 59 | (0 | )% | ||||||||
Loss on disposal of property, plant and equipment | (2,116 | ) | (1,432 | ) | (684 | ) | 48 | % | |||||||
Accretion of asset retirement obligations | (282 | ) | (147 | ) | (135 | ) | 92 | % | |||||||
Impairment of long-lived assets | — | (5,855 | ) | 5,855 | (100 | )% | |||||||||
Income (loss) from operations | 163,290 | (50,904 | ) | 214,194 | (421 | )% | |||||||||
Earnings from unconsolidated affiliates | 1,517 | 1,260 | 257 | 20 | % | ||||||||||
Interest income | 1,185 | 201 | 984 | 490 | % | ||||||||||
Interest expense | (75,970 | ) | (63,964 | ) | (12,006 | ) | 19 | % | |||||||
Amortization of deferred financing costs and discount (a component of interest expense) | (8,517 | ) | (6,528 | ) | (1,989 | ) | 30 | % | |||||||
Derivative gain related to interest expense | 1,871 | 2,265 | (394 | ) | (17 | )% | |||||||||
Miscellaneous income, net | 1,129 | 2,546 | (1,417 | ) | (56 | )% | |||||||||
Income (loss) before provision for income tax | $ | 84,505 | $ | (115,124 | ) | $ | 199,629 | (173 | )% | ||||||
Derivative Loss Not Allocated to Segments. Unrealized gain from the mark-to-market of our derivative instruments was $13.8 million for the nine months ended September 30, 2010 compared to unrealized loss of $148.4 million for the same period in 2009. Realized loss from the settlement of our derivative instruments was $35.7 million for the nine months ended September 30, 2010 compared to realized gain of $43.1 million for the same period in 2009. The total change of $83.4 million is primarily due to volatility in commodity prices.
Facility Expenses Adjustments. Facility expenses adjustments consist of the reallocation of the MarkWest Pioneer field services fee and the reallocation of the interest expense related to the SMR which is included in 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, as well as increases in headcount, short-term incentive compensation, insurance and corporate office rent. These increases were partially offset by a decrease in professional services expense.
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Depreciation. Depreciation increased due to depreciation on additional projects completed during the end of 2009 through the third quarter of 2010.
Impairment of Long-Lived Assets. During the nine months ended September 30, 2009, we recognized an impairment of $5.9 million related to certain gas-gathering and intangible assets in the Southwest segment.
Interest Expense. Interest expense increased primarily due to additional borrowings in May 2009 to fund our capital plan and interest expense related to the SMR.
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 and the amortization of the financing costs associated with the Credit Facility.
Derivative Gain Related to Interest Expense. Derivative gain related to interest expense in 2010 relates 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 $10.2 million, which includes a deferred benefit of less than $0.1 million. The current provision for income tax expense was $10.3 million. Approximately $9.0 million is attributable to MarkWest Hydrocarbon and the remaining $1.3 million is related to taxes payable by the Partnership associated with the Texas Margin Tax and Michigan Business Taxes.
