UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
x QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2012
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 |
|
27-0005456 |
(State or other jurisdiction of |
|
(IRS Employer |
1515 Arapahoe Street, Tower 1, Suite 1600, Denver, Colorado 80202-2137
(Address of principal executive offices)
Registrants 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 x 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 x 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 x |
|
Accelerated filer o |
|
|
|
Non-accelerated filer o |
|
Smaller reporting company o |
(Do not check if a smaller reporting company) |
|
|
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 x
As of October 31, 2012, the number of the registrants common units and Class B units outstanding were 117,594,365 and 19,954,389, respectively.
Throughout this document we make statements that are classified as forward-looking. Please refer to 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. References to the General Partner are intended to mean MarkWest Energy GP, L.L.C., the general partner of the Partnership.
Glossary of Terms
Bbl |
|
Barrel |
Bbl/d |
|
Barrels per day |
Bcf/d |
|
Billion cubic feet per day |
Btu |
|
One British thermal unit, an energy measurement |
Credit Facility |
|
Amended and restated revolving credit agreement |
DER |
|
Distribution equivalent right |
Dth/d |
|
Dekatherms per day |
EPA |
|
Environmental Protection Agency |
ERCOT |
|
Electric Reliability Council of Texas south zone (around the clock) |
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 |
Mcf |
|
One thousand cubic feet of natural gas |
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) |
|
Segment revenue less purchased product costs, excluding any derivative gain (loss) |
NGL |
|
Natural gas liquids, such as ethane, propane, butanes and natural gasoline |
N/A |
|
Not applicable |
OTC |
|
Over-the-Counter |
SEC |
|
Securities and Exchange Commission |
SMR |
|
Steam methane reformer, operated by a third party and located at the Javelina gas processing and fractionation facility in Corpus Christi, Texas |
VIE |
|
Variable interest entity |
WTI |
|
West Texas Intermediate |
MARKWEST ENERGY PARTNERS, L.P.
Condensed Consolidated Balance Sheets
(unaudited, in thousands)
|
|
September 30, 2012 |
|
December 31, 2011 |
| ||
ASSETS |
|
|
|
|
| ||
Current assets: |
|
|
|
|
| ||
Cash and cash equivalents ($2,710 and $2,684, respectively) |
|
$ |
415,064 |
|
$ |
117,016 |
|
Restricted cash |
|
25,000 |
|
26,193 |
| ||
Receivables, net ($1,448 and $1,569, respectively) |
|
196,296 |
|
226,561 |
| ||
Inventories |
|
33,537 |
|
41,006 |
| ||
Fair value of derivative instruments |
|
15,766 |
|
8,698 |
| ||
Deferred income taxes |
|
6,544 |
|
14,885 |
| ||
Other current assets ($10 and $169, respectively) |
|
24,645 |
|
11,748 |
| ||
Total current assets |
|
716,852 |
|
446,107 |
| ||
|
|
|
|
|
| ||
Property, plant and equipment ($306,023 and $156,808, respectively) |
|
4,975,209 |
|
3,302,369 |
| ||
Less: accumulated depreciation ($20,420 and $15,551, respectively) |
|
(568,670 |
) |
(438,062 |
) | ||
Total property, plant and equipment, net |
|
4,406,539 |
|
2,864,307 |
| ||
|
|
|
|
|
| ||
Other long-term assets: |
|
|
|
|
| ||
Investment in unconsolidated affiliate |
|
26,441 |
|
27,853 |
| ||
Intangibles, net of accumulated amortization of $206,375 and $168,168, respectively |
|
870,196 |
|
603,767 |
| ||
Goodwill |
|
144,582 |
|
67,918 |
| ||
Deferred financing costs, net of accumulated amortization of $17,091 and $13,194, respectively |
|
52,085 |
|
41,798 |
| ||
Deferred contract cost, net of accumulated amortization of $2,496 and $2,262, respectively |
|
754 |
|
988 |
| ||
Fair value of derivative instruments |
|
17,423 |
|
16,092 |
| ||
Other long-term assets ($102 and $102, respectively) |
|
2,271 |
|
1,595 |
| ||
Total assets |
|
$ |
6,237,143 |
|
$ |
4,070,425 |
|
|
|
|
|
|
| ||
LIABILITIES AND EQUITY |
|
|
|
|
| ||
Current liabilities: |
|
|
|
|
| ||
Accounts payable ($14,834 and $96, respectively) |
|
$ |
281,868 |
|
$ |
179,871 |
|
Accrued liabilities ($60,441 and $1,144, respectively) |
|
419,497 |
|
171,451 |
| ||
Fair value of derivative instruments |
|
32,823 |
|
90,551 |
| ||
Total current liabilities |
|
734,188 |
|
441,873 |
| ||
|
|
|
|
|
| ||
Deferred income taxes |
|
199,574 |
|
93,664 |
| ||
Fair value of derivative instruments |
|
29,715 |
|
65,403 |
| ||
Long-term debt, net of discounts of $8,258 and $1,050, respectively |
|
2,522,854 |
|
1,846,062 |
| ||
Other long-term liabilities ($77 and $73, respectively) |
|
129,872 |
|
121,356 |
| ||
|
|
|
|
|
| ||
Commitments and contingencies (Note 11) |
|
|
|
|
| ||
|
|
|
|
|
| ||
Equity: |
|
|
|
|
| ||
Common units (117,594 and 94,940 common units issued and outstanding, respectively) |
|
1,745,672 |
|
679,309 |
| ||
Class B units (19,954 units issued and outstanding) |
|
752,531 |
|
752,531 |
| ||
Non-controlling interest in consolidated subsidiaries |
|
122,737 |
|
70,227 |
| ||
Total equity |
|
2,620,940 |
|
1,502,067 |
| ||
Total liabilities and equity |
|
$ |
6,237,143 |
|
$ |
4,070,425 |
|
Asset and liability amounts in parentheses represent the portion of the consolidated balance attributable to VIEs.
The accompanying notes are an integral part of these condensed consolidated financial statements.
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, |
| ||||||||
|
|
2012 |
|
2011 |
|
2012 |
|
2011 |
| ||||
Revenue: |
|
|
|
|
|
|
|
|
| ||||
Revenue |
|
$ |
320,137 |
|
$ |
400,883 |
|
$ |
1,029,304 |
|
$ |
1,109,632 |
|
Derivative (loss) gain |
|
(36,400 |
) |
106,943 |
|
50,952 |
|
61,854 |
| ||||
Total revenue |
|
283,737 |
|
507,826 |
|
1,080,256 |
|
1,171,486 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Operating expenses: |
|
|
|
|
|
|
|
|
| ||||
Purchased product costs |
|
119,369 |
|
189,284 |
|
386,655 |
|
497,493 |
| ||||
Derivative loss (gain) related to purchased product costs |
|
11,643 |
|
(1,274 |
) |
(21,136 |
) |
17,866 |
| ||||
Facility expenses |
|
53,293 |
|
44,236 |
|
150,671 |
|
124,358 |
| ||||
Derivative loss (gain) related to facility expenses |
|
4,028 |
|
(2,787 |
) |
1,136 |
|
(2,871 |
) | ||||
Selling, general and administrative expenses |
|
21,922 |
|
20,162 |
|
69,025 |
|
60,454 |
| ||||
Depreciation |
|
48,136 |
|
38,715 |
|
132,199 |
|
110,280 |
| ||||
Amortization of intangible assets |
|
14,988 |
|
10,985 |
|
38,280 |
|
32,632 |
| ||||
Loss on disposal of property, plant and equipment |
|
655 |
|
147 |
|
2,983 |
|
4,619 |
| ||||
Accretion of asset retirement obligations |
|
141 |
|
557 |
|
540 |
|
934 |
| ||||
Total operating expenses |
|
274,175 |
|
300,025 |
|
760,353 |
|
845,765 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Income from operations |
|
9,562 |
|
207,801 |
|
319,903 |
|
325,721 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Other income (expense): |
|
|
|
|
|
|
|
|
| ||||
Earnings (loss) from unconsolidated affiliate |
|
246 |
|
(507 |
) |
788 |
|
(1,262 |
) | ||||
Interest income |
|
64 |
|
62 |
|
295 |
|
214 |
| ||||
Interest expense |
|
(30,621 |
) |
(26,899 |
) |
(86,855 |
) |
(83,036 |
) | ||||
Amortization of deferred financing costs and discount (a component of interest expense) |
|
(1,428 |
) |
(1,002 |
) |
(3,943 |
) |
(3,873 |
) | ||||
Loss on redemption of debt |
|
|
|
(133 |
) |
|
|
(43,461 |
) | ||||
Miscellaneous income (expense), net |
|
1 |
|
(4 |
) |
63 |
|
127 |
| ||||
(Loss) Income before provision for income tax |
|
(22,176 |
) |
179,318 |
|
230,251 |
|
194,430 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Provision for income tax (benefit) expense: |
|
|
|
|
|
|
|
|
| ||||
Current |
|
(17,948 |
) |
3,959 |
|
2,202 |
|
8,104 |
| ||||
Deferred |
|
10,528 |
|
21,905 |
|
39,396 |
|
18,338 |
| ||||
Total provision for income tax |
|
(7,420 |
) |
25,864 |
|
41,598 |
|
26,442 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Net (loss) income |
|
(14,756 |
) |
153,454 |
|
188,653 |
|
167,988 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Net loss (income) attributable to non-controlling interest |
|
416 |
|
(13,142 |
) |
(65 |
) |
(33,208 |
) | ||||
Net (loss) income attributable to the Partnerships unitholders |
|
$ |
(14,340 |
) |
$ |
140,312 |
|
$ |
188,588 |
|
$ |
134,780 |
|
|
|
|
|
|
|
|
|
|
| ||||
Net (loss) income attributable to the Partnerships common unitholders per common unit (Note 13): |
|
|
|
|
|
|
|
|
| ||||
Basic |
|
$ |
(0.13 |
) |
$ |
1.77 |
|
$ |
1.77 |
|
$ |
1.75 |
|
Diluted |
|
$ |
(0.13 |
) |
$ |
1.77 |
|
$ |
1.49 |
|
$ |
1.75 |
|
|
|
|
|
|
|
|
|
|
| ||||
Weighted average number of outstanding common units: |
|
|
|
|
|
|
|
|
| ||||
Basic |
|
113,994 |
|
78,619 |
|
105,916 |
|
76,118 |
| ||||
Diluted |
|
113,994 |
|
78,760 |
|
126,595 |
|
76,276 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Cash distribution declared per common unit |
|
$ |
0.80 |
|
$ |
0.70 |
|
$ |
2.35 |
|
$ |
2.02 |
|
The accompanying notes are an integral part of these condensed consolidated financial statements.
MARKWEST ENERGY PARTNERS, L.P.
Condensed Consolidated Statements of Changes in Equity
(unaudited, in thousands)
|
|
Common Units |
|
Class B Units |
|
Non- |
|
|
| ||||||||
|
|
Units |
|
Amounts |
|
Units |
|
Amounts |
|
Interest |
|
Total |
| ||||
December 31, 2011 |
|
94,940 |
|
$ |
679,309 |
|
19,954 |
|
$ |
752,531 |
|
$ |
70,227 |
|
$ |
1,502,067 |
|
Issuance of units in public offering, net of offering costs |
|
22,408 |
|
1,191,066 |
|
|
|
|
|
|
|
1,191,066 |
| ||||
Distributions paid |
|
|
|
(244,169 |
) |
|
|
|
|
(4,495 |
) |
(248,664 |
) | ||||
Contributions from non-controlling interest |
|
|
|
|
|
|
|
|
|
56,940 |
|
56,940 |
| ||||
Share-based compensation activity |
|
246 |
|
3,517 |
|
|
|
|
|
|
|
3,517 |
| ||||
Excess tax benefits related to share-based compensation |
|
|
|
2,216 |
|
|
|
|
|
|
|
2,216 |
| ||||
Deferred income tax impact from changes in equity |
|
|
|
(74,855 |
) |
|
|
|
|
|
|
(74,855 |
) | ||||
Net income |
|
|
|
188,588 |
|
|
|
|
|
65 |
|
188,653 |
| ||||
September 30, 2012 |
|
117,594 |
|
$ |
1,745,672 |
|
19,954 |
|
$ |
752,531 |
|
$ |
122,737 |
|
$ |
2,620,940 |
|
|
|
Common Units |
|
Non-controlling |
|
|
| |||||
|
|
Units |
|
Amounts |
|
Interest |
|
Total |
| |||
December 31, 2010 |
|
71,440 |
|
$ |
993,049 |
|
$ |
465,517 |
|
$ |
1,458,566 |
|
Issuance of units in public offering, net of offering costs |
|
7,475 |
|
323,492 |
|
|
|
323,492 |
| |||
Distributions paid |
|
|
|
(155,931 |
) |
(49,099 |
) |
(205,030 |
) | |||
Contributions from non-controlling interest |
|
|
|
|
|
80,332 |
|
80,332 |
| |||
Share-based compensation activity |
|
275 |
|
5,213 |
|
|
|
5,213 |
| |||
Excess tax benefits related to share-based compensation |
|
|
|
1,089 |
|
|
|
1,089 |
| |||
Net income |
|
|
|
134,780 |
|
33,208 |
|
167,988 |
| |||
September 30, 2011 |
|
79,190 |
|
$ |
1,301,692 |
|
$ |
529,958 |
|
$ |
1,831,650 |
|
The accompanying notes are an integral part of these condensed consolidated financial statements.
MARKWEST ENERGY PARTNERS, L.P.
Condensed Consolidated Statements of Cash Flows
(unaudited, in thousands)
|
|
Nine months ended September 30, |
| ||||
|
|
2012 |
|
2011 |
| ||
Cash flows from operating activities: |
|
|
|
|
| ||
Net income |
|
$ |
188,653 |
|
$ |
167,988 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
| ||
Depreciation |
|
132,199 |
|
110,280 |
| ||
Amortization of intangible assets |
|
38,280 |
|
32,632 |
| ||
Loss on redemption of debt |
|
|
|
43,461 |
| ||
Amortization of deferred financing costs and discount |
|
3,943 |
|
3,873 |
| ||
Accretion of asset retirement obligations |
|
540 |
|
934 |
| ||
Amortization of deferred contract cost |
|
234 |
|
234 |
| ||
Phantom unit compensation expense |
|
11,579 |
|
10,611 |
| ||
Equity in (earnings) loss of unconsolidated affiliate |
|
(788 |
) |
1,262 |
| ||
Distributions from unconsolidated affiliate |
|
2,200 |
|
300 |
| ||
Unrealized gain on derivative instruments |
|
(101,815 |
) |
(99,400 |
) | ||
Loss on disposal of property, plant and equipment |
|
2,983 |
|
4,619 |
| ||
Deferred income taxes |
|
39,396 |
|
18,338 |
| ||
Changes in operating assets and liabilities, net of working capital acquired: |
|
|
|
|
| ||
Receivables |
|
32,739 |
|
(12,776 |
) | ||
Inventories |
|
7,590 |
|
(19,470 |
) | ||
Other current assets |
|
(12,707 |
) |
(725 |
) | ||
Accounts payable and accrued liabilities |
|
36,737 |
|
56,716 |
| ||
Other long-term assets |
|
(676 |
) |
(284 |
) | ||
Other long-term liabilities |
|
8,631 |
|
12,656 |
| ||
Net cash provided by operating activities |
|
389,718 |
|
331,249 |
| ||
|
|
|
|
|
| ||
Cash flows from investing activities: |
|
|
|
|
| ||
Restricted cash |
|
1,003 |
|
|
| ||
Capital expenditures |
|
(1,240,866 |
) |
(359,926 |
) | ||
Acquisition of business, net of cash acquired |
|
(506,797 |
) |
(230,728 |
) | ||
Proceeds from disposal of property, plant and equipment |
|
589 |
|
2,968 |
| ||
Net cash flows used in investing activities |
|
(1,746,071 |
) |
(587,686 |
) | ||
|
|
|
|
|
| ||
Cash flows from financing activities: |
|
|
|
|
| ||
Proceeds from public equity offerings, net |
|
1,191,066 |
|
323,492 |
| ||
Proceeds from Credit Facility |
|
511,100 |
|
1,074,700 |
| ||
Payments of Credit Facility |
|
(577,100 |
) |
(929,600 |
) | ||
Proceeds from long-term debt |
|
742,613 |
|
499,000 |
| ||
Payments of long-term debt |
|
|
|
(440,638 |
) | ||
Payments of premiums on redemption of long-term debt |
|
|
|
(39,642 |
) | ||
Payments for debt issuance costs, deferred financing costs and registration costs |
|
(14,184 |
) |
(7,795 |
) | ||
Contributions from non-controlling interest |
|
56,940 |
|
80,332 |
| ||
Payments of SMR liability |
|
(1,525 |
) |
(1,390 |
) | ||
Cash paid for taxes related to net settlement of share-based payment awards |
|
(8,061 |
) |
(6,354 |
) | ||
Excess tax benefits related to share-based compensation |
|
2,216 |
|
1,089 |
| ||
Payment of distributions to common unitholders |
|
(244,169 |
) |
(155,931 |
) | ||
Payment of distributions to non-controlling interest |
|
(4,495 |
) |
(49,099 |
) | ||
Net cash flows provided by financing activities |
|
1,654,401 |
|
348,164 |
| ||
|
|
|
|
|
| ||
Net increase in cash and cash equivalents |
|
298,048 |
|
91,727 |
| ||
Cash and cash equivalents at beginning of year |
|
117,016 |
|
67,450 |
| ||
Cash and cash equivalents at end of period |
|
$ |
415,064 |
|
$ |
159,177 |
|
The accompanying notes are an integral part of these condensed consolidated financial statements.