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Operating Data
| Three months ended September 30, | | Nine months ended September 30, | | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | % Change | 2010 | 2009 | % Change | |||||||||||||||
Southwest | |||||||||||||||||||||
East Texas | |||||||||||||||||||||
Gathering systems throughput (Mcf/d) | 433,000 | 455,100 | (4.9 | )% | 433,600 | 456,700 | (5.1 | )% | |||||||||||||
NGL product sales (gallons) | 60,204,100 | 66,996,400 | (10.1 | )% | 186,287,500 | 180,059,000 | 3.5 | % | |||||||||||||
Oklahoma | |||||||||||||||||||||
Foss Lake gathering system throughput (Mcf/d) | 70,200 | 82,200 | (14.6 | )% | 71,700 | 89,300 | (19.7 | )% | |||||||||||||
Stiles Ranch gathering system throughput (Mcf/d) | 105,900 | 87,800 | 20.6 | % | 109,800 | 90,700 | 21.1 | % | |||||||||||||
Grimes gathering system throughput (Mcf/d) | 7,500 | 9,400 | (20.2 | )% | 7,800 | 10,100 | (22.8 | )% | |||||||||||||
Arapaho NGL product sales (gallons) | 33,822,300 | 33,723,900 | 0.3 | % | 93,359,400 | 92,854,000 | 0.5 | % | |||||||||||||
Southeast Oklahoma gathering system throughput (Mcf/d) | 535,800 | 389,100 | 37.7 | % | 524,100 | 403,700 | 29.8 | % | |||||||||||||
Arkoma Connector Pipeline throughput (Mcf/d)(1) | 396,800 | 229,000 | 73.3 | % | 378,900 | 229,000 | 65.5 | % | |||||||||||||
Other Southwest | |||||||||||||||||||||
Appleby gathering system throughput (Mcf/d) | 29,700 | 44,200 | (32.8 | )% | 31,900 | 50,200 | (36.5 | )% | |||||||||||||
Other gathering systems throughput (Mcf/d)(2) | 7,300 | 10,500 | (30.5 | )% | 8,300 | 10,700 | (22.4 | )% | |||||||||||||
Northeast | |||||||||||||||||||||
Appalachia(3) | |||||||||||||||||||||
Natural gas processed (Mcf/d) | 190,300 | 197,200 | (3.5 | )% | 194,400 | 197,700 | (1.7 | )% | |||||||||||||
Keep-whole sales (gallons) | 28,741,100 | 26,668,300 | 7.8 | % | 105,328,500 | 104,381,200 | 0.9 | % | |||||||||||||
Percent-of-proceeds sales (gallons) | 30,763,000 | 23,858,400 | 28.9 | % | 87,886,700 | 69,922,200 | 25.7 | % | |||||||||||||
Total NGL product sales (gallons)(4) | 59,504,100 | 50,526,700 | 17.8 | % | 193,215,200 | 174,303,400 | 10.8 | % | |||||||||||||
Michigan | |||||||||||||||||||||
Crude oil transported for a fee (Bbl/d) | 12,100 | 12,100 | 0.0 | % | 12,400 | 12,400 | 0.0 | % | |||||||||||||
Liberty | |||||||||||||||||||||
Gathering system throughput (Mcf/d) | 153,300 | 56,100 | 173.3 | % | 127,700 | 44,500 | 187.0 | % | |||||||||||||
NGL product sales (gallons) | 32,379,600 | 10,558,900 | 206.7 | % | 77,372,300 | 18,995,200 | 307.3 | % | |||||||||||||
Gulf Coast | |||||||||||||||||||||
Refinery off-gas processed (Mcf/d) | 123,000 | 127,800 | (3.8 | )% | 118,400 | 119,000 | (0.5 | )% | |||||||||||||
Liquids fractionated (Bbl/d) | 23,100 | 24,500 | (5.7 | )% | 22,800 | 23,200 | (1.7 | )% |
- (1)
- We began commercial operation of the Arkoma Connector Pipeline in mid-July 2009. The volume reported for 2009 is the average daily rate for the days of operation.
- (2)
- Excludes lateral pipelines where revenue is not based on throughput.
- (3)
- Includes throughput from the Kenova, Cobb, and Boldman processing plants.
- (4)
- Represents sales at the Siloam NGL fractionation plant. The total sales exclude 16,651,700 gallons and 6,602,400 gallons sold by the Northeast on behalf of Liberty for the three months ended September 30, 2010 and 2009, respectively, and 39,957,600 gallons and 13,122,500 gallons sold for the nine months ended September 30, 2010 and 2009, respectively.