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 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 and fractionator 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 Partnerships consolidated financial statements included in the Partnerships Annual Report on Form 10-K for the year ended December 31, 2011. In managements 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, 2012 are not necessarily indicative of results for the full year 2012 or any other future period.
The Partnerships unaudited condensed consolidated financial statements include all majority-owned or majority-controlled subsidiaries. In addition, MarkWest Utica EMG, L.L.C. and its subsidiaries (MarkWest Utica EMG), and MarkWest Pioneer, L.L.C. (MarkWest Pioneer), VIEs for which the Partnership has been determined to be the primary beneficiary, are included in the condensed consolidated financial statements (see Note 4). All intercompany investments, accounts and transactions have been eliminated. The Partnerships investment in Centrahoma Processing, LLC (Centrahoma), in which the Partnership exercises significant influence but does not control and is not the primary beneficiary, is accounted for using the equity method.
2. Recent Accounting Pronouncements
In May 2011, the FASB amended the accounting guidance for fair value measurement and disclosure. The amendment primarily clarifies the application of the existing guidance and provides for increased disclosures, particularly related to Level 3 fair value measurements. The amended guidance is effective for the Partnership prospectively as of January 1, 2012. Except for the additional disclosures included in Note 6, the adoption of the amended guidance did not have a material effect on the Partnerships condensed consolidated financial statements.
In December 2011, the FASB amended the accounting guidance for balance sheet offsetting for financial assets and financial liabilities. The amended guidance is intended to help investors and other financial statement users to better assess the effect or potential effect of offsetting arrangements on a companys financial position and provides for increased disclosures. The amended guidance is effective for the Partnership prospectively as of January 1, 2013. Except for additional disclosures related to our offsetting arrangements, the adoption of the amended guidance is not expected to have a material effect on the Partnerships consolidated financial statements.
3. Business Combination
Keystone Acquisition
On May 29, 2012, the Partnership acquired natural gas gathering and processing assets from Keystone Midstream Services, LLC (Keystone) for a cash purchase price of approximately $509.6 million, subject to finalization of working capital adjustments. Keystones existing assets are located in Butler County, Pennsylvania and include two cryogenic gas processing plants totaling 90 MMcf/d of processing capacity, a gas gathering system and associated field compression. The acquisition is referred to as the Keystone Acquisition.
As a result of the Keystone Acquisition, the Partnership became a party to a long-term fee-based agreement to gather and process certain natural gas owned or controlled by R.E. Gas Development, L.L.C. (Rex), a subsidiary of Rex Energy Corporation, and Summit Discovery Resources II, L.L.C. (Summit), a subsidiary of Sumitomo Corporation, at the acquired facilities and in 2013 to exchange the resulting NGLs for fractionated products at facilities already owned and operated by the Partnership. Rex and Summit have dedicated an area of approximately 900 square miles to the Partnership as part of this long-term gathering and processing agreement. As a result of the Keystone Acquisition, the Partnership has expanded its position in the liquids rich Marcellus Shale area into northwest Pennsylvania.
The Keystone Acquisition is accounted for as a business combination. The total purchase price is allocated to identifiable assets acquired and liabilities assumed based on the estimated fair values at the acquisition date. The remaining purchase price in excess of the fair value of the identifiable assets and liabilities is recorded as goodwill. The acquired assets and the related results of operations are included in the Partnerships Liberty segment. The following table summarizes the preliminary purchase price allocation for the Keystone Acquisition (in thousands):
Assets: |
|
|
| |
Cash |
|
$ |
2,837 |
|
Accounts receivable |
|
1,756 |
| |
Property, plant and equipment |
|
136,593 |
| |
Goodwill |
|
76,664 |
| |
Intangible asset |
|
304,708 |
| |
Liabilities: |
|
|
| |
Accounts payable |
|
(12,117 |
) | |
Other short-term liabilities |
|
(175 |
) | |
Other long-term liabilities |
|
(632 |
) | |
Total |
|
$ |
509,634 |
|
As of September 30, 2012, the purchase price for the Keystone Acquisition is $509.6 million subject to finalization of working capital adjustments. Due to the potential changes in the purchase price and the Partnerships continuing process to finalize the fair value estimates of the acquired assets and liabilities, the purchase price allocation is subject to further adjustment, which could impact depreciation and amortization expense.
The goodwill recognized from the Keystone Acquisition results primarily from synergies created from integrating the Keystone assets with the Partnerships existing Marcellus Shale operations and the Partnerships strengthened competitive position as it plans to expand its business in the newly developing liquids-rich areas of the Marcellus Shale. All of the goodwill is deductible for tax purposes.
The intangible asset consists of an identifiable contractual customer relationship with Rex and Summit. The acquired intangible asset will be amortized on a straight-line basis over the estimated customer contract useful life of approximately 19 years.
The results of operations of Keystone are included in the condensed consolidated financial statements from the acquisition date. Revenue and net income related to Keystone are immaterial for the three and nine months ended September 30, 2012.
Pro forma financial results that give effect to the Keystone Acquisition are not presented as any pro forma adjustments would not be material to the Partnerships historical results.
4. Variable Interest Entities
MarkWest Utica EMG
Effective January 1, 2012, the Partnership and EMG Utica, LLC (EMG Utica) executed agreements to form a joint venture, MarkWest Utica EMG, to develop significant natural gas gathering, processing and NGL fractionation, transportation and marketing infrastructure in Eastern Ohio. Under the terms of the agreements, the Partnership made an initial contribution to MarkWest Utica EMG in a nominal amount in exchange for a 60% membership interest in MarkWest Utica EMG, and EMG Utica made an initial contribution in a nominal amount and has agreed to contribute to MarkWest Utica EMG $350 million in cash on an as needed basis (the Initial EMG Contribution) in exchange for a 40% membership interest in MarkWest Utica EMG. Following the funding of the Initial EMG Contribution, the Partnership has the one time right to elect that (i) EMG Utica fund, as needed, all capital required to develop projects within MarkWest Utica EMG until the earlier of December 31, 2016 or such time as EMG Uticas total investment balance reaches $500 million (the Minimum EMG Investment) or (ii) the Partnership fund 60% of all capital required to develop projects within MarkWest Utica EMG until such time as EMG Uticas total investment balance equals the Minimum EMG Investment and EMG Utica will be required to fund the remaining 40% of all such capital. Once EMG Utica has funded capital equal to the Minimum EMG Investment, or if EMG Utica has not funded the Minimum EMG Investment by December 31, 2016, then commencing on January 1, 2017, the Partnership is required to fund, as needed, 100% of all capital required to develop projects within MarkWest Utica EMG until such time as the total investment balances of the Partnership and EMG Utica are in the ratio of 60% and 40%, respectively (such time being referred to as the First Equalization Date). If the First Equalization Date has not occurred by December 31, 2016, each members ownership interest will be adjusted to equal the proportionate share of capital that it has
contributed, and allocations of profits and losses and distributions of available cash will be made in accordance with those adjusted membership interests. Following the First Equalization Date, the Partnership shall have the right to elect to continue to fund up to 100% of any additional capital required until such time as the investment balances of the Partnership and EMG Utica are in the ratio of 70% and 30%, respectively (such time being referred to as the Second Equalization Date). To the extent the Partnership does not fully exercise such right at any time prior to the Second Equalization Date, EMG Utica shall have the right, but not the obligation, to contribute such additional capital that is requested and that is not contributed by the Partnership. After the Second Equalization Date, EMG Utica shall have the right, but not the obligation, to maintain a 30% interest in MarkWest Utica EMG by funding 30% of any additional required capital.
The Partnership has determined that MarkWest Utica EMG is a VIE primarily due to the Partnerships disproportionate economic interests as compared to its stated ownership interests and voting interests. The Partnerships 60% ownership interest in the entity is disproportionate to its economic interest due to the timing of the capital funding requirements described above. The Partnership has concluded that it is the primary beneficiary of MarkWest Utica EMG based on its role as the operator and its right to receive benefits and absorb losses of MarkWest Utica EMG. 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 MarkWest Utica EMG.
MarkWest Pioneer
MarkWest Pioneer is the owner and operator of the Arkoma Connector Pipeline. The Partnership and Arkoma Pipeline Partners, LLC share the equity interests in MarkWest Pioneer equally (50% and 50%). As discussed in Note 4 in the Partnerships Annual Report on Form 10-K for the year ended December 31, 2011, the Partnership determined that MarkWest Pioneer is a VIE and the Partnership is the primary beneficiary.
Financial Statement Impact of VIEs
As the primary beneficiary of MarkWest Pioneer and MarkWest Utica EMG, the Partnership consolidates the entities and recognizes non-controlling interests. As of December 31, 2011, MarkWest Pioneer was the only VIE included in the Partnerships condensed consolidated financial statements and its assets and liabilities are disclosed parenthetically on the accompanying Condensed Consolidated Balance Sheets. The following tables show the consolidated assets and liabilities attributable to MarkWest Pioneer and MarkWest Utica EMG, excluding intercompany balances, as of September 30, 2012 (in thousands).
|
|
As of September 30, 2012 |
| |||||||
|
|
MarkWest |
|
MarkWest |
|
Total |
| |||
ASSETS |
|
|
|
|
|
|
| |||
Cash and cash equivalents |
|
$ |
2,710 |
|
$ |
|
|
$ |
2,710 |
|
Receivables, net |
|
1,298 |
|
150 |
|
1,448 |
| |||
Other current assets |
|
10 |
|
|
|
10 |
| |||
Property, plant and equipment, net of accumulated depreciation of $20,278 and $142, respectively |
|
137,666 |
|
147,937 |
|
285,603 |
| |||
Other long-term assets |
|
102 |
|
|
|
102 |
| |||
Total assets |
|
$ |
141,786 |
|
$ |
148,087 |
|
$ |
289,873 |
|
|
|
|
|
|
|
|
| |||
LIABILITIES |
|
|
|
|
|
|
| |||
Accounts payable |
|
$ |
48 |
|
$ |
14,786 |
|
$ |
14,834 |
|
Accrued liabilities |
|
1,067 |
|
59,374 |
|
60,441 |
| |||
Other long-term liabilities |
|
77 |
|
|
|
77 |
| |||
Total liabilities |
|
$ |
1,192 |
|
$ |
74,160 |
|
$ |
75,352 |
|
The assets of the VIEs are the property of the respective entities and are not available to the Partnership for any other purpose, including as collateral for its secured debt (see Note 9 and Note 15). VIE asset balances can only be used to settle obligations of each respective VIE. The liabilities of the VIEs do not represent additional claims against the Partnerships general assets, and the creditors or beneficial interest holders of the VIE do not have recourse to the general credit of the Partnership. The Partnerships 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 compensation received for the performance of the operating services. The Partnership may temporarily fund MarkWest Utica EMG for certain projects due to the timing of the capital call process. The Partnership will receive distributions as reimbursement for any temporary funding. Other than temporary funding, 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, 2012 and 2011.
The results of operations of MarkWest Utica EMG and MarkWest Pioneer are included in the Partnerships Liberty and Southwest segments, respectively (see Note 14). Construction began for MarkWest Utica EMG assets in the second quarter of 2012 with total cash capital expenditures of approximately $88.6 million for the nine months ended September 30, 2012. With limited operating activities commencing in the third quarter 2012, the results of operations and cash flows, other than capital expenditures, related to MarkWest Utica EMG are not material to the Partnership. The result of operations and cash flows for MarkWest Pioneer are not material to the Partnership.
5. Derivative Financial Instruments
Commodity Derivatives
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 Partnerships control. The Partnerships profitability is directly affected by prevailing commodity prices primarily as a result of processing or conditioning at its own 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 natural gas drilling by the Partnerships producer customers, such prices also affect profitability. To protect itself financially against adverse price movements and to maintain more stable and predictable cash flows so that the Partnership can meet its cash distribution objectives, debt service and capital expenditures, the Partnership executes a strategy governed by the risk management policy approved by the General Partners board of directors (the Board). The Partnership has a committee comprised of senior management that oversees risk management activities (the Hedge Committee), continually monitors the risk management program and adjusts its strategy as 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 and options traded on the OTC market and fixed price forward contracts. The risk management policy does not allow for trading 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. The Partnership often manages a portion of its NGL price risk using crude oil contracts, referred to as proxy contracts, as the NGL financial markets are not as liquid and historically there has been a strong relationship between changes in NGL and crude oil prices. The pricing relationship between NGLs and crude oil, which may vary in certain periods due to various market conditions, has significantly weakened during the first nine months of 2012. 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 may settle its derivative positions prior to the contractual settlement date in order to take advantage of favorable terms at which the Partnership could settle these proxy contracts that are expected to be less effective. The Partnership enters into NGL derivative contracts when adequate market liquidity exists and future prices are satisfactory.
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 portion of its expected commodity price risk through the fourth quarter of 2014. 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 Credit Facility (participating bank group members). Currently, all of the Partnerships financial derivative positions are with participating bank group members. Management conducts a standard credit review on counterparties to derivative contracts. There are no collateral requirements for derivative contracts among the Partnership and any participating bank group members. Specifically, the Partnership is not required to post collateral when it enters into derivative contracts with participating bank group members as the participating bank group members have a collateral position in substantially all the wholly-owned assets of the Partnership other than
MarkWest Liberty Midstream and its subsidiaries. The Partnership uses standard master netting arrangements that allow for offset of positive and negative exposures.
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. The Partnerships accounting may cause volatility in the Condensed Consolidated Statements of Operations as the Partnership recognizes in current earnings all unrealized gains and losses from the changes in fair value on derivatives.
As of September 30, 2012, the Partnership had the following outstanding commodity contracts that were entered into to manage cash flow risk associated with future sales of NGLs or future purchases of natural gas.
Derivative contracts not designated as hedging instruments |
|
Financial |
|
Notional Quantity |
|
Crude Oil (bbl) |
|
Short |
|
6,214,543 |
|
Natural Gas (MMBtu) |
|
Long |
|
8,467,690 |
|
NGLs (gal) |
|
Short |
|
47,006,992 |
|
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 commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. This contract is accounted for as an embedded derivative and is recorded at fair value. The changes in fair value of this commodity contract are based on the difference between the contractual and index pricing and are recorded in earnings through Derivative (loss) gain related to purchased product costs. In February 2011, the Partnership executed agreements with the producer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022. As of September 30, 2012, the estimated fair value of this contract was a liability of $87.9 million and the recorded value was a liability of $34.4 million. The recorded liability does not include the inception fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception of February 1, 2011 is deemed to be allocable to the host processing contract and therefore not recorded as a derivative liability. See the following table for a reconciliation of the liability recorded for the embedded derivative as of September 30, 2012 (in thousands):
Fair value of commodity contract |
|
$ |
87,863 |
|
Inception value for period from April 1, 2015 to December 31, 2022 |
|
(53,507 |
) | |
Derivative liability as of September 30, 2012 |
|
$ |
34,356 |
|
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 its plant location in the Gulf Coast segment through the fourth quarter of 2014. Changes in the fair value of the derivative component of this contract are recorded in Derivative loss (gain) related to facility expenses. As of September 30, 2012, the estimated fair value of this contract was an asset of $6.4 million.