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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 $500 million of capital expenditures for growth projects and approximately $10 million for maintenance capital. Our share of growth capital expenditures is expected to be approximately $300 million and the remainder will be funded through contributions from our MarkWest Liberty Midstream joint venture partner and existing cash balances in the joint venture. As of September 30, 2010 we have spent approximately $374.2 million, including the amounts funded by M&R. During the nine months ended September 30, 2010, we received approximately $148.1 million from M&R to fund capital expenditures and working capital needs 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 partner for capital projects encompassed by the joint venture, and our current borrowing capacity under the 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 November 2, 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. Fitch Ratings initiated coverage in June 2010 and assigned us a current credit rating of BB with a Stable outlook. 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.
Debt Financing Activities
On July 1, 2010, we entered into the Credit Facility (see Note 7 of the accompanying Notes to the Condensed Consolidated Financial Statements). The Credit Facility replaced our prior credit agreement in its entirety and initially provided for committed borrowing capacity of up to $700 million, with an uncommitted accordion feature of up to $200 million. On July 29, 2010, we exercised a portion of the accordion feature and increased our borrowing capacity under the Credit Facility to $705 million. The Credit Facility matures on July 1, 2015; however, if we do not refinance or repay all the 2014 Senior Notes by May 1, 2014, the Credit Facility will mature on May 1, 2014. We expect that all of the 2014 Senior Notes will be repurchased in the fourth quarter 2010.
Under the provisions of the Credit Facility, we are subject to a number of restrictions and covenants, which are substantially the same as the restrictions and covenants under the prior credit agreement. As of September 30, 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
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November 2, 2010, we had $12.3 million of borrowings outstanding and $27.4 million of letters of credit outstanding under the Credit Facility, leaving approximately $665.3 million available for borrowing.
On November 2, 2010, we completed a public offering of $500.0 million in aggregate principal amount of 6.75% senior unsecured notes due 2020. We used approximately $360 million of the proceeds from the 2020 Senior Notes offering to repurchase 94% of the outstanding 2014 Senior Notes and pay the related premiums, fees and accrued interest. The remaining proceeds will be used to repurchase the remaining outstanding 2014 Senior Notes, to repay all borrowings outstanding under the Credit Facility and to provide working capital for general partnership purposes.
As of November 2, 2010, we had three series of Senior Notes outstanding: $275.0 million aggregate principal issued in July 2006 and due July 2016; $500.0 million aggregate principal issued in April and May 2008 and due April 2018; and $500.0 million aggregate principal issued in November 2010 and due November 2020. In addition, approximately $24.1 million of the 2014 Senior Notes were outstanding as of November 2, 2010, but are expected to be repurchased during the fourth quarter 2010. 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 Credit Facility limits our ability to enter into transactions with parties that require margin calls under certain derivative instruments. The Credit Facility prevents members of the participating bank group from requiring margin calls. As of November 2, 2010, all of our derivative positions 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.
Equity Offerings
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 $142.3 million were used to repay borrowings under our revolving credit facility and to partially fund our ongoing capital expenditure program.
Liquidity Risks and Uncertainties
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 prices have increased in 2010 compared to 2009, our operating performance could be negatively impacted if the increases in NGL prices are not sustained. Natural gas prices have remained at relatively low levels throughout 2009 and 2010. Although low natural gas prices increase our earnings under keep-whole contracts in the short term, our earnings
56
could be adversely impacted if the low natural gas prices do not increase and result in reduced volumes from our producers over the long term. Additionally, new legislation recently enacted 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 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 counterparties to all 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.
Cash Flow
The following table summarizes cash inflows (outflows) (in thousands):
| Nine months ended September 30, | | ||||||||
---|---|---|---|---|---|---|---|---|---|---|
| 2010 | 2009 | $ Change | |||||||
Net cash provided by operating activities | $ | 197,238 | $ | 147,865 | $ | 49,373 | ||||
Net cash flows used in investing activities | (373,649 | ) | (404,687 | ) | 31,038 | |||||
Net cash flows provided by financing activities | 177,154 | 318,807 | (141,653 | ) |
Net cash provided by operating activities increased primarily due to a $133.4 million increase in operating income, excluding derivative gains and losses, in our operating segments, which was partially offset by a $76.4 million decrease in net cash received from the settlement of derivative positions and a decrease in operating cash flows resulting from changes in working capital.
Net cash used in investing activities decreased primarily due to a $14.3 million decrease in capital expenditures and a $6.4 million decrease in contributions to equity investments, and $10.0 million related to the removal of restrictions on certain cash balances.
Net cash provided by financing activities decreased primarily due to a $36.4 million decrease in proceeds from public offerings and a $22.4 million increase in distributions to common unitholders, offset by a $58.4 million increase in net borrowings. Cash provided by financing activities for the nine months ended September 30, 2009 also included $73.1 million in proceeds from the SMR transaction and $60.7 million in net proceeds from the sale of an equity interest in the Arkoma Connector Pipeline.
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 September 30, 2010, our purchase obligations for the remainder of 2010 were $63.4 million compared to our 2010 obligations of
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$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 primarily represent purchase orders and contracts related to property, plant and equipment.
Matters Impacting Future Results
In the fourth quarter 2010, we will redeem the entire $375 million aggregate principal amount of 2014 Senior Notes for a redemption price of approximately $398 million, including related fees and expenses as well as accrued and unpaid interest through the date of redemption. We will record a pre-tax loss on redemption of debt of approximately $46 million in the fourth quarter of 2010, which consists of approximately $37 million for the non-cash write-off of the unamortized discount and deferred finance costs associated with the 2014 Senior Notes and approximately $9 million for payment of the related call and tender premiums.
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 nine months ended September 30, 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 Operations—Critical 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 VIE's 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 holder's 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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Description | Judgments and Uncertainties | Effect if Actual Results Differ from Estimates and Assumptions | ||
---|---|---|---|---|
Accounting for Share-Based Compensation | ||||
Our long-term incentive plans permit the grant of restricted units, phantom units, unit options and substitute awards. In April 2010, the Board granted 282,000 phantom units to our senior executives and other key employees that will vest in equal installments on January 31, 2011 and January 31, 2012, subject to Market Criteria and Performance Criteria to be determined at the Board's discretion. The Market Criteria, which must be considered in determining the grant-date fair value of the award, is based on the Partnership's total unitholder return over a three-year calendar period relative to the total unitholder return of a defined group of peer companies over the same period. The Performance Criteria do not affect the fair value of the awards but do impact the recognition of expense as compensation expense is only recognized for those awards that are expected to vest. | We must exercise significant judgment and make several assumptions to estimate the fair value of the awards based on the Market Criteria. This includes determining the appropriate valuation methodology and the related inputs such as the expected volatility of the market price of our common units, the expected volatility of the market price of the common units or common stock of the peer companies, and the correlation between changes in the market price of our common units and those of the peer companies. We utilize a Monte Carlo simulation model which is a commonly accepted methodology for valuing this type of award. We utilized historical volatilities and correlation factors as the key inputs to this model. We have also exercised judgment in assuming that the Board will not increase or decrease the number of units that vest based on the Performance Criteria as there is no basis to conclude that it is probable that any adjustment to the vesting will be made. | If we had used a different valuation methodology or different assumptions regarding expected volatilities and correlations, the estimated fair value and related compensation expense of the phantom units may have been significantly different. Compensation expense could also increase or decrease significantly in future periods if the Board adjusts the number of units that vest based on the Performance Criteria. |
Recent Accounting Pronouncements
Refer to Note 2 of the accompanying Notes to the Condensed Consolidated Financial Statements for information regarding recent accounting pronouncements.