Financial Statement Impact of Derivative Instruments
There were no material changes to the Partnerships policy regarding the accounting for these instruments as previously disclosed in the Partnerships Annual Report on Form 10-K for the year ended December 31, 2011. The fair value of the Partnerships derivative instruments recorded on its Condensed Consolidated Balance Sheets and its Condensed Consolidated Statements of Operations is summarized below (in thousands):
|
|
Assets |
|
Liabilities |
| ||||||||
Derivative instruments not designated as hedging |
|
September 30, |
|
December 31, |
|
September 30, |
|
December 31, |
| ||||
Commodity contracts(1) |
|
|
|
|
|
|
|
|
| ||||
Fair value of derivative instruments current |
|
$ |
15,766 |
|
$ |
8,698 |
|
$ |
(32,823 |
) |
$ |
(90,551 |
) |
Fair value of derivative instruments - long-term |
|
17,423 |
|
16,092 |
|
(29,715 |
) |
(65,403 |
) | ||||
Total |
|
$ |
33,189 |
|
$ |
24,790 |
|
$ |
(62,538 |
) |
$ |
(155,954 |
) |
(1) Includes Embedded Derivatives in Commodity Contracts as discussed above.
Derivative contracts not designated as hedging |
|
Three months ended September 30, |
|
Nine months ended September 30, |
| ||||||||
recognized in income |
|
2012 |
|
2011 |
|
2012 |
|
2011 |
| ||||
Revenue: Derivative (loss) gain |
|
|
|
|
|
|
|
|
| ||||
Realized loss |
|
$ |
(2,025 |
) |
$ |
(9,809 |
) |
$ |
(9,662 |
) |
$ |
(36,386 |
) |
Unrealized (loss) gain |
|
(34,375 |
) |
116,752 |
|
60,614 |
|
98,240 |
| ||||
Total revenue: derivative (loss) gain |
|
(36,400 |
) |
106,943 |
|
50,952 |
|
61,854 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Derivative (loss) gain related to purchased product costs |
|
|
|
|
|
|
|
|
| ||||
Realized loss |
|
(6,334 |
) |
(5,989 |
) |
(21,201 |
) |
(19,436 |
) | ||||
Unrealized (loss) gain |
|
(5,309 |
) |
7,263 |
|
42,337 |
|
1,570 |
| ||||
Total derivative (loss) gain related to purchase product costs |
|
(11,643 |
) |
1,274 |
|
21,136 |
|
(17,866 |
) | ||||
|
|
|
|
|
|
|
|
|
| ||||
Derivative (loss) gain related to facility expenses |
|
|
|
|
|
|
|
|
| ||||
Unrealized (loss) gain |
|
(4,028 |
) |
2,787 |
|
(1,136 |
) |
2,871 |
| ||||
Total (loss) gain |
|
$ |
(52,071 |
) |
$ |
111,004 |
|
$ |
70,952 |
|
$ |
46,859 |
|
For the three months ended September 30, 2012 and 2011, the Realized (loss)gainrevenue includes amortization of premium payments of zero and $1.2 million, respectively. For the nine months ended September 30, 2012 and 2011, the Realized (loss) gainrevenue includes amortization of premium payments of zero and $3.3 million, respectively.
During the first nine months of 2012, the Partnership settled a portion of its crude oil derivative positions related to 2014 commodity price exposure prior to the contractual settlement date in order to take advantage of favorable crude oil prices at which the Partnership could settle these proxy contracts that are expected to be less effective. The Partnership plans to opportunistically enter into future NGL hedge transactions to manage the 2014 NGL price exposure. Upon early settlement, the Partnership received $11.3 million which was recorded as a realized gain in Revenue: Derivative (loss) gain in the accompanying Consolidated Statements of Operations.
6. Fair Value
Fair value measurements and disclosures relate primarily to the Partnerships derivative positions discussed in Note 5. The following table presents the derivative instruments carried at fair value as of September 30, 2012 and December 31, 2011 (in thousands):
As of September 30, 2012 |
|
Assets |
|
Liabilities |
| ||
Significant other observable inputs (Level 2) |
|
|
|
|
| ||
Commodity contracts |
|
$ |
7,748 |
|
$ |
(25,894 |
) |
Significant unobservable inputs (Level 3) |
|
|
|
|
| ||
Commodity contracts |
|
19,060 |
|
(2,288 |
) | ||
Embedded derivatives in commodity contracts |
|
6,381 |
|
(34,356 |
) | ||
Total carrying value in Condensed Consolidated Balance Sheet |
|
$ |
33,189 |
|
$ |
(62,538 |
) |
As of December 31, 2011 |
|
Assets |
|
Liabilities |
| ||
Significant other observable inputs (Level 2) |
|
|
|
|
| ||
Commodity contracts |
|
$ |
5,063 |
|
$ |
(79,358 |
) |
Significant unobservable inputs (Level 3) |
|
|
|
|
| ||
Commodity contracts |
|
12,210 |
|
(15,175 |
) | ||
Embedded derivatives in commodity contracts |
|
7,517 |
|
(61,421 |
) | ||
Total carrying value in Condensed Consolidated Balance Sheet |
|
$ |
24,790 |
|
$ |
(155,954 |
) |
The following table provides additional information about the significant unobservable inputs used in the valuation of Level 3 instruments as of September 30, 2012. The market approach is used for valuation of all instruments.
Level 3 Instrument |
|
Balance Sheet |
|
Unobservable |
|
Value Range |
|
Time Period |
| ||
Commodity contracts |
|
Assets |
|
Forward propane prices (per gallon) |
|
$0.92 |
- |
$0.99 |
|
Oct. 2012 - Dec. 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forward isobutane prices (per gallon) |
|
$1.60 |
- |
$1.67 |
|
Jan. 2013 - Dec. 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forward normal butane prices (per gallon) |
|
$1.41 |
- |
$1.52 |
|
Jan. 2013 - Dec. 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forward natural gasoline prices (per gallon) |
|
$1.89 |
- |
$2.02 |
|
Jan. 2013 - Dec. 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude option volatilities (%) |
|
17.82% |
- |
31.96% |
|
Oct. 2012 - Dec. 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities |
|
Forward propane prices (per gallon) |
|
$0.92 |
- |
$0.95 |
|
Oct. 2012 - Mar. 2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude option volatilities (%) |
|
16.55% |
- |
37.77% |
|
Oct. 2012 - Dec. 2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Embedded derivatives in commodity contracts |
|
Asset |
|
ERCOT Pricing (per MegaWatt Hour) (1) |
|
$26.53 |
- |
$60.98 |
|
Oct. 2012 - Dec. 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liability |
|
Forward propane prices (per gallon) |
|
$0.90 |
- |
$0.99 |
|
Oct. 2012 - Dec. 2022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forward isobutane prices (per gallon) |
|
$1.54 |
- |
$1.70 |
|
Oct. 2012 - Dec. 2022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forward normal butane prices (per gallon) |
|
$1.37 |
- |
$1.52 |
|
Oct. 2012 - Dec. 2022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forward natural gasoline prices (per gallon) |
|
$1.81 |
- |
$2.02 |
|
Oct. 2012 - Dec. 2022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forward natural gas prices (per mmbtu) |
|
$3.01 |
- |
$6.33 |
|
Oct. 2012 - Dec. 2022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Probability of renewal (2) |
|
|
0% |
|
|
|
|
(1) The forward ERCOT prices utilized in the valuations are generally increasing over time with a seasonal spike in pricing in the summer months.
(2) The producer counterparty to the embedded derivative has the option to renew the gas purchase agreement and the related keep-whole processing agreement for two successive five year terms after 2022. The embedded gas purchase agreement cannot be renewed without the renewal of the related keep-whole processing agreement. Due to the significant number of years until the renewal options are exercisable and the high level of uncertainty regarding the counterpartys future business strategy, the future commodity price environment, and the future competitive environment for midstream services in the Appalachia area, management determined that a 0% probability of renewal is an appropriate assumption.
Fair Value Sensitivity Related to Unobservable Inputs
Commodity contracts (assets and liabilities) - For the Partnerships commodity contracts, increases in forward NGL prices result in a decrease in the fair value of the derivative assets and an increase in the fair value of the derivative liabilities. The forward prices for the individual NGL products generally increase or decrease in a positive correlation with one another. An increase in crude option volatilities will generally result in an increase in the fair value of the Partnerships derivative assets and derivative liabilities in commodity contracts.
Embedded derivative in commodity contracts (liability) - The embedded derivative liability relates to the natural gas purchase agreement embedded in a keep-whole processing agreement as discussed further in Note 5. Increases (decreases) in forward NGL prices result in an increase (decrease) in the fair value of the embedded derivative liability. An increase in the probability of renewal would result in an increase in the fair value of the related embedded derivative liability.
Embedded derivative in commodity contracts (asset) - The embedded derivative asset relates to utilities costs discussed further in Note 5. Increases in the forward ERCOT prices, relative to natural gas prices, result in an increase in the fair value of the embedded derivative asset.
Level 3 Valuation Process
The Partnerships Risk Management Department (the Risk Department) is responsible for the valuation of the Partnerships commodity derivative contracts and embedded derivatives in commodity contracts. The Risk Department reports to the Chief Financial Officer and is responsible for the oversight of the Partnerships commodity risk management program. The members of the Risk Department have the requisite experience, knowledge and day-to-day involvement in the energy commodity markets to ensure appropriate valuations and understand the changes in the valuations from period to period. The valuations of the commodity derivative contracts are performed by a third-party pricing service and reviewed and validated on a quarterly basis by the Risk Department by comparing the pricing and option volatilities to actual market data and/or data provided by other independent third-party pricing services. The valuations for the embedded derivatives in commodity contracts are completed by the Risk Department utilizing the market data and price curves provided by the third-party pricing service. For the embedded derivative in the keep-whole processing arrangement discussed in Note 5, the Risk Department must develop forward price curves for NGLs and natural gas for periods in which price curves are not available from third-party pricing services due to insufficient market data. As of September 30, 2012, the Risk Department utilized internally developed price curves for the period of January 2015 through December 2022 in the valuation of the embedded derivative in the keep-whole processing arrangement. In developing the pricing curves for these periods, the Risk Department maximizes its use of the latest known market data and trends as well as its understanding of the historical relationships between the forward NGL and natural gas prices and the forward market data that is available for the required period, such as crude oil pricing and natural gas pricing from other markets. However, there is very limited actual market data available to validate the Partnerships estimated price curves. The fair value of the Partnerships commodity derivative contracts and embedded derivatives in commodity contracts are reviewed quarterly by the Hedge Committee.
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, 2012 and 2011 for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands).
|
|
Three months ended September 30, 2012 |
|
Nine months ended September 30, 2012 |
| ||||||||
|
|
Commodity |
|
Embedded |
|
Commodity |
|
Embedded |
| ||||
Fair value at beginning of period |
|
$ |
29,556 |
|
$ |
(10,395 |
) |
$ |
(2,965 |
) |
$ |
(53,904 |
) |
Total (loss) gain (realized and unrealized) included in earnings (1) |
|
(13,199 |
) |
(19,842 |
) |
21,016 |
|
17,829 |
| ||||
Settlements |
|
415 |
|
2,262 |
|
(1,279 |
) |
8,100 |
| ||||
Fair value at end of period |
|
$ |
16,772 |
|
$ |
(27,975 |
) |
$ |
16,772 |
|
$ |
(27,975 |
) |
|
|
|
|
|
|
|
|
|
| ||||
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period (1) |
|
$ |
(11,754 |
) |
$ |
(15,643 |
) |
$ |
14,843 |
|
$ |
17,728 |
|
|
|
Three months ended September 30, 2011 |
|
Nine months ended September 30, 2011 |
| ||||||||
|
|
Commodity |
|
Embedded |
|
Commodity |
|
Embedded |
| ||||
Fair value at beginning of period |
|
$ |
(22,290 |
) |
$ |
(49,447 |
) |
$ |
(14,357 |
) |
$ |
(34,936 |
) |
Total gain (loss) (realized and unrealized) included in earnings (1) |
|
47,939 |
|
8,042 |
|
35,402 |
|
(14,063 |
) | ||||
Settlements |
|
3,167 |
|
4,167 |
|
7,771 |
|
11,761 |
| ||||
Fair value at end of period |
|
$ |
28,816 |
|
$ |
(37,238 |
) |
$ |
28,816 |
|
$ |
(37,238 |
) |
|
|
|
|
|
|
|
|
|
| ||||
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period (1) |
|
$ |
48,544 |
|
$ |
8,337 |
|
$ |
39,196 |
|
$ |
(10,813 |
) |
(1) Gains and losses on Commodity Derivative Contracts classified as Level 3 are recorded in Revenue: Derivative (loss) gain. Gains and losses on Embedded Derivatives in Commodity Contracts are recorded in Purchased product costs, Derivative loss (gain) related to purchased product costs, Facility expenses, and Derivative loss (gain) related to facility expenses.
7. Inventories
Inventories consist of the following (in thousands):
|
|
September 30, 2012 |
|
December 31, 2011 |
| ||
NGLs |
|
$ |
23,120 |
|
$ |
32,352 |
|
Spare parts, materials and supplies |
|
10,417 |
|
8,654 |
| ||
Total inventories |
|
$ |
33,537 |
|
$ |
41,006 |
|
8. Goodwill
Changes in goodwill for the nine months ended September 30, 2012 are summarized as follows (in thousands):
|
|
Southwest |
|
Northeast |
|
Liberty |
|
Gulf Coast |
|
Total |
| |||||
Gross goodwill as of December 31, 2011 |
|
$ |
24,324 |
|
$ |
62,445 |
|
$ |
|
|
$ |
9,854 |
|
$ |
96,623 |
|
Acquisition (1) |
|
|
|
|
|
76,664 |
|
|
|
76,664 |
| |||||
Gross goodwill as of September 30, 2012 |
|
24,324 |
|
62,445 |
|
76,664 |
|
9,854 |
|
173,287 |
| |||||
Cumulative impairment (2) |
|
(18,851 |
) |
|
|
|
|
(9,854 |
) |
(28,705 |
) | |||||
Balance as of September 30, 2012 |
|
$ |
5,473 |
|
$ |
62,445 |
|
$ |
76,664 |
|
$ |
|
|
$ |
144,582 |
|
(1) Represents goodwill associated with the Keystone Acquisition (see Note 3).
(2) All impairments recorded in the fourth quarter of 2008.
9. Long-Term Debt
Debt is summarized below (in thousands):
|
|
September 30, 2012 |
|
December 31, 2011 |
| ||
Credit Facility |
|
|
|
|
| ||
Credit Facility, 4.25% interest, due September 2017 |
|
$ |
|
|
$ |
66,000 |
|
|
|
|
|
|
| ||
Senior Notes (1) |
|
|
|
|
| ||
2018 Senior Notes, 8.75% interest, net of discount of $114 and $129, respectively, issued April and May 2008 and due April 2018 |
|
80,998 |
|
80,983 |
| ||
2020 Senior Notes, 6.75% interest, issued November 2010 and due November 2020 |
|
500,000 |
|
500,000 |
| ||
2021 Senior Notes, 6.5% interest, net of discount of $849 and $921, respectively, issued February and March 2011 and due August 2021 |
|
499,151 |
|
499,079 |
| ||
2022 Senior Notes, 6.25% interest, issued October 2011 and due June 2022 |
|
700,000 |
|
700,000 |
| ||
2023 Senior Notes, 5.5% interest, net of discount of $7,295 and $0, respectively, issued August 2012 and due February 2023 |
|
742,705 |
|
|
| ||
Total long-term debt |
|
$ |
2,522,854 |
|
$ |
1,846,062 |
|
(1) The estimated aggregate fair value of the senior notes (collectively, the Senior Notes) was approximately $2,706.7 million and $1,880.7 million as of September 30, 2012 and December 31, 2011, respectively, based on quoted prices in an inactive market. The fair value of the Partnerships Senior Notes is considered a Level 3 measurement.
Credit Facility
On June 29, 2012, the Partnership amended its Credit Facility to increase the borrowing capacity to $1.2 billion and retained the existing accordion option, providing for potential future increases of up to an aggregate of $250 million upon the satisfaction of certain requirements. The term of the Credit Facility was extended one year and now matures on September 7, 2017. The Partnership incurred approximately $2.5 million of deferred financing costs associated with modifications of the Credit Facility during the nine months ended September 30, 2012.
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 by the Partnerships wholly-owned subsidiaries, other than MarkWest Liberty Midstream and its subsidiaries, and collateralized by substantially all of the Partnerships assets and those of its wholly-owned subsidiaries, other than MarkWest Liberty Midstream and its
subsidiaries. As of September 30, 2012, the Partnership had no borrowings outstanding and approximately $21.6 million of letters of credit outstanding under the Credit Facility, leaving approximately $1,178.4 million available for borrowing.
Senior Notes
On August 10, 2012, the Partnership completed a public offering of $750 million in aggregate principal amount of 5.5% senior unsecured notes (2023 Senior Notes), which were issued at 99.015% of par. The 2023 Senior Notes mature on February 15, 2023, and interest is payable semi-annually in arrears on February 15 and August 15, commencing February 15, 2013. The Partnership received net proceeds of approximately $731 million from the 2023 Senior Notes offering after deducting the underwriting fees and other third-party expenses. The Partnership used a portion of the net proceeds from the offering to repay borrowings under its Credit Facility and used the remainder for general partnership purposes, including, but not limited to, funding capital expenditures and general working capital.
10. Equity
Equity Offerings
In January 2012, the Partnership issued approximately 0.7 million common units representing limited partner interests pursuant to the underwriters exercise of their option to purchase additional common units under the equity offering initiated in December 2011. The total net proceeds from the exercise of this option were approximately $38 million and were used to partially fund the Partnerships ongoing capital expenditure program.
In March 2012, the Partnership completed a public offering of approximately 6.8 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters over-allotment option. Net proceeds after deducting underwriting fees and other third-party offering expenses were approximately $388 million and were used to partially fund the Partnerships ongoing capital expenditure program.
In May 2012, the Partnership completed a public offering of 8.0 million newly issued common units representing limited partner interests. Net proceeds after deducting underwriting fees and other third-party offering expenses were approximately $427 million, and were used to partially fund the Keystone Acquisition.
In August 2012, the Partnership completed a public offering of approximately 6.9 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters over-allotment option. Net proceeds after deducting underwriting fees and other third-party offering expenses were approximately $338 million and were used to partially fund the Partnerships capital expenditure program, for general working capital and for other general partnership purposes.
Distributions of Available Cash and Range of Unit Prices
|
|
Common Unit Price |
|
Distribution |
|
|
|
|
|
|
| |||||
Quarter Ended |
|
High |
|
Low |
|
Unit |
|
Declaration Date |
|
Record Date |
|
Payment Date |
| |||
September 30, 2012 |
|
$ |
55.04 |
|
$ |
49.01 |
|
$ |
0.81 |
|
October 25, 2012 |
|
November 7, 2012 |
|
November 14, 2012 |
|
June 30, 2012 |
|
$ |
60.32 |
|
$ |
45.36 |
|
$ |
0.80 |
|
July 26, 2012 |
|
August 6, 2012 |
|
August 14, 2012 |
|
March 31, 2012 |
|
$ |
61.60 |
|
$ |
53.51 |
|
$ |
0.79 |
|
April 26, 2012 |
|
May 7, 2012 |
|
May 15, 2012 |
|
December 31, 2011 |
|
$ |
56.82 |
|
$ |
42.18 |
|
$ |
0.76 |
|
January 26, 2012 |
|
February 6, 2012 |
|
February 14, 2012 |
|
11. 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 the ordinary course of business, the Partnership is a party to various 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 Partnerships financial condition, liquidity or results of operations.
Contract Contingencies
Certain natural gas processing arrangements in the Partnerships Liberty and Northeast segments require the Partnership to construct new natural gas processing plants and NGL pipelines. Some contracts contain certain fees and charges if specified construction milestones are not achieved for reasons other than force majeure. The Partnership has experienced delays in the construction of a processing facility in the Partnerships Liberty Segment due to events that management considers force majeure, including inabilities or delays in obtaining requisite permits, as well as extreme weather events. The requisite permits were subsequently issued several months later than expected and construction has since re-commenced, however those delays exacerbated construction conditions. In addition, the Partnership continued to experience extraordinary weather events in the first quarter of 2012, which resulted in additional delays. Delay charges for delays other than due to force majeure events are $1.0 million for each month (pro-rated for partial months) that the Partnership does not achieve certain intermediate and final completion construction milestones. In addition, if delays (other than due to force majeure events) are six months or longer, the producer has the option to purchase the processing facilities and terminate the processing agreement with a substantial termination fee. The Partnership has made a force majeure claim as the delays were a direct result of permit delays and weather which constitute force majeure events under the applicable contract. The customer has reserved its rights to dispute the Partnerships force majeure claim, but has not requested the payment of any delay charges. The Partnerships management believes it has a convincing legal position and believes that its force majeure claim would be recognized as valid if contested. The Partnership has completed construction of interim compression and transportation facilities and is providing alternative processing services to mitigate the impact of these delays.
Effective July 2012, the Partnership amended a significant office lease to include additional space and extend the term of the lease through 2024. The following table shows the increase in minimum future lease payments as of September 30, 2012 compared to the amount disclosed in Note 18 Commitments and Contingencies in the Partnerships Form 10-K for the year ended December 31, 2011 (in thousands):
2012 |
|
$ |
569 |
|
2013 |
|
4,295 |
| |
2014 |
|
3,995 |
| |
2015 |
|
3,926 |
| |
2016 |
|
4,747 |
| |
2017 and thereafter |
|
58,221 |
| |
Total |
|
$ |
75,753 |
|
12. Income Taxes
A reconciliation of the provision for income tax and the amount computed by applying the federal statutory rate to income before provision for income tax for the nine months ended September 30, 2012 and 2011 is as follows (in thousands):
|
|
Nine months ended September 30, 2012 |
| ||||||||||
|
|
Corporation |
|
Partnership |
|
Eliminations |
|
Consolidated |
| ||||
Income before provision for income tax |
|
$ |
74,679 |
|
$ |
153,363 |
|
$ |
2,209 |
|
$ |
230,251 |
|
Federal statutory rate |
|
35 |
% |
0 |
% |
0 |
% |
|
| ||||
Federal income tax at statutory rate |
|
26,138 |
|
|
|
|
|
26,138 |
| ||||
Permanent items |
|
21 |
|
|
|
|
|
21 |
| ||||
State income taxes, net of federal benefit |
|
3,418 |
|
734 |
|
|
|
4,152 |
| ||||
Provision on income from Class A units (1) |
|
11,287 |
|
|
|
|
|
11,287 |
| ||||
Provision for income tax |
|
$ |
40,864 |
|
$ |
734 |
|
$ |
|
|
$ |
41,598 |
|
|
|
Nine months ended September 30, 2011 |
| ||||||||||
|
|
Corporation |
|
Partnership |
|
Eliminations |
|
Consolidated |
| ||||
Income before provision for income tax |
|
$ |
31,993 |
|
$ |
166,649 |
|
$ |
(4,212 |
) |
$ |
194,430 |
|
Federal statutory rate |
|
35 |
% |
0 |
% |
0 |
% |
|
| ||||
Federal income tax at statutory rate |
|
11,198 |
|
|
|
|
|
11,198 |
| ||||
Permanent items |
|
22 |
|
|
|
|
|
22 |
| ||||
State income taxes net of federal benefit |
|
889 |
|
848 |
|
|
|
1,737 |
| ||||
Provision on income from Class A units (1) |
|
13,359 |
|
|
|
|
|
13,359 |
| ||||
Other |
|
126 |
|
|
|
|
|
126 |
| ||||
Provision for income tax |
|
$ |
25,594 |
|
$ |
848 |
|
$ |
|
|
$ |
26,442 |
|
(1) The Corporation and the General Partner of the Partnership own Class A units of the Partnership that were received in the merger of the Corporation and the Partnership completed in February 2008. The Class A units share, on a pro-rata basis, in the income or loss of the Partnership, except for items attributable to the Partnerships ownership of or sale of shares of the Corporations common stock. The provision for income tax on income from Class A units includes intra period allocations to continued operations and excludes allocations to equity.
During the three months ended September 30, 2012, management updated its estimates of the Corporations taxable income primarily due to additional depreciation recognized for income tax purposes on property, plant and equipment that is expected to be placed into service in 2012. The increase in expected depreciation for income tax purposes resulted in a current tax benefit, and corresponding deferred tax expense, of $17.6 million for the three and nine months ended September 30, 2012.
13. Earnings (Loss) Per Common Unit
The following table shows the computation of basic and diluted net income (loss) per common unit for the three and nine months ended September 30, 2012 and 2011, and the weighted-average units used to compute basic and diluted net income (loss) per common unit (in thousands, except per unit data):
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
| ||||||||
|
|
2012 |
|
2011 |
|
2012 |
|
2011 |
| ||||
Net (loss) income attributable to the Partnerships unitholders |
|
$ |
(14,340 |
) |
$ |
140,312 |
|
$ |
188,588 |
|
$ |
134,780 |
|
Less: Income allocable to phantom units |
|
541 |
|
1,287 |
|
1,595 |
|
1,288 |
| ||||
(Loss) Income available for common unitholders - basic |
|
(14,881 |
) |
139,025 |
|
186,993 |
|
133,492 |
| ||||
Add: Income allocable to phantom units and DER expense |
|
|
|
|
|
1,627 |
|
|
| ||||
(Loss) Income available for common unitholders - diluted |
|
$ |
(14,881 |
) |
$ |
139,025 |
|
$ |
188,620 |
|
$ |
133,492 |
|
|
|
|
|
|
|
|
|
|
| ||||
Weighted average common units outstanding - basic |
|
113,994 |
|
78,619 |
|
105,916 |
|
76,118 |
| ||||
Potential common shares (Class B and phantom units) (2) |
|
|
|
141 |
|
20,679 |
|
158 |
| ||||
Weighted average common units outstanding - diluted |
|
113,994 |
|
78,760 |
|
126,595 |
|
76,276 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Net (loss) income attributable to the Partnerships common unitholders per common unit (1) |
|
|
|
|
|
|
|
|
| ||||
Basic |
|
$ |
(0.13 |
) |
$ |
1.77 |
|
$ |
1.77 |
|
$ |
1.75 |
|
Diluted |
|
$ |
(0.13 |
) |
$ |
1.77 |
|
$ |
1.49 |
|
$ |
1.75 |
|
(1) Earnings per Class B units equals zero as Class B unitholders are not entitled to receive distributions and therefore no income is allocable to Class B units under the two class method.
(2) For the three months ended September 30, 2012, 20,641 units were excluded from the calculation of diluted units because the impact was anti-dilutive.
14. Segment Information
The Partnership prepares segment information in accordance with GAAP. Certain items below Income from operations in the accompanying 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 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 the Partnerships segment profit measure, Operating income before items not allocated to segments, for the three and nine months ended September 30, 2012 and 2011 and capital expenditures for the nine months ended September 30, 2012 and 2011 for the reported segments (in thousands).
Three months ended September 30, 2012:
|
|
Southwest |
|
Northeast |
|
Liberty |
|
Gulf Coast |
|
Total |
| |||||
Segment revenue |
|
$ |
181,456 |
|
$ |
39,987 |
|
$ |
78,852 |
|
$ |
21,477 |
|
$ |
321,772 |
|
Purchased product costs |
|
92,112 |
|
11,054 |
|
16,203 |
|
|
|
119,369 |
| |||||
Net operating margin |
|
89,344 |
|
28,933 |
|
62,649 |
|
21,477 |
|
202,403 |
| |||||
Facility expenses |
|
20,527 |
|
6,267 |
|
20,241 |
|
8,928 |
|
55,963 |
| |||||
Portion of operating income (loss) attributable to non-controlling interests |
|
1,543 |
|
|
|
(627 |
) |
|
|
916 |
| |||||
Operating income before items not allocated to segments |
|
$ |
67,274 |
|
$ |
22,666 |
|
$ |
43,035 |
|
$ |
12,549 |
|
$ |
145,524 |
|
Three months ended September 30, 2011:
|
|
Southwest |
|
Northeast |
|
Liberty |
|
Gulf Coast |
|
Total |
| |||||
Segment revenue |
|
$ |
241,998 |
|
$ |
55,920 |
|
$ |
78,586 |
|
$ |
26,868 |
|
$ |
403,372 |
|
Purchased product costs |
|
141,067 |
|
15,947 |
|
32,270 |
|
|
|
189,284 |
| |||||
Net operating margin |
|
100,931 |
|
39,973 |
|
46,316 |
|
26,868 |
|
214,088 |
| |||||
Facility expenses |
|
21,043 |
|
6,879 |
|
9,108 |
|
9,798 |
|
46,828 |
| |||||
Portion of operating income attributable to non-controlling interests |
|
1,227 |
|
|
|
18,223 |
|
|
|
19,450 |
| |||||
Operating income before items not allocated to segments |
|
$ |
78,661 |
|
$ |
33,094 |
|
$ |
18,985 |
|
$ |
17,070 |
|
$ |
147,810 |
|
The following is a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to income before provision for income tax for the three months ended September 30, 2012 and 2011 (in thousands):
|
|
Three months ended September 30, |
| ||||
|
|
2012 |
|
2011 |
| ||
|
|
|
|
|
| ||
Total segment revenue |
|
$ |
321,772 |
|
$ |
403,372 |
|
Derivative (loss) gain not allocated to segments |
|
(36,400 |
) |
106,943 |
| ||
Revenue deferral adjustment (1) |
|
(1,635 |
) |
(2,489 |
) | ||
Total revenue |
|
$ |
283,737 |
|
$ |
507,826 |
|
|
|
|
|
|
| ||
Operating income before items not allocated to segments |
|
$ |
145,524 |
|
$ |
147,810 |
|
Portion of operating income attributable to non-controlling interests |
|
916 |
|
19,450 |
| ||
Derivative (loss) gain not allocated to segments |
|
(52,071 |
) |
111,004 |
| ||
Revenue deferral adjustment (1) |
|
(1,635 |
) |
(2,489 |
) | ||
Compensation expense included in facility expenses not allocated to segments |
|
(193 |
) |
(263 |
) | ||
Facility expenses adjustments (2) |
|
2,863 |
|
2,855 |
| ||
Selling, general and administrative expenses |
|
(21,922 |
) |
(20,162 |
) | ||
Depreciation |
|
(48,136 |
) |
(38,715 |
) | ||
Amortization of intangible assets |
|
(14,988 |
) |
(10,985 |
) | ||
|
|
|
|
|
| ||
Loss on disposal of property, plant and equipment |
|
(655 |
) |
(147 |
) | ||
Accretion of asset retirement obligations |
|
(141 |
) |
(557 |
) | ||
Income from operations |
|
9,562 |
|
207,801 |
| ||
|
|
|
|
|
| ||
Earnings (loss) from unconsolidated affiliate |
|
246 |
|
(507 |
) | ||
Interest income |
|
64 |
|
62 |
| ||
Interest expense |
|
(30,621 |
) |
(26,899 |
) | ||
Amortization of deferred financing costs and discount (a component of interest expense) |
|
(1,428 |
) |
(1,002 |
) | ||
Loss on redemption of debt |
|
|
|
(133 |
) | ||
Miscellaneous income, net |
|
1 |
|
(4 |
) | ||
(Loss) Income before provision for income tax |
|
$ |
(22,176 |
) |
$ |
179,318 |
|
(1) Amount relates to certain contracts in which the cash consideration that the Partnership receives for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as the Partnership will perform a similar level of service for the entire term. Therefore, the revenue recognized in the current reporting period is less than the cash received. However, the Partnerships chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the three months ended September 30, 2012, approximately $0.2 million and $1.4 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. In comparison, for the three months ended September 30, 2011, approximately $0.2 million and $2.3 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Beginning in 2015, the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.
(2) 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 Southwest and Gulf Coast segments, respectively.