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Item 3. Quantitative and Qualitative Disclosures about Market Risk
Commodity Price Risk
NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty, availability of NGL transportation and fractionation capacity and a variety of additional factors that are beyond our control. Our profitability is directly affected by prevailing commodity prices primarily as a result of processing or conditioning at our processing plants or third-party processing plants, purchasing and selling or gathering and transporting volumes of natural gas at index-related prices and the cost of third-party transportation and fractionation services. To the extent that commodity prices influence the level of drilling activity, such prices also affect profitability. To protect ourselves financially against adverse price movements and to maintain more stable and predictable earnings so that we can meet our cash distribution objectives, debt service and capital expenditures, we execute a hedging strategy governed by the risk management policy approved by the Board. We have a committee comprised of senior management that oversees risk management activities, continually monitors the risk management program and adjusts our strategy as conditions warrant. We enter into certain derivative contracts to reduce the risks associated with unfavorable changes in the prices of natural gas, NGLs and crude oil. Derivative contracts utilized are swaps, options and fixed price forward contracts traded on the OTC market. The risk management policy does not allow speculative derivative contracts.
To mitigate our cash flow exposure to fluctuations in the price of NGLs, we have entered into derivative financial instruments relating to the future price of NGLs and crude oil. Generally we hedge our NGL price risk using crude oil as NGL financial markets lack adequate liquidity and historically there has been a strong relationship between changes in NGL and crude oil prices. The pricing relationship between NGLs and crude oil may vary in certain periods because crude oil pricing is generally based on worldwide demand and the level of production of major crude oil exporting countries while NGL prices are correlated to North America supply and petrochemical demand. In periods where NGL prices and crude oil prices are not consistent with the historical relationship, we incur increased risk and additional gains or losses. We enter into NGL derivative contracts when adequate market liquidity exists.
To mitigate our cash flow exposure to fluctuations in the price of natural gas, we primarily utilize derivative financial instruments relating to the future price of natural gas and take into account the partial offset of our long and short gas positions resulting from normal operating activities.
As a result of our current derivative positions, we have mitigated a significant portion of our expected commodity price risk through the fourth quarter of 2013. For entities that are not wholly owned by us, commodity risk is mitigated only for our ownership interest. We would be exposed to additional commodity risk in certain situations such as if producers under deliver or over deliver product or when processing facilities are operated in different recovery modes. In the event we have derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions may be terminated.
We enter into derivative contracts primarily with financial institutions that are participating members of the Credit Facility as collateral is not posted by us as the participating members have a collateral position in substantially all of our wholly-owned assets. All of our financial derivative positions are currently with participating bank group members. Management conducts a standard credit review on counterparties and we have agreements containing collateral requirements. For all participating bank group members, collateral requirements do not exist when a derivative contract favors us. We use standardized agreements that allow for offset of positive and negative exposures (master netting arrangements).
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Outstanding Derivative Contracts
The following tables provide information on the volume of our derivative activity for positions related to long liquids and keep-whole price risk at September 30, 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 | 750 | $ | 68.08 | $ | 80.11 | $ | (295 | ) | |||||