Nine months ended September 30, 2012:
|
|
Southwest |
|
Northeast |
|
Liberty |
|
Gulf Coast |
|
Total |
| |||||
Segment revenue |
|
$ |
585,343 |
|
$ |
168,956 |
|
$ |
213,906 |
|
$ |
66,703 |
|
$ |
1,034,908 |
|
Purchased product costs |
|
288,137 |
|
49,662 |
|
48,856 |
|
|
|
386,655 |
| |||||
Net operating margin |
|
297,206 |
|
119,294 |
|
165,050 |
|
66,703 |
|
648,253 |
| |||||
Facility expenses |
|
66,553 |
|
17,577 |
|
46,135 |
|
28,173 |
|
158,438 |
| |||||
Portion of operating income (loss) attributable to non-controlling interests |
|
4,579 |
|
|
|
(740 |
) |
|
|
3,839 |
| |||||
Operating income before items not allocated to segments |
|
$ |
226,074 |
|
$ |
101,717 |
|
$ |
119,655 |
|
$ |
38,530 |
|
$ |
485,976 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Capital expenditures |
|
$ |
134,630 |
|
$ |
70,206 |
|
$ |
1,019,374 |
|
$ |
11,744 |
|
$ |
1,235,954 |
|
Capital expenditures not allocated to segments |
|
|
|
|
|
|
|
|
|
4,912 |
| |||||
Total capital expenditures |
|
|
|
|
|
|
|
|
|
$ |
1,240,866 |
|
Nine months ended September 30, 2011:
|
|
Southwest |
|
Northeast |
|
Liberty |
|
Gulf Coast |
|
Total |
| |||||
Segment revenue |
|
$ |
679,347 |
|
$ |
201,687 |
|
$ |
168,142 |
|
$ |
73,310 |
|
$ |
1,122,486 |
|
Purchased product costs |
|
373,251 |
|
72,527 |
|
51,715 |
|
|
|
497,493 |
| |||||
Net operating margin |
|
306,096 |
|
129,160 |
|
116,427 |
|
73,310 |
|
624,993 |
| |||||
Facility expenses |
|
62,055 |
|
19,402 |
|
22,875 |
|
27,100 |
|
131,432 |
| |||||
Portion of operating income attributable to non-controlling interests |
|
3,745 |
|
|
|
45,782 |
|
|
|
49,527 |
| |||||
Operating income before items not allocated to segments |
|
$ |
240,296 |
|
$ |
109,758 |
|
$ |
47,770 |
|
$ |
46,210 |
|
$ |
444,034 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Capital expenditures |
|
$ |
80,069 |
|
$ |
17,768 |
|
$ |
256,877 |
|
$ |
1,282 |
|
$ |
355,996 |
|
Capital expenditures not allocated to segments |
|
|
|
|
|
|
|
|
|
3,930 |
| |||||
Total capital expenditures |
|
|
|
|
|
|
|
|
|
$ |
359,926 |
|
The following is a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to income before provision for income tax for the nine months ended September 30, 2012 and 2011 (in thousands):
|
|
Nine months ended September 30, |
| ||||
|
|
2012 |
|
2011 |
| ||
|
|
|
|
|
| ||
Total segment revenue |
|
$ |
1,034,908 |
|
$ |
1,122,486 |
|
Derivative gain not allocated to segments |
|
50,952 |
|
61,854 |
| ||
Revenue deferral adjustment (1) |
|
(5,604 |
) |
(12,854 |
) | ||
Total revenue |
|
$ |
1,080,256 |
|
$ |
1,171,486 |
|
|
|
|
|
|
| ||
Operating income before items not allocated to segments |
|
$ |
485,976 |
|
$ |
444,034 |
|
Portion of operating income attributable to non-controlling interests |
|
3,839 |
|
49,527 |
| ||
Derivative gain not allocated to segments |
|
70,952 |
|
46,859 |
| ||
Revenue deferral adjustment (1) |
|
(5,604 |
) |
(12,854 |
) | ||
Compensation expense included in facility expenses not allocated to segments |
|
(826 |
) |
(1,491 |
) | ||
Facility expenses adjustments (2) |
|
8,593 |
|
8,565 |
| ||
Selling, general and administrative expenses |
|
(69,025 |
) |
(60,454 |
) | ||
Depreciation |
|
(132,199 |
) |
(110,280 |
) | ||
Amortization of intangible assets |
|
(38,280 |
) |
(32,632 |
) | ||
Loss on disposal of property, plant and equipment |
|
(2,983 |
) |
(4,619 |
) | ||
Accretion of asset retirement obligations |
|
(540 |
) |
(934 |
) | ||
Income from operations |
|
319,903 |
|
325,721 |
| ||
|
|
|
|
|
| ||
Earnings (loss) from unconsolidated affiliate |
|
788 |
|
(1,262 |
) | ||
Interest income |
|
295 |
|
214 |
| ||
Interest expense |
|
(86,855 |
) |
(83,036 |
) | ||
Amortization of deferred financing costs and discount (a component of interest expense) |
|
(3,943 |
) |
(3,873 |
) | ||
Loss on redemption of debt |
|
|
|
(43,461 |
) | ||
Miscellaneous income, net |
|
63 |
|
127 |
| ||
Income before provision for income tax |
|
$ |
230,251 |
|
$ |
194,430 |
|
(1) Amount relates to certain contracts in which the cash consideration that the Partnership receives for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as the Partnership will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the Partnerships chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore the impact of the revenue deferrals is excluded for segment reporting purposes. For the nine months ended September 30, 2012, approximately $0.6 million and $5.0 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. For the nine months ended September 30, 2011, approximately $6.9 million and $5.9 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Beginning in 2015, the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.
(2) 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 Southwest and Gulf Coast segments, respectively.
The tables below present information about segment assets as of September 30, 2012 and December 31, 2011 (in thousands):
|
|
September 30, 2012 |
|
December 31, 2011 |
| ||
Southwest |
|
$ |
1,716,013 |
|
$ |
1,701,919 |
|
Northeast |
|
573,832 |
|
533,591 |
| ||
Liberty |
|
2,894,407 |
|
1,114,654 |
| ||
Gulf Coast |
|
538,732 |
|
553,043 |
| ||
Total segment assets |
|
5,722,984 |
|
3,903,207 |
| ||
Assets not allocated to segments: |
|
|
|
|
| ||
Certain cash and cash equivalents |
|
365,957 |
|
66,212 |
| ||
Fair value of derivatives |
|
33,189 |
|
24,790 |
| ||
Investment in unconsolidated affiliate |
|
26,441 |
|
27,853 |
| ||
Other (1) |
|
88,572 |
|
48,363 |
| ||
Total assets |
|
$ |
6,237,143 |
|
$ |
4,070,425 |
|
(1) Includes corporate fixed assets, deferred financing costs, income tax receivable, receivables and other corporate assets not allocated to segments.
15. Supplemental Condensed Consolidating Financial Information
The Partnership has no operations independent of its subsidiaries. As of September 30, 2012, the Partnerships obligations under the outstanding Senior Notes (see Note 9) were fully, jointly and severally guaranteed, by all of its wholly-owned subsidiaries other than MarkWest Liberty Midstream and its subsidiaries. The guarantees are unconditional except for certain customary circumstances in which a subsidiary would be released from the guarantee under the indentures. MarkWest Liberty Midstream, MarkWest Utica EMG and MarkWest Pioneer, together with certain of the Partnerships other subsidiaries that do not guarantee the outstanding Senior Notes, have significant assets and operations in the aggregate. For the purpose of the following financial information, the Partnerships 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 Parents financial information. Condensed consolidating financial information for the Partnership, its combined guarantor subsidiaries and combined non-guarantor subsidiaries as of September 30, 2012 and December 31, 2011 and for the three and nine months ended September 30, 2012 and 2011 is as follows (in thousands):
Condensed Consolidating Balance Sheets
|
|
As of September 30, 2012 |
| |||||||||||||
|
|
Parent |
|
Guarantor |
|
Non- |
|
Consolidating |
|
Consolidated |
| |||||
ASSETS |
|
|
|
|
|
|
|
|
|
|
| |||||
Current assets: |
|
|
|
|
|
|
|
|
|
|
| |||||
Cash and cash equivalents |
|
$ |
300,013 |
|
$ |
111,456 |
|
$ |
3,595 |
|
$ |
|
|
$ |
415,064 |
|
Restricted cash |
|
|
|
|
|
25,000 |
|
|
|
25,000 |
| |||||
Receivables and other current assets |
|
4,087 |
|
194,248 |
|
62,687 |
|
|
|
261,022 |
| |||||
Intercompany receivables |
|
1,196,163 |
|
7,686 |
|
20,908 |
|
(1,224,757 |
) |
|
| |||||
Fair value of derivative instruments |
|
|
|
14,703 |
|
1,063 |
|
|
|
15,766 |
| |||||
Total current assets |
|
1,500,263 |
|
328,093 |
|
113,253 |
|
(1,224,757 |
) |
716,852 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total property, plant and equipment, net |
|
3,672 |
|
1,981,143 |
|
2,539,813 |
|
(118,089 |
) |
4,406,539 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Other long-term assets: |
|
|
|
|
|
|
|
|
|
|
| |||||
Investment in unconsolidated affiliate |
|
|
|
26,441 |
|
|
|
|
|
26,441 |
| |||||
Investment in consolidated affiliates |
|
3,308,731 |
|
2,310,456 |
|
|
|
(5,619,187 |
) |
|
| |||||
Intangibles, net of accumulated amortization |
|
|
|
570,297 |
|
299,899 |
|
|
|
870,196 |
| |||||
Fair value of derivative instruments |
|
|
|
17,061 |
|
362 |
|
|
|
17,423 |
| |||||
Intercompany notes receivable |
|
225,000 |
|
|
|
|
|
(225,000 |
) |
|
| |||||
Other long-term assets |
|
51,791 |
|
70,116 |
|
77,785 |
|
|
|
199,692 |
| |||||
Total assets |
|
$ |
5,089,457 |
|
$ |
5,303,607 |
|
$ |
3,031,112 |
|
$ |
(7,187,033 |
) |
$ |
6,237,143 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
|
|
| |||||
Current liabilities: |
|
|
|
|
|
|
|
|
|
|
| |||||
Intercompany payables |
|
$ |
4,215 |
|
$ |
1,199,639 |
|
$ |
20,903 |
|
$ |
(1,224,757 |
) |
$ |
|
|
Fair value of derivative instruments |
|
|
|
32,324 |
|
499 |
|
|
|
32,823 |
| |||||
Other current liabilities |
|
43,798 |
|
185,656 |
|
471,911 |
|
|
|
701,365 |
| |||||
Total current liabilities |
|
48,013 |
|
1,417,619 |
|
493,313 |
|
(1,224,757 |
) |
734,188 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Deferred income taxes |
|
1,176 |
|
198,398 |
|
|
|
|
|
199,574 |
| |||||
Long-term intercompany financing payable |
|
|
|
225,000 |
|
101,923 |
|
(326,923 |
) |
|
| |||||
Fair value of derivative instruments |
|
|
|
29,715 |
|
|
|
|
|
29,715 |
| |||||
Long-term debt, net of discounts |
|
2,522,854 |
|
|
|
|
|
|
|
2,522,854 |
| |||||
Other long-term liabilities |
|
3,045 |
|
124,144 |
|
2,683 |
|
|
|
129,872 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Equity: |
|
|
|
|
|
|
|
|
|
|
| |||||
Common units |
|
1,761,838 |
|
3,308,731 |
|
2,433,193 |
|
(5,758,090 |
) |
1,745,672 |
| |||||
Class B units |
|
752,531 |
|
|
|
|
|
|
|
752,531 |
| |||||
Non-controlling interest in consolidated subsidiaries |
|
|
|
|
|
|
|
122,737 |
|
122,737 |
| |||||
Total equity |
|
2,514,369 |
|
3,308,731 |
|
2,433,193 |
|
(5,635,353 |
) |
2,620,940 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Total liabilities and equity |
|
$ |
5,089,457 |
|
$ |
5,303,607 |
|
$ |
3,031,112 |
|
$ |
(7,187,033 |
) |
$ |
6,237,143 |
|
|
|
As of December 31, 2011 |
| |||||||||||||
|
|
Parent |
|
Guarantor |
|
Non- |
|
Consolidating |
|
Consolidated |
| |||||
ASSETS |
|
|
|
|
|
|
|
|
|
|
| |||||
Current assets: |
|
|
|
|
|
|
|
|
|
|
| |||||
Cash and cash equivalents |
|
$ |
22 |
|
$ |
99,580 |
|
$ |
17,414 |
|
$ |
|
|
$ |
117,016 |
|
Restricted cash |
|
|
|
|
|
26,193 |
|
|
|
26,193 |
| |||||
Receivables and other current assets |
|
7,097 |
|
232,010 |
|
55,098 |
|
(5 |
) |
294,200 |
| |||||
Intercompany receivables |
|
19,981 |
|
40,519 |
|
22,193 |
|
(82,693 |
) |
|
| |||||
Fair value of derivative instruments |
|
|
|
8,015 |
|
683 |
|
|
|
8,698 |
| |||||
Total current assets |
|
27,100 |
|
380,124 |
|
121,581 |
|
(82,698 |
) |
446,107 |
| |||||
Total property, plant and equipment, net |
|
4,012 |
|
1,714,857 |
|
1,163,226 |
|
(17,788 |
) |
2,864,307 |
| |||||
Other long-term assets: |
|
|
|
|
|
|
|
|
|
|
| |||||
Investment in unconsolidated affiliate |
|
|
|
27,853 |
|
|
|
|
|
27,853 |
| |||||
Investment in consolidated affiliates |
|
3,071,124 |
|
1,097,350 |
|
|
|
(4,168,474 |
) |
|
| |||||
Intangibles, net of accumulated amortization |
|
|
|
603,224 |
|
543 |
|
|
|
603,767 |
| |||||
Fair value of derivative instruments |
|
|
|
16,092 |
|
|
|
|
|
16,092 |
| |||||
Intercompany notes receivable |
|
235,700 |
|
|
|
|
|
(235,700 |
) |
|
| |||||
Other long-term assets |
|
41,492 |
|
70,434 |
|
373 |
|
|
|
112,299 |
| |||||
Total assets |
|
$ |
3,379,428 |
|
$ |
3,909,934 |
|
$ |
1,285,723 |
|
$ |
(4,504,660 |
) |
$ |
4,070,425 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
|
|
| |||||
Current liabilities: |
|
|
|
|
|
|
|
|
|
|
| |||||
Intercompany payables |
|
$ |
40,503 |
|
$ |
40,374 |
|
$ |
1,816 |
|
$ |
(82,693 |
) |
$ |
|
|
Fair value of derivative instruments |
|
|
|
90,551 |
|
|
|
|
|
90,551 |
| |||||
Other current liabilities |
|
38,775 |
|
219,622 |
|
92,930 |
|
(5 |
) |
351,322 |
| |||||
Total current liabilities |
|
79,278 |
|
350,547 |
|
94,746 |
|
(82,698 |
) |
441,873 |
| |||||
Deferred income taxes |
|
1,228 |
|
92,436 |
|
|
|
|
|
93,664 |
| |||||
Long-term intercompany financing payable |
|
|
|
212,700 |
|
23,000 |
|
(235,700 |
) |
|
| |||||
Fair value of derivative instruments |
|
|
|
65,403 |
|
|
|
|
|
65,403 |
| |||||
Long-term debt, net of discounts |
|
1,846,062 |
|
|
|
|
|
|
|
1,846,062 |
| |||||
Other long-term liabilities |
|
3,232 |
|
117,724 |
|
400 |
|
|
|
121,356 |
| |||||
Equity: |
|
|
|
|
|
|
|
|
|
|
| |||||
Common Units |
|
697,097 |
|
3,071,124 |
|
1,167,577 |
|
(4,256,489 |
) |
679,309 |
| |||||
Class B Units |
|
752,531 |
|
|
|
|
|
|
|
752,531 |
| |||||
Non-controlling interest in consolidated subsidiaries |
|
|
|
|
|
|
|
70,227 |
|
70,227 |
| |||||
Total equity |
|
1,449,628 |
|
3,071,124 |
|
1,167,577 |
|
(4,186,262 |
) |
1,502,067 |
| |||||
Total liabilities and equity |
|
$ |
3,379,428 |
|
$ |
3,909,934 |
|
$ |
1,285,723 |
|
$ |
(4,504,660 |
) |
$ |
4,070,425 |
|
Condensed Consolidating Statements of Operations
|
|
Three Months Ended September 30, 2012 |
| |||||||||||||
|
|
Parent |
|
Guarantor |
|
Non- |
|
Consolidating |
|
Consolidated |
| |||||
Total revenue |
|
$ |
|
|
$ |
205,629 |
|
$ |
81,584 |
|
$ |
(3,476 |
) |
$ |
283,737 |
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
| |||||
Purchased product costs |
|
|
|
114,685 |
|
16,327 |
|
|
|
131,012 |
| |||||
Facility expenses |
|
|
|
36,437 |
|
21,061 |
|
(177 |
) |
57,321 |
| |||||
Selling, general and administrative expenses |
|
10,241 |
|
5,633 |
|
7,342 |
|
(1,294 |
) |
21,922 |
| |||||
Depreciation and amortization |
|
146 |
|
41,593 |
|
22,963 |
|
(1,578 |
) |
63,124 |
| |||||
Other operating expenses |
|
|
|
488 |
|
308 |
|
|
|
796 |
| |||||
Total operating expenses |
|
10,387 |
|
198,836 |
|
68,001 |
|
(3,049 |
) |
274,175 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