2011 | 1,659 | 67.57 | 85.05 | (3,382 | ) | ||||||||
2012 | 820 | 60.00 | 85.87 | (3,026 | ) |
WTI Crude Puts | Volumes (Bbl/d) | WAVG Floor (Per Bbl) | Fair Value (in thousands) | |||||||
---|---|---|---|---|---|---|---|---|---|---|
2010 | 2,366 | $ | 80.00 | $ | 538 | |||||
2011 | 1,818 | 80.00 | 4,527 |
WTI Crude Swaps | Volumes (Bbl/d) | WAVG Price (Per Bbl) | Fair Value (in thousands) | |||||||
---|---|---|---|---|---|---|---|---|---|---|
2010 | 2,801 | $ | 74.40 | $ | (1,707 | ) | ||||
2011 | 3,753 | 81.30 | (4,708 | ) | ||||||
2012 | 4,813 | 84.54 | (4,625 | ) | ||||||
2013 | 1,510 | 83.86 | (2,336 | ) |
Natural Gas Swaps | Volumes (MMBtu/d) | WAVG Price (Per MMBtu) | Fair Value (in thousands) | |||||||
---|---|---|---|---|---|---|---|---|---|---|
2010 | 5,780 | $ | 6.08 | $ | (1,241 | ) | ||||
2011 | 1,210 | 5.38 | (544 | ) | ||||||
2012 | 4,650 | 5.62 | (1,460 | ) | ||||||
2013 | 980 | 5.13 | (65 | ) |
IsoButane Swaps | Volumes (Gal/d) | WAVG Price (Per Gal) | Fair Value (in thousands) | |||||||
---|---|---|---|---|---|---|---|---|---|---|
2010 | 6,170 | $ | 1.36 | $ | (121 | ) |
Natural Gasoline Swaps | Volumes (Gal/d) | WAVG Price (Per Gal) | Fair Value (in thousands) | |||||||
---|---|---|---|---|---|---|---|---|---|---|
2010 | 12,137 | $ | 1.67 | $ | (107 | ) |
Normal Butane Swaps | Volumes (Gal/d) | WAVG Price (Per Gal) | Fair Value (in thousands) | |||||||
---|---|---|---|---|---|---|---|---|---|---|
2010 | 10,050 | $ | 1.30 | $ | (184 | ) |
Propane Swaps | Volumes (Gal/d) | WAVG Price (Per Gal) | Fair Value (in thousands) | |||||||
---|---|---|---|---|---|---|---|---|---|---|
2010 | 30,577 | $ | 1.05 | $ | (343 | ) |
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The following tables provide information on the volume of our taxable subsidiary's commodity derivative activity for positions related to keep-whole price risk at September 30, 2010, including the WAVG:
WTI Crude Collars | Volumes (Bbl/d) | WAVG Floor (Per Bbl) | WAVG Cap (Per Bbl) | Fair Value (in thousands) | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
2012 | 646 | $ | 70.00 | $ | 91.85 | $ | (1,147 | ) |
WTI Crude Swaps | Volumes (Bbl/d) | WAVG Price (Per Bbl) | Fair Value (in thousands) | |||||||
---|---|---|---|---|---|---|---|---|---|---|
2010 | 4,120 | $ | 73.66 | $ | (2,847 | ) | ||||
2011 | 3,398 | 86.90 | 2,664 | |||||||
2012 | 1,840 | 86.93 | (165 | ) | ||||||
2013 | 442 | 85.20 | (463 | ) |
Natural Gas Swaps | Volumes (MMBtu/d) | WAVG Price (Per MMBtu) | Fair Value (in thousands) | |||||||
---|---|---|---|---|---|---|---|---|---|---|
2010 | 1,215 | $ | 6.79 | $ | (4,482 | ) | ||||
2011 | 17,941 | 8.23 | (23,302 | ) | ||||||
2012 | 13,801 | 6.07 | (4,364 | ) | ||||||
2013 | 1,801 | 5.57 | (128 | ) |
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 September 30, 2010.
WTI Crude Collars | Volumes (Bbl/d) | WAVG Floor (Per Bbl) | WAVG Cap (Per Bbl) | |||||||
---|---|---|---|---|---|---|---|---|---|---|
2012 | 840 | $ | 80.00 | $ | 96.25 | |||||
2013 | 836 | 80.00 | 98.25 |
Embedded Derivatives in Commodity Contracts
We have 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 throughDerivative loss related to purchased product costs. As of September 30, 2010, the estimated fair value of this contract was a liability of $33.5 million.
We have a commodity contract that gives us an option to fix a component of the utilities cost to an index price on electricity at one of our plant locations. The value of the derivative component of this contract is marked to market throughDerivative (gain) loss related to facility expenses. As of September 30, 2010, the estimated fair value of this contract was an asset of $0.2 million.
Interest Rate Risk
The information about interest rate risk for the nine months ended September 30, 2010 does not differ materially from that discussed in Item 7A.Quantitative and Qualitative Disclosures about Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2009.
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Item 4. Controls and Procedures
Evaluation of Disclosure 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 September 30, 2010. Based on this evaluation, the Partnership's management, including our Chief Executive Officer and Chief Financial Officer, concluded that as of September 30, 2010, our disclosure controls and procedures were effective to provide reasonable assurance that information 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.