(Loss) income from operations |
|
(10,387 |
) |
6,793 |
|
13,583 |
|
(427 |
) |
9,562 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Earnings from consolidated affiliates |
|
20,122 |
|
10,848 |
|
|
|
(30,970 |
) |
|
| |||||
Other expense, net |
|
(24,637 |
) |
(4,908 |
) |
(3,151 |
) |
958 |
|
(31,738 |
) | |||||
(Loss) income before provision for income tax |
|
(14,902 |
) |
12,733 |
|
10,432 |
|
(30,439 |
) |
(22,176 |
) | |||||
Provision for income tax expense |
|
(31 |
) |
(7,389 |
) |
|
|
|
|
(7,420 |
) | |||||
Net (loss) income |
|
(14,871 |
) |
20,122 |
|
10,432 |
|
(30,439 |
) |
(14,756 |
) | |||||
Net income attributable to non-controlling interest |
|
|
|
|
|
|
|
416 |
|
416 |
| |||||
Net (loss) income attributable to the Partnerships unitholders |
|
$ |
(14,871 |
) |
$ |
20,122 |
|
$ |
10,432 |
|
$ |
(30,023 |
) |
$ |
(14,340 |
) |
|
|
Three Months Ended September 30, 2011 |
| |||||||||||||
|
|
Parent |
|
Guarantor |
|
Non- |
|
Consolidating |
|
Consolidated |
| |||||
Total revenue |
|
$ |
|
|
$ |
425,142 |
|
$ |
82,684 |
|
$ |
|
|
$ |
507,826 |
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
| |||||
Purchased product costs |
|
|
|
155,612 |
|
32,398 |
|
|
|
188,010 |
| |||||
Facility expenses |
|
|
|
31,351 |
|
10,263 |
|
(165 |
) |
41,449 |
| |||||
Selling, general and administrative expenses |
|
11,270 |
|
7,768 |
|
2,421 |
|
(1,297 |
) |
20,162 |
| |||||
Depreciation and amortization |
|
182 |
|
38,391 |
|
11,314 |
|
(187 |
) |
49,700 |
| |||||
Other operating expenses |
|
|
|
1,069 |
|
(365 |
) |
|
|
704 |
| |||||
Total operating expenses |
|
11,452 |
|
234,191 |
|
56,031 |
|
(1,649 |
) |
300,025 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
(Loss) income from operations |
|
(11,452 |
) |
190,951 |
|
26,653 |
|
1,649 |
|
207,801 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Earnings from consolidated affiliates |
|
174,458 |
|
13,479 |
|
|
|
(187,937 |
) |
|
| |||||
Loss on redemption of debt |
|
(133 |
) |
|
|
|
|
|
|
(133 |
) | |||||
Other expense, net |
|
(20,609 |
) |
(4,849 |
) |
(32 |
) |
(2,860 |
) |
(28,350 |
) | |||||
Income before provision for income tax |
|
142,264 |
|
199,581 |
|
26,621 |
|
(189,148 |
) |
179,318 |
| |||||
Provision for income tax expense |
|
741 |
|
25,123 |
|
|
|
|
|
25,864 |
| |||||
Net income |
|
141,523 |
|
174,458 |
|
26,621 |
|
(189,148 |
) |
153,454 |
| |||||
Net income attributable to non-controlling interest |
|
|
|
|
|
|
|
(13,142 |
) |
(13,142 |
) | |||||
Net income attributable to the Partnerships unitholders |
|
$ |
141,523 |
|
$ |
174,458 |
|
$ |
26,621 |
|
$ |
(202,290 |
) |
$ |
140,312 |
|
|
|
Nine Months Ended September 30, 2012 |
| |||||||||||||
|
|
Parent |
|
Guarantor |
|
Non- |
|
Consolidating |
|
Consolidated |
| |||||
Total revenue |
|
$ |
|
|
$ |
858,227 |
|
$ |
227,980 |
|
$ |
(5,951 |
) |
$ |
1,080,256 |
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
| |||||
Purchased product costs |
|
|
|
316,327 |
|
49,192 |
|
|
|
365,519 |
| |||||
Facility expenses |
|
|
|
103,484 |
|
49,009 |
|
(686 |
) |
151,807 |
| |||||
Selling, general and administrative expenses |
|
37,197 |
|
13,333 |
|
21,851 |
|
(3,356 |
) |
69,025 |
| |||||
Depreciation and amortization |
|
458 |
|
121,520 |
|
51,446 |
|
(2,945 |
) |
170,479 |
| |||||
Other operating expenses |
|
|
|
2,227 |
|
1,296 |
|
|
|
3,523 |
| |||||
Total operating expenses |
|
37,655 |
|
556,891 |
|
172,794 |
|
(6,987 |
) |
760,353 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
(Loss) income from operations |
|
(37,655 |
) |
301,336 |
|
55,186 |
|
1,036 |
|
319,903 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Earnings from consolidated affiliates |
|
294,036 |
|
49,600 |
|
|
|
(343,636 |
) |
|
| |||||
Other expense, net |
|
(68,681 |
) |
(16,036 |
) |
(5,521 |
) |
586 |
|
(89,652 |
) | |||||
Income before provision for income tax |
|
187,700 |
|
334,900 |
|
49,665 |
|
(342,014 |
) |
230,251 |
| |||||
Provision for income tax expense |
|
734 |
|
40,864 |
|
|
|
|
|
41,598 |
| |||||
Net income |
|
186,966 |
|
294,036 |
|
49,665 |
|
(342,014 |
) |
188,653 |
| |||||
Net income attributable to non-controlling interest |
|
|
|
|
|
|
|
(65 |
) |
(65 |
) | |||||
Net income attributable to the Partnerships unitholders |
|
$ |
186,966 |
|
$ |
294,036 |
|
$ |
49,665 |
|
$ |
(342,079 |
) |
$ |
188,588 |
|
|
|
Nine Months Ended September 30, 2011 |
| |||||||||||||
|
|
Parent |
|
Guarantor |
|
Non- |
|
Consolidating |
|
Consolidated |
| |||||
Total revenue |
|
$ |
|
|
$ |
991,993 |
|
$ |
179,493 |
|
$ |
|
|
$ |
1,171,486 |
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
| |||||
Purchased product costs |
|
|
|
463,459 |
|
51,900 |
|
|
|
515,359 |
| |||||
Facility expenses |
|
|
|
95,701 |
|
26,285 |
|
(499 |
) |
121,487 |
| |||||
Selling, general and administrative expenses |
|
35,348 |
|
23,139 |
|
6,390 |
|
(4,423 |
) |
60,454 |
| |||||
Depreciation and amortization |
|
538 |
|
112,868 |
|
30,010 |
|
(504 |
) |
142,912 |
| |||||
Other operating expenses |
|
673 |
|
4,895 |
|
(15 |
) |
|
|
5,553 |
| |||||
Total operating expenses |
|
36,559 |
|
700,062 |
|
114,570 |
|
(5,426 |
) |
845,765 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
(Loss) income from operations |
|
(36,559 |
) |
291,931 |
|
64,923 |
|
5,426 |
|
325,721 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Earnings from consolidated affiliates |
|
287,377 |
|
31,623 |
|
|
|
(319,000 |
) |
|
| |||||
Loss on redemption of debt |
|
(43,461 |
) |
|
|
|
|
|
|
(43,461 |
) | |||||
Other expense, net |
|
(67,574 |
) |
(10,583 |
) |
(92 |
) |
(9,581 |
) |
(87,830 |
) | |||||
Income before provision for income tax |
|
139,783 |
|
312,971 |
|
64,831 |
|
(323,155 |
) |
194,430 |
| |||||
Provision for income tax expense |
|
848 |
|
25,594 |
|
|
|
|
|
26,442 |
| |||||
Net (loss) income |
|
138,935 |
|
287,377 |
|
64,831 |
|
(323,155 |
) |
167,988 |
| |||||
Net income attributable to non-controlling interest |
|
|
|
|
|
|
|
(33,208 |
) |
(33,208 |
) | |||||
Net income attributable to the Partnerships unitholders |
|
$ |
138,935 |
|
$ |
287,377 |
|
$ |
64,831 |
|
$ |
(356,363 |
) |
$ |
134,780 |
|
Condensed Consolidating Statements of Cash Flows
|
|
Nine Months Ended September 30, 2012 |
| |||||||||||||
|
|
Parent |
|
Guarantor |
|
Non- |
|
Consolidating |
|
Consolidated |
| |||||
Net cash (used in) provided by operating activities |
|
$ |
(89,558 |
) |
$ |
301,270 |
|
$ |
179,334 |
|
$ |
(1,328 |
) |
$ |
389,718 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
| |||||
Restricted cash |
|
|
|
|
|
1,003 |
|
|
|
1,003 |
| |||||
Capital expenditures |
|
(120 |
) |
(236,153 |
) |
(1,006,431 |
) |
1,838 |
|
(1,240,866 |
) | |||||
Equity investments |
|
(42,120 |
) |
(1,367,484 |
) |
|
|
1,409,604 |
|
|
| |||||
Acquisition of business, net of cash acquired |
|
|
|
|
|
(506,797 |
) |
|
|
(506,797 |
) | |||||
Distributions from consolidated affiliates |
|
48,973 |
|
100,238 |
|
|
|
(149,211 |
) |
|
| |||||
Investment in intercompany notes, net |
|
(12,300 |
) |
|
|
|
|
12,300 |
|
|
| |||||
Proceeds from disposal of property, plant and equipment |
|
|
|
1,718 |
|
84 |
|
(1,213 |
) |
589 |
| |||||
Net cash flows provided by (used in) investing activities |
|
(5,567 |
) |
(1,501,681 |
) |
(1,512,141 |
) |
1,273,318 |
|
(1,746,071 |
) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
| |||||
Proceeds from public equity offerings, net |
|
1,191,066 |
|
|
|
|
|
|
|
1,191,066 |
| |||||
Proceeds from Credit Facility |
|
511,100 |
|
|
|
|
|
|
|
511,100 |
| |||||
Payments of Credit Facility |
|
(577,100 |
) |
|
|
|
|
|
|
(577,100 |
) | |||||
Proceeds from long-term debt |
|
742,613 |
|
|
|
|
|
|
|
742,613 |
| |||||
Proceeds (Payments) related to intercompany financing, net |
|
|
|
12,300 |
|
(703 |
) |
(11,597 |
) |
|
| |||||
Payments for debt issue costs and deferred financing costs |
|
(14,184 |
) |
|
|
|
|
|
|
(14,184 |
) | |||||
Contributions from parent and affiliates |
|
|
|
42,120 |
|
1,367,484 |
|
(1,409,604 |
) |
|
| |||||
Contribution from non-controlling interest |
|
|
|
|
|
56,940 |
|
|
|
56,940 |
| |||||
Share-based payment activity |
|
(8,061 |
) |
2,216 |
|
|
|
|
|
(5,845 |
) | |||||
Payment of distributions |
|
(244,169 |
) |
(48,973 |
) |
(104,733 |
) |
149,211 |
|
(248,664 |
) | |||||
Payments of SMR liability |
|
|
|
(1,525 |
) |
|
|
|
|
(1,525 |
) | |||||
Intercompany advances, net |
|
(1,206,149 |
) |
1,206,149 |
|
|
|
|
|
|
| |||||
Net cash flows provided by financing activities |
|
395,116 |
|
1,212,287 |
|
1,318,988 |
|
(1,271,990 |
) |
1,654,401 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Net increase (decrease) in cash |
|
299,991 |
|
11,876 |
|
(13,819 |
) |
|
|
298,048 |
| |||||
Cash and cash equivalents at beginning of year |
|
22 |
|
99,580 |
|
17,414 |
|
|
|
117,016 |
| |||||
Cash and cash equivalents at end of period |
|
$ |
300,013 |
|
$ |
111,456 |
|
$ |
3,595 |
|
$ |
|
|
$ |
415,064 |
|
|
|
Nine Months Ended September 30, 2011 |
| |||||||||||||
|
|
Parent |
|
Guarantor |
|
Non- |
|
Consolidating |
|
Consolidated |
| |||||
Net cash (used in) provided by operating activities |
|
$ |
(89,044 |
) |
$ |
303,401 |
|
$ |
121,551 |
|
$ |
(4,659 |
) |
$ |
331,249 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
| |||||
Capital expenditures |
|
(785 |
) |
(100,155 |
) |
(264,996 |
) |
6,010 |
|
(359,926 |
) | |||||
Acquisition of business |
|
|
|
(230,728 |
) |
|
|
|
|
(230,728 |
) | |||||
Equity investments |
|
(34,246 |
) |
(204,428 |
) |
|
|
238,674 |
|
|
| |||||
Distributions from consolidated affiliates |
|
37,978 |
|
50,019 |
|
|
|
(87,997 |
) |
|
| |||||
Investment in intercompany notes, net |
|
(17,600 |
) |
|
|
|
|
17,600 |
|
|
| |||||
Proceeds from disposal of property, plant and equipment |
|
|
|
365 |
|
3,954 |
|
(1,351 |
) |
2,968 |
| |||||
Net cash flows used in investing activities |
|
(14,653 |
) |
(484,927 |
) |
(261,042 |
) |
172,936 |
|
(587,686 |
) | |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
| |||||
Proceeds from public equity offering, net |
|
323,492 |
|
|
|
|
|
|
|
323,492 |
| |||||
Proceeds from Credit Facility |
|
1,074,700 |
|
|
|
|
|
|
|
1,074,700 |
| |||||
Payments of Credit Facility |
|
(929,600 |
) |
|
|
|
|
|
|
(929,600 |
) | |||||
Proceeds from long-term debt |
|
499,000 |
|
|
|
|
|
|
|
499,000 |
| |||||
Payments of long-term debt |
|
(440,638 |
) |
|
|
|
|
|
|
(440,638 |
) | |||||
Payments of premiums on redemption of long-term debt |
|
(39,642 |
) |
|
|
|
|
|
|
(39,642 |
) | |||||
(Payments) proceeds related to intercompany financing, net |
|
|
|
(5,400 |
) |
23,000 |
|
(17,600 |
) |
|
| |||||
Payments for debt issuance costs, deferred financing costs and registration costs |
|
(7,795 |
) |
|
|
|
|
|
|
(7,795 |
) | |||||
Contributions from parent and affiliates |
|
|
|
34,246 |
|
204,428 |
|
(238,674 |
) |
|
| |||||
Contributions from non-controlling interest |
|
|
|
|
|
80,332 |
|
|
|
80,332 |
| |||||
Share-based payment activity |
|
(6,354 |
) |
1,089 |
|
|
|
|
|
(5,265 |
) | |||||
Payment of distributions |
|
(155,931 |
) |
(37,978 |
) |
(99,118 |
) |
87,997 |
|
(205,030 |
) | |||||
Payments of SMR liability |
|
|
|
(1,390 |
) |
|
|
|
|
(1,390 |
) | |||||
Intercompany advances, net |
|
(213,532 |
) |
213,532 |
|
|
|
|
|
|
| |||||
Net cash flows provided by financing activities |
|
103,700 |
|
204,099 |
|
208,642 |
|
(168,277 |
) |
348,164 |
| |||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Net increase in cash |
|
3 |
|
22,573 |
|
69,151 |
|
|
|
91,727 |
| |||||
Cash and cash equivalents at beginning of year |
|
|
|
63,850 |
|
3,600 |
|
|
|
67,450 |
| |||||
Cash and cash equivalents at end of period |
|
$ |
3 |
|
$ |
86,423 |
|
$ |
72,751 |
|
$ |
|
|
$ |
159,177 |
|
16. Supplemental Cash Flow Information
The following table provides information regarding supplemental cash flow information (in thousands):
|
|
Nine months ended September 30, |
| ||||
|
|
2012 |
|
2011 |
| ||
Supplemental disclosures of cash flow information: |
|
|
|
|
| ||
Cash paid for interest, net of amounts capitalized |
|
$ |
73,624 |
|
$ |
76,876 |
|
Cash paid for income taxes, net |
|
18,925 |
|
5,051 |
| ||
|
|
|
|
|
| ||
Supplemental schedule of non-cash investing and financing activities: |
|
|
|
|
| ||
Accrued property, plant and equipment |
|
$ |
389,601 |
|
$ |
85,666 |
|
Interest capitalized on construction in progress |
|
16,353 |
|
571 |
| ||
Issuance of common units for vesting of share-based payment awards |
|
2,506 |
|
5,412 |
|
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
Forward-Looking Statements
Managements 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 Annual Report on Form 10-K for the year ended December 31, 2011. 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 and fractionator in the Appalachian region.
Significant Financial and Other Highlights
Significant financial and other highlights for the three months ended September 30, 2012 are listed below. Refer to Results of Operations and Liquidity and Capital Resources for further details.
· Total segment operating income before items not allocated to segments (a non-GAAP financial measure, see below) decreased approximately $2.3 million, or 2%, for the three months ended September 30, 2012 compared to the same period in 2011. The decrease is due primarily to a decline in NGL prices which was partially offset by our acquisition of M&R MWE Liberty, L.L.C.s (M&R) interest in MarkWest Liberty Midstream and over 20% increase in total processed volumes, primarily due to our expanding operations in the Liberty and Southwest segments.
· Realized losses from the settlement of our derivative instruments were $8.4 million for the three months ended September 30, 2012 compared to $15.8 million for the same period in 2011. Changes in the correlation between the price of NGLs and price of crude oil has reduced the effectiveness of our crude oil derivative positions that are used as a proxy contract for managing NGL price risk.
· In July 2012, we announced a long-term fee-based agreement with XTO Energy Inc. (XTO) to extend our NGL gathering pipeline in northwest Pennsylvania to XTOs processing plant in Butler County, Pennsylvania, which is expected to commence operations in late 2012. The NGLs will be transported by truck until the pipeline is complete in late 2013.
· In August 2012, we received net proceeds of approximately $338 million from a public offering of approximately 6.9 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters over-allotment option.
· In August 2012, we received net proceeds of approximately $731 million from a public offering of $750 million in aggregate principal amount of 5.5% senior unsecured notes due in 2023, which were issued at 99.015% of par.
· In September 2012, we signed a 10-year agreement to become a firm shipper on the Mariner East (Mariner East) pipeline subject to final regulatory approvals. Mariner East is currently designed to transport ethane and propane sourced at our Houston, Pennsylvania processing and fractionation complex (Houston Complex) to Sunoco Inc.s (Sunoco) Marcus Hook facility near Philadelphia, Pennsylvania. Once delivered, the ethane-propane mix will be re-fractionated into purity products for sale into domestic and international markets.
· In October 2012, we commenced operations of the 200 MMcf/d Sherwood I processing facility and associated gathering and compression in Doddridge County, West Virginia. These assets are supported by a long-term, fee-based agreement with Antero Resources.
· In November 2012, we announced plans to expand the processing capacity at our Mobley complex in Wetzel County, West Virginia by 200 MMcf/d. This expansion is supported by an existing long-term, fee-based agreement with EQT Corporation and is expected to be completed in the fourth quarter of 2013.
· In November 2012, MarkWest Utica EMG announced the execution of long-term fee-based agreements with Antero Resources to provide gas processing, fractionation and marketing services in Noble County, Ohio. Services under these agreements will be provided using the assets currently under construction for our Utica Shale operations as described below in Results of Operations-Segment Reporting-Utica.
Non-GAAP Measures
In evaluating our financial performance, management utilizes the segment performance measures, segment revenues and operating income before items not allocated to segments. These financial measures are presented in Note 14 to the accompanying condensed consolidated financial statements and are considered non-GAAP financial measures when presented outside of the notes to the condensed consolidated financial statements. The use of these measures allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources. See Note 14 to the accompanying condensed consolidated financial statements for the reconciliations of segment revenue and operating income before items not allocated to segments to the respective most comparable GAAP measure.
Management evaluates contract performance on the basis of net operating margin (a non-GAAP financial measure). These adjustments have been made for the purpose of enhancing the understanding by both management and investors of the underlying baseline operating performance of our contractual arrangements, which management uses to evaluate our financial performance for purposes of planning and forecasting.
The following is a reconciliation to Income (loss) from operations, the most comparable GAAP financial measure to net operating margin (in thousands):
|
|
Three months ended September 30, |
|
Nine months ended September 30, |
| ||||||||
|
|
2012 |
|
2011 |
|
2012 |
|
2011 |
| ||||
Segment revenue |
|
$ |
321,772 |
|
$ |
403,372 |
|
$ |
1,034,908 |
|
$ |
1,122,486 |
|
Purchased product costs |
|
(119,369 |
) |
(189,284 |
) |
(386,655 |
) |
(497,493 |
) | ||||
Net operating margin |
|
202,403 |
|
214,088 |
|
648,253 |
|
624,993 |
| ||||
Facility expenses |
|
(53,293 |
) |
(44,236 |
) |
(150,671 |
) |
(124,358 |
) | ||||
Derivative gain (loss) |
|
(52,071 |
) |
111,004 |
|
70,952 |
|
46,859 |
| ||||
Revenue deferral adjustment |
|
(1,635 |
) |
(2,489 |
) |
(5,604 |
) |
(12,854 |
) | ||||
Selling, general and administrative expenses |
|
(21,922 |
) |
(20,162 |
) |
(69,025 |
) |
(60,454 |
) | ||||
Depreciation |
|
(48,136 |
) |
(38,715 |
) |
(132,199 |
) |
(110,280 |
) | ||||
Amortization of intangible assets |
|
(14,988 |
) |
(10,985 |
) |
(38,280 |
) |
(32,632 |
) | ||||
Loss on disposal of property, plant and equipment |
|
(655 |
) |
(147 |
) |
(2,983 |
) |
(4,619 |
) | ||||
Accretion of asset retirement obligations |
|
(141 |
) |
(557 |
) |
(540 |
) |
(934 |
) | ||||
Income from operations |
|
$ |
9,562 |
|
$ |
207,801 |
|
$ |
319,903 |
|
$ |
325,721 |
|
Segment revenues, operating income before items not allocated to segments and net operating margin (collectively, the Non-GAAP Measures) do not have any standardized definition and therefore are unlikely to be comparable to similar measures presented by other reporting companies. Non-GAAP Measures should not be evaluated in isolation of, or as a substitute for, our financial results prepared in accordance with GAAP. Non-GAAP Measures and the underlying methodology in excluding certain revenues or charges is not necessarily an indication of the results of operations expected in the future, or that we will not, in fact, receive such revenue or incur such charges in future periods.
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. BusinessOur Contracts in our Annual Report on Form 10-K for the year ended December 31, 2011 for further discussion of each of these types of arrangements.
The following table does not give effect to our active commodity risk management program. For the nine months ended September 30, 2012, we calculated the following approximate percentages of our segment revenue and net operating margin from the following types of contracts:
|
|
Fee-Based |
|
Percent-of-Proceeds (1) |
|
Percent-of-Index (2) |
|
Keep-Whole (3) |
|
Segment revenue |
|
29 |
% |
35 |
% |
3 |
% |
33 |
% |
Net operating margin (4) |
|
47 |
% |
26 |
% |
0 |
% |
27 |
% |
(1) Includes condensate sales and other types of arrangements tied to NGL prices.
(2) Includes arrangements tied to natural gas prices.
(3) Includes condensate sales and other types of arrangements tied to both NGL and natural gas prices.
(4) We manage our business by taking into account the partial offset of short natural gas positions by long positions primarily in our Southwest segment. The calculated percentages for the net operating margin for percent-of-proceeds, percent-of-index and keep-whole contracts reflect the partial offset of our natural gas positions.
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 and Liberty segments are particularly impacted by seasonality. In our Northeast and Liberty segments, we store a portion of the propane that is produced in the summer to be sold in the winter months. To manage this seasonality, we have access to approximately 50 million gallons of propane storage capacity provided by our own storage facilities and a firm capacity arrangement with a third-party. If we are unable to fully utilize our storage capacity due to third party capacity constraints or other reasons, our operations would be adversely affected. 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, however, the expected growth and expansion in our Liberty segment may partially counteract this seasonality impact on sales volumes.
Results of Operations
Segment Reporting
We present information in this MD&A by segment. The segment information appearing in Note 14 of the accompanying Notes to the Condensed Consolidated Financial Statements is presented on a basis consistent with our internal management reporting. We conduct our operations in the following operating segments: Southwest, Northeast, Liberty and Gulf Coast. Our assets and operations in each of these segments are described below. In addition, we include a description of our initial plans to develop our Utica operations, which are included in the Liberty segment.
Southwest
· East Texas. We own a system that consists of natural gas gathering pipelines, centralized compressor stations, 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 either purchase the NGLs from the producers under percent-of-proceeds arrangements, or we transport and process volumes for a fee. We expect to complete an additional 120 MMcf/d cryogenic processing plant during the fourth quarter of 2012, increasing total processing capacity in East Texas to 400 MMcf/d. We also plan to expand gathering capacity in East Texas by 140 MMcf/d and residue gas outlet capacities by 60 MMcf/d.
· Oklahoma. We own a natural gas gathering system in the Woodford Shale play in the Arkoma Basin of southeast Oklahoma. The liquids-rich natural gas gathered in the Woodford system is processed through Centrahoma, our equity investment, or other third-party processors. We have agreed to fund our share of a 120 MMcf/d processing plant expansion at Centrahoma in order to support the drilling programs in the Woodford Shale. The expansion is expected to be operational in the first quarter of 2014. In addition, we own the Foss Lake natural gas gathering system and the Western Oklahoma natural gas processing complex, all located in Roger Mills, Beckham, 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 is ultimately compressed and delivered to the processing plants. We also own a gathering system in the Granite Wash formation in the Texas panhandle that is connected to our Western Oklahoma processing complex.
Through our joint venture, MarkWest Pioneer, we operate the Arkoma Connector Pipeline, a 50-mile FERC-regulated pipeline that interconnects with the Midcontinent Express Pipeline and Gulf Crossing Pipeline at Bennington, Oklahoma and is designed to provide approximately 638,000 Dth/d of Woodford Shale takeaway capacity. We completed an additional interconnect with the NGPL Pipeline in Bennington, Oklahoma in April 2012. For a complete discussion of the formation of, and accounting treatment for, MarkWest Pioneer, see Note 4 of Item 8. Financial Statement and Supplementary Data, of our Annual Report on Form 10-K for the year ended December 31, 2011.
· Other Southwest. We own a number of natural gas gathering systems and lateral pipelines located in Texas, Louisiana and New Mexico, including the Appleby gathering system in Nacogdoches County, Texas. We gather a significant portion of the natural gas produced from fields adjacent to our gathering systems, including from wells targeting the Haynesville Shale. In many areas we are the primary gatherer, and in some of the areas served by our smaller systems we are the sole gatherer. Our Hobbs, New Mexico natural gas lateral pipeline is subject to regulation by FERC.
Northeast
· Kentucky and southern West Virginia. Our Northeast segment assets include the Kenova, Boldman, Cobb, Kermit and the Langley natural gas processing plants, an NGL pipeline, and the Siloam NGL fractionation plant. During the fourth quarter 2012, we completed an additional cryogenic natural gas processing plant at the Langley processing complex with a capacity of 150 MMcf/d. In addition, we have two caverns for storing propane at our Siloam facility and additional propane storage capacity under a long-term firm-capacity agreement with a third-party. Including our presence in the Marcellus Shale (see Liberty Segment below), we are the largest processor and fractionator of natural gas in the Appalachian region, with fully integrated processing, fractionation, storage and marketing operations.
· Michigan. We own and operate a FERC-regulated crude oil pipeline in Michigan providing transportation service for three shippers.
Liberty
· Marcellus Shale. We provide extensive natural gas midstream services in southwest Pennsylvania and northern West Virginia through MarkWest Liberty Midstream and its subsidiaries. With gathering capacity of approximately 390 MMcf/d and current processing capacity of 915 MMcf/d, we are the largest processor of natural gas in the Marcellus Shale, with fully integrated gathering, processing, fractionation, storage and marketing operations that are critical to the liquids-rich gas development in the northeast United States.
The gathering, processing and fractionation facilities currently operating and under construction in our Liberty segment consist of the following:
Natural Gas Gathering
· Existing gathering system delivering to our Houston Complex.
· Existing gathering lines acquired in the Keystone Acquisition.
· Existing gathering system completed in the fourth quarter, delivering to our processing facilities in Sherwood, West Virginia, (Sherwood Complex).
Natural Gas Processing
· 355 MMcf/d of current cryogenic processing capacity at our Houston Complex.
· 270 MMcf/d of current cryogenic processing capacity at our Majorsville, West Virginia processing complex (Majorsville Complex).
· 90 MMcf/d of cryogenic processing capacity at our Butler County, Pennsylvania processing plants (Keystone Complex), which we acquired in the Keystone Acquisition.
· 200 MMcf/d cryogenic processing capacity at our recently completed Sherwood Complex.
· 800 MMcf/d expansion of our Majorsville Complex under construction that is supported by long-term agreements with Chesapeake Energy Corporation, CONSOL Energy Inc., Noble Energy Inc. and Range Resources Corporation. The Majorsville expansion includes four, 200 MMcf/d processing plants that are expected to commence operation in 2013 and 2014 and will bring our total cryogenic processing capacity at Majorsville to approximately 1.1 Bcf/d.
· 520 MMcf/d cryogenic processing capacity under construction in Mobley, West Virginia (Mobley Complex) where 200 MMcf/d, 120 MMcf/d and 200 MMcf/d cryogenic plants are expected to be completed in the fourth quarter of 2012, first quarter of 2013 and fourth quarter 2013, respectively.
· 200 MMcf/d cryogenic processing capacity under construction at our Sherwood Complex that is expected to be completed in the second quarter of 2013. We plan to expand the capacity at our Sherwood Complex with an additional 200 MMcf/d cryogenic processing plant that is expected to be completed in third quarter 2013. The expansion plans are based, in part, on Antero Resources decision to support the additional capacity under a long-term processing agreement. Antero Resources must make its final decision on whether to proceed with the additional plant at the Sherwood Complex by May 1, 2013.
· 120 MMcf/d cryogenic processing capacity under construction in Butler County, Pennsylvania as part of our Keystone Acquisition, which is expected to commence operation in the first quarter of 2014. Based on producers production we may expand our Keystone Complex by 200 MMcf/d as soon as 2014.
By the end of 2014, MarkWest Liberty Midstream is expected to have up to approximately 3.0 Bcf/d of cryogenic processing capacity that is supported by primarily fee-based long-term agreements with our producer customers.
NGL Gathering, Fractionation and Market Outlets
· NGLs produced at the Majorsville Complex are delivered through an NGL pipeline (Majorsville Pipeline) to the Houston Complex for exchange for fractionated products. NGL pipelines connecting each of the planned processing facilities in West Virginia to the Majorsville Pipeline are under construction and will allow for NGL transportation to the Houston Complex for fractionation. Additionally, we have announced our plans to extend our NGL pipeline into northwest Pennsylvania to allow us to gather, fractionate and market NGLs produced at our Keystone Complex and at a processing facility owned by XTO that is expected to begin operations in late 2012. We will provide the transportation, fractionation and marketing services to XTO pursuant to a long-term fee-based agreement executed in July 2012. The NGLs will be transported to the fractionation facility at our Houston Complex by truck until the NGL pipeline is complete in late 2013.
· Existing fractionation facility at our Houston Complex with a design capacity of 60,000 Bbl/d.
· Existing interconnect with a key interstate pipeline providing a market outlet for the propane produced from this region.
· Existing agreements to access international markets. Propane is currently being transported by truck to a third-party terminal near Philadelphia, Pennsylvania where it is loaded onto marine vessels and delivered to international markets. We plan to add rail deliveries to the terminal in the next several months as rail unloading capabilities are expanded. As discussed below, we will also have the ability to deliver propane to Sunocos terminal in Philadelphia via pipeline once the Mariner East pipeline is placed into service.
· Existing extension of our Majorsville Pipeline to receive NGLs produced at a third-partys Fort Beeler processing plant. This project allows certain producers to benefit from our integrated NGL fractionation and marketing operations.
· Existing eight bay truck loading and unloading facility at our Houston Complex.
· Recently completed 200 railcar loading facility at our Houston Complex.
We continue to evaluate additional projects to expand our gathering, processing, fractionation, and marketing operations in the Marcellus Shale.
Ethane Recovery and Associated Market Outlets
Due to the increased production of natural gas from the liquids-rich area of the Marcellus Shale, natural gas processors must begin to recover a significant amount of ethane from the raw NGL stream to continue to meet the pipeline gas quality specifications for residue gas. We have been developing solutions that will have the capability to recover and fractionate the required ethane, be scalable to recover and fractionate additional ethane at the option of our producer customers and provide access to attractive ethane markets in North America and Europe. The primary components of our ethane recovery solution consist of the following:
· 76,000 Bbl/d de-ethanization facilities under construction at our Houston Complex and Majorsville Complex that are expected to be completed by mid-2013.
· A third de-ethanization facility at the Majorsville Complex is planned that would increase production capacity of purity ethane to approximately 115,000 Bbl/d in first quarter 2014.
· A joint pipeline project with Sunoco Logistics, L.P. (Sunoco) that is currently under construction to deliver Marcellus ethane to Sarnia, Ontario, Canada markets (Mariner West). Mariner West will utilize new and existing pipelines and is anticipated to have an initial capacity to transport up to 50,000 Bbl/d of ethane in the third quarter of 2013 with the ability to expand to support higher volumes as needed.
· Mariner East, a pipeline and marine project, is intended to deliver Marcellus purity ethane and purity propane to the Gulf Coast and international markets. Mariner East is expected to begin delivering propane in the second half of 2014 and ethane in the first half of 2015.
We continue to evaluate additional projects that would support a comprehensive ethane solution for producers in the Marcellus Shale.
Utica
Effective January 1, 2012, we formed MarkWest Utica EMG, a joint venture focused on the development of significant natural gas gathering, processing and NGL fractionation, transportation and marketing infrastructure to serve producers drilling programs in the Utica Shale in eastern Ohio with The Energy & Minerals Group (EMG). The current Utica development plan includes gathering and compression systems and two new processing complexes with total cryogenic processing capacity of 725 MMcf/d and 100,000 Bbl/d of fractionation, storage, and marketing capabilities. The fractionation facility in Harrison County for propane and heavier components (Harrison Fractionation Facility) will be jointly owned by MarkWest Utica EMG and MarkWest Liberty Midstream. The processing complexes will be in Cadiz township in Harrison County (Cadiz Complex) and in Seneca township in Noble County (Seneca Complex). The Cadiz Complex is expected to begin the first phase of operations in the fourth quarter of 2012 with interim mechanical refrigeration processing capacity of 60 MMcf/d. The Seneca Complex is expected to begin the first phase of operations in second quarter 2013 with interim mechanical refrigeration processing capacity of 45 MMcf/d. The total planned cryogenic processing capacity of 725 MMcf/d is expected to be in operation by the first quarter of 2014.
Both processing complexes are expected to be connected via an NGL gathering pipeline system to the Harrison Fractionation Facility that is expected to be operational by the first quarter of 2014. Creating a large network of processing complexes connected through an extensive NGL gathering system has been critical to the full development of the Marcellus, and the announced Ohio facilities represent the first major step in providing Utica Shale producers with the same benefits. From the Harrison Fractionation Facility, we plan to market NGLs by truck, rail and pipeline. A railcar loading facility that can accommodate 200 rail cars and an eight bay truck loading and unloading facility are under construction at Harrison Fractionation Facility and are expected to be complete by mid-2013. Additionally, at our Cadiz Complex we are also constructing de-ethanization capacity and a connection to Enterprise Products Partners L.P.s NGL pipeline from Appalachia to Texas (ATEX Pipeline). We expect to begin delivering ethane to the ATEX Pipeline in the first quarter 2014. Additionally, the Harrison Fractionation Facility is expected to be connected to our extensive processing and NGL pipeline network in our Liberty segment and provide for the integrated operation of the two largest fractionation complexes in the Northeast United States in the first quarter 2014.
On June 4, 2012, MarkWest Utica EMG announced agreements with Gulfport Energy Corporation (Gulfport) to provide gathering, processing, fractionation, and marketing services in the liquids-rich corridor of the Utica Shale. Under the terms of the agreements, MarkWest Utica EMG is developing natural gas gathering infrastructure to provide service to Gulfport, primarily in Harrison, Guernsey, and Belmont Counties, that commenced initial operations beginning in the third quarter of 2012. MarkWest Utica EMG is processing the gas at its Cadiz Complex, and is expected to provide NGL fractionation and marketing services at the Harrison Fractionation Facility when it is completed in the first quarter of 2014.
Gulf Coast
· 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 also have a product supply agreement creating a long-term contractual obligation for the payment of processing fees in exchange for all of the product processed by the SMR that is operated by a third-party. The product received under this agreement is sold to a refinery customer pursuant to a corresponding long-term agreement.
The following summarizes the percentage of our segment 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, 2012:
|
|
Southwest |
|
Northeast |
|
Liberty |
|
Gulf Coast |
|
Segment revenue |
|
57 |
% |
16 |
% |
21 |
% |
6 |
% |
Net operating margin |
|
46 |
% |
18 |
% |
26 |
% |
10 |
% |
Segment Operating Results
Items below Income (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 financial information, as evaluated by management, for the reported segments for the three months ended September 30, 2012 and 2011 and for the nine months ended September 30, 2012 and 2011. The information includes net operating margin, a non-GAAP financial measure. See above for a reconciliation of net operating margin to Income (loss) from operations, the most comparable GAAP financial measure.
Three months ended September 30, 2012 compared to three months ended September 30, 2011
Southwest
|
|
Three months ended September 30, |
|
|
|
% |
| |||||
|
|
2012 |
|
2011 |
|
$ Change |
|
Change |
| |||
|
|
(in thousands) |
|
|
| |||||||
Segment revenue |
|
$ |
181,456 |
|
$ |
241,998 |
|
$ |
(60,542 |
) |
(25 |
)% |
Purchased product costs |
|
92,112 |
|
141,067 |
|
(48,955 |
) |
(35 |
)% | |||
Net operating margin |
|
89,344 |
|
100,931 |
|
(11,587 |
) |
(11 |
)% | |||
Facility expenses |
|
20,527 |
|
21,043 |
|
(516 |
) |
(2 |
)% | |||
Portion of operating income attributable to non-controlling interests |
|
1,543 |
|
1,227 |
|
316 |
|
26 |
% | |||
Operating income before items not allocated to segments |
|
$ |
67,274 |
|
$ |
78,661 |
|
$ |
(11,387 |
) |
(14 |
)% |
Segment Revenue. Revenue decreased primarily due to lower NGL prices and decrease in natural gas sales volumes. The decrease was partially offset by increased NGL sales volumes, primarily due to the expansion of the Western Oklahoma processing facilities completed at the end of the third quarter 2011 and increases in processing and gathering fees in Southeast Oklahoma.
Purchased Product Costs. Purchased product costs decreased primarily due to a decrease in the price NGLs and a decrease in the volume of natural gas purchased.
Northeast
|
|
Three months ended September 30, |
|
|
|
% |
| |||||
|
|
2012 |
|
2011 |
|
$ Change |
|
Change |
| |||
|
|
(in thousands) |
|
|
| |||||||
Segment revenue |
|
$ |
39,987 |
|
$ |
55,920 |
|
$ |
(15,933 |
) |
(28 |
)% |
Purchased product costs |
|
11,054 |
|
15,947 |
|
(4,893 |
) |
(31 |
)% | |||
Net operating margin |
|
28,933 |
|
39,973 |
|
(11,040 |
) |
(28 |
)% | |||
Facility expenses |
|
6,267 |
|
6,879 |
|
(612 |
) |
(9 |
)% | |||
Operating income before items not allocated to segments |
|
$ |
22,666 |
|
$ |
33,094 |
|
$ |
(10,428 |
) |
(32 |
)% |
Segment Revenue. Revenue decreased due to lower NGL prices, partially offset by an increase in NGL sales volumes. The increase in NGL sales volumes for the three months ended September 30, 2012 compared to the same period in 2011 is partly due to a key transmission pipeline feeding our processing plants, which was damaged and had limited service capacity during the first nine months of 2011. However, the pipeline was repaired and fully operational for the entire third quarter of 2012.
Purchased Product Costs. Purchased product costs decreased due to lower prices for natural gas that is purchased to satisfy the keep-whole arrangements in the Appalachia area, partially offset by an increase in NGL sales volumes.
Liberty
|
|
Three months ended September 30, |
|
|
|
% |
| |||||
|
|
2012 |
|
2011 |
|
$ Change |
|
Change |
| |||
|
|
(in thousands) |
|
|
| |||||||
Segment revenue |
|
$ |
78,852 |
|
$ |
78,586 |
|
$ |
266 |
|
0 |
% |
Purchased product costs |
|
16,203 |
|
32,270 |
|
(16,067 |
) |
(50 |
)% | |||
Net operating margin |
|
62,649 |
|
46,316 |
|
16,333 |
|
35 |
% | |||
Facility expenses |
|
20,241 |
|
9,108 |
|
11,133 |
|
122 |
% | |||
Portion of operating (loss) income attributable to non-controlling interests |
|
(627 |
) |
18,223 |
|
(18,850 |
) |
(103 |
)% | |||
Operating income before items not allocated to segments |
|
$ |
43,035 |
|
$ |
18,985 |
|
$ |
24,050 |
|
127 |
% |
Segment Revenue. Revenue increased due to ongoing expansion of the Liberty operations resulting in increased gathered, processed and fractionated volumes. Revenue increased approximately $15.3 million related to gathering, processing and fractionation fees, offset by approximately $15.1 million decrease related to lower prices for NGLs sold.
Purchased Product Costs. Purchased product costs decreased due to lower NGL prices and lower NGL volumes purchased from a producer.
Facility Expenses. Facility expenses increased due to the ongoing expansion of the Liberty operations.
Portion of Operating Income Attributable to Non-controlling Interests. The portion of operating income attributable to non-controlling interests for the three months ended September 30, 2011 represented the interest of M&R, an affiliate of EMG, our former joint venture partner in MarkWest Liberty Midstream, in net operating income of MarkWest Liberty Midstream. As a result of our acquisition of M&Rs interest in MarkWest Liberty Midstream, no portion of its income is attributable to non-controlling interests for the three months ended September 30, 2012. The immaterial portion of loss allocable to the non-controlling interest for the three months ended September 30, 2012 relates to MarkWest Utica EMG and its subsidiaries.
Gulf Coast
|
|
Three months ended September 30, |
|
|
|
% |
| |||||
|
|
2012 |
|
2011 |
|
$ Change |
|
Change |
| |||
|
|
(in thousands) |
|
|
| |||||||
Segment revenue |
|
$ |
21,477 |
|
$ |
26,868 |
|
$ |
(5,391 |
) |
(20 |
)% |
Purchased product costs |
|
|
|
|
|
|
|
N/A |
| |||
Net operating margin |
|
21,477 |
|
26,868 |
|
(5,391 |
) |
(20 |
)% | |||
Facility expenses |
|
8,928 |
|
9,798 |
|
(870 |
) |
(9 |
)% | |||
Operating income before items not allocated to segments |
|
$ |
12,549 |
|
$ |
17,070 |
|
$ |
(4,521 |
) |
(26 |
)% |
Segment Revenue. Revenue decreased primarily due to lower NGL prices.
Facility Expenses. Facility expenses decreased primarily due to the timing of facility maintenance and repairs.
Reconciliation of Segment Operating Income to Consolidated Income (Loss) Before Provision for Income Tax
The following table provides a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to our consolidated income (loss) before provision for income tax for the three months ended September 30, 2012 and 2011, respectively. The ensuing items listed below the Total segment revenue and Operating income before items not allocated to segments lines are not allocated to business segments as management does not consider these items allocable to any individual segment.
|
|
Three months ended September 30, |
|
|
|
% |
| |||||
|
|
2012 |
|
2011 |
|
$ Change |
|
Change |
| |||
|
|
(in thousands) |
|
|
| |||||||
Total segment revenue |
|
$ |
321,772 |
|
$ |
403,372 |
|
$ |
(81,600 |
) |
(20 |
)% |
Derivative (loss) gain not allocated to segments |
|
(36,400 |
) |
106,943 |
|
(143,343 |
) |
(134 |
)% | |||
Revenue deferral adjustment |
|
(1,635 |
) |
(2,489 |
) |
854 |
|
(34 |
)% | |||
Total revenue |
|
$ |
283,737 |
|
$ |
507,826 |
|
$ |
(224,089 |
) |
(44 |
)% |
|
|
|
|
|
|
|
|
|
| |||
Operating income before items not allocated to segments |
|
$ |
145,524 |
|
$ |
147,810 |
|
$ |
(2,286 |
) |
(2 |
)% |
Portion of operating income attributable to non-controlling interests |
|
916 |
|
19,450 |
|
(18,534 |
) |
(95 |
)% | |||
Derivative (loss) gain not allocated to segments |
|
(52,071 |
) |
111,004 |
|
(163,075 |
) |
(147 |
)% | |||
Revenue deferral adjustment |
|
(1,635 |
) |
(2,489 |
) |
854 |
|
(34 |
)% | |||
Compensation expense included in facility expenses not allocated to segments |
|
(193 |
) |
(263 |
) |
70 |
|
(27 |
)% | |||
Facility expenses adjustments |
|
2,863 |
|
2,855 |
|
8 |
|
0 |
% | |||
Selling, general and administrative expenses |
|
(21,922 |
) |
(20,162 |
) |
(1,760 |
) |
9 |
% | |||
Depreciation |
|
(48,136 |
) |
(38,715 |
) |
(9,421 |
) |
24 |
% | |||
Amortization of intangible assets |
|
(14,988 |
) |
(10,985 |
) |
(4,003 |
) |
36 |
% | |||
Loss on disposal of property, plant and equipment |
|
(655 |
) |
(147 |
) |
(508 |
) |
346 |
% | |||
Accretion of asset retirement obligations |
|
(141 |
) |
(557 |
) |
416 |
|
(75 |
)% | |||
Income from operations |
|
9,562 |
|
207,801 |
|
(198,239 |
) |
(95 |
)% | |||
|
|
|
|
|
|
|
|
|
| |||
Earnings (loss) from unconsolidated affiliate |
|
246 |
|
(507 |
) |
753 |
|
(149 |
)% | |||
Interest income |
|
64 |
|
62 |
|
2 |
|
3 |
% | |||
Interest expense |
|
(30,621 |
) |
(26,899 |
) |
(3,722 |
) |
14 |
% | |||
Amortization of deferred financing costs and discount (a component of interest expense) |
|
(1,428 |
) |
(1,002 |
) |
(426 |
) |
43 |
% | |||
Loss on redemption of debt |
|
|
|
(133 |
) |
133 |
|
(100 |
)% | |||
Miscellaneous income (expense), net |
|
1 |
|
(4 |
) |
5 |
|
(125 |
)% | |||
(Loss) income before provision for income tax |
|
$ |
(22,176 |
) |
$ |
179,318 |
|
$ |
(201,494 |
) |
(112 |
)% |
Derivative (Loss) Gain Not Allocated to Segments. Unrealized loss from the change in fair value of our derivative instruments was $43.7 million for the three months ended September 30, 2012 compared to an unrealized gain of $126.8 million for the same period in 2011. Realized loss from the settlement of our derivative instruments was $8.4 million for the three months ended September 30, 2012 compared to $15.8 million for the same period in 2011. The total change of $163.1 million is due mainly to volatility in commodity prices. Despite the decline in NGL prices in 2012 compared to 2011, we continued to experience realized losses on our derivative positions used to manage NGL price risk due to the decreased effectiveness of crude oil positions used as a proxy contract for NGLs. We are not able to predict the future effectiveness of our crude oil positions in managing NGL price risk, but ineffectiveness may continue for the near-term.
Revenue Deferral Adjustment. Revenue deferral adjustment relates primarily to certain contracts in which the cash consideration we receive for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as we will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the three months ended September 30, 2012,
approximately $0.2 million and $1.4 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. For the three months ended September 30, 2011, approximately $0.2 million and $2.3 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Based on current commodity prices, management expects the deferred revenue in subsequent periods to approximate the third quarter 2012s amount until the beginning of 2015 when the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.
Selling, General and Administrative Expenses. Selling, general and administrative expenses increased primarily due to higher labor, benefits, office expense and professional services necessary to support the overall growth of our operations.
Depreciation. Depreciation increased due to additional projects completed during 2011 through the third quarter of 2012, as well as the Keystone Acquisition.
Amortization of Intangible Assets. Amortization increased due to the customer relationship intangibles acquired in the Keystone Acquisition.
Interest Expense. Interest expense increased due to the increased amount of outstanding debt. The increase was partially offset by an increase in capitalized interest.
Nine months ended September 30, 2012 compared to nine months ended September 30, 2011
Southwest
|
|
Nine months ended September 30, |
|
|
|
% |
| |||||
|
|
2012 |
|
2011 |
|
$ Change |
|
Change |
| |||
|
|
(in thousands) |
|
|
| |||||||
Segment revenue |
|
$ |
585,343 |
|
$ |
679,347 |
|
$ |
(94,004 |
) |
(14 |
)% |
Purchased product costs |
|
288,137 |
|
373,251 |
|
(85,114 |
) |
(23 |
)% | |||
Net operating margin |
|
297,206 |
|
306,096 |
|
(8,890 |
) |
(3 |
)% | |||
Facility expenses |
|
66,553 |
|
62,055 |
|
4,498 |
|
7 |
% | |||
Portion of operating income attributable to non-controlling interests |
|
4,579 |
|
3,745 |
|
834 |
|
22 |
% | |||
Operating income before items not allocated to segments |
|
$ |
226,074 |
|
$ |
240,296 |
|
$ |
(14,222 |
) |
(6 |
)% |
Segment Revenue. Revenue decreased primarily due to lower NGL prices and a decrease in natural gas sales volumes. The decrease was partially offset by an increase in NGL sales volumes, primarily due to the expansion of the Western Oklahoma processing facilities completed at the end of the third quarter of 2011 and increases in processing and gathering fees in Southeast Oklahoma.
Purchased Product Costs. Purchased product costs decreased primarily due to lower NGL prices and a reduction in the volume of natural gas purchased.
Facility Expenses. Facility expenses increased primarily due to the expansion of our processing and gathering facilities in Western Oklahoma.
Northeast
|
|
Nine months ended September 30, |
|
|
|
% |
| |||||
|
|
2012 |
|
2011 |
|
$ Change |
|
Change |
| |||
|
|
(in thousands) |
|
|
| |||||||
Segment revenue