Limitations on Controls
Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives as specified above. Management does not expect, however, that our disclosure controls and procedures will prevent or detect all error and fraud. Any control system, no matter how well designed and operated, is based upon certain assumptions and can provide only reasonable, not absolute, assurance that its objectives will be met. Further, no evaluation of controls can provide absolute assurance that misstatements due to error or fraud will not occur or that all control issues and instances of fraud, if any, within the Partnership have been detected.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting during the quarter ended September 30, 2010 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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Refer to Note 9 of the accompanying Notes to the Condensed Consolidated Financial Statements for information regarding legal proceedings.
There were no material changes in our risk factors as disclosed in Item 1A.Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2009, except as set forth below.
The enactment of the Dodd-Frank Act could have an adverse impact on our ability to hedge risks associated with our business.
In July 2010, Congress enacted and the President signed broad financial regulatory reform legislation that, among other things, will impose comprehensive regulation on the OTC derivatives marketplace and will affect the use of derivatives in hedging transactions. The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") will subject "swap dealers" and "major swap participants" to substantial supervision and regulation, including capital standards, margin requirements, business conduct standards, and recordkeeping and reporting requirements. It also will require central clearing for transactions unless one of the parties is not a swap dealer or major swap participant, is using the transaction to hedge commercial risk and elects not to clear the transaction under the so-called "end-user" exemption. However, the "end-user" exemption does not expressly extend to margin requirements, and uncleared transactions may still be subject to regulated margin requirements. The Dodd-Frank Act delegates significant authority to generally regulate and develop implementing regulations for OTC commodity derivatives to the Commodity Futures Trading Commission ("CFTC") and the SEC, including express authority to impose position limits for derivatives related to energy commodities. Separately, in late January 2010, the CFTC proposed regulations that would impose speculative position limits for certain futures and option contracts in natural gas, crude oil, heating oil, and gasoline. These proposed regulations would make an exemption available for certainbona fide hedging of commercial risks. The Dodd-Frank Act and regulations promulgated thereunder will generally become effective one year after the date of enactment of the Act. While we know the substance of the Dodd-Frank Act, it is not possible at this time to predict the final form and substance of the CFTC or the SEC regulations that must be adopted to carry out the Act. The CFTC and the SEC must adopt regulations within one year from the date of enactment of the Dodd-Frank Act. Any such regulations that subject us or our counterparties to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity. We may be unable to hedge a significant portion of our exposure to commodity price risk which could have a material adverse impact on our income from operations, cash flows and quarterly distribution to common unitholders.
10.1 | (1) | Amended and Restated Revolving Credit Agreement dated as of July 1, 2010 among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, as successor Administrative Agent, Issuing Bank and Swingline Linder, Royal Bank of Canada, as prior administrative agent, RBC Capital Markets, as Syndication Agent, BNP Paribas, Morgan Stanley Bank and U.S. Bank National Association, as Documentation Agents, and the lenders party thereto. | |
10.2 | (2) | Joinder Agreement dated as of July 29, 2010 among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, individually and as Administrative Agent, Issuing Bank and Swingline Lender and Goldman Sachs Bank USA. |
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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. | |
101 | * | The following financial information from the quarterly report on Form 10-Q of MarkWest Energy Partners, L.P. for the quarter ended September 30, 2010, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statements of Changes in Equity, (iv) Condensed Consolidated Statements of Cash Flows, and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text. |
- (1)
- Incorporated by reference to the Current Report on Form 8-K filed July 7, 2010.
- (2)
- Incorporated by reference to the Current Report on Form 8-K filed August 4, 2010.
- *
- Filed herewith
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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: November 8, 2010 | /s/ FRANK M. SEMPLE Frank M. Semple Chairman, President and Chief Executive Officer (Principal Executive Officer) | |||
Date: November 8, 2010 | /s/ NANCY K. BUESE Nancy K. Buese Senior Vice President & Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) |
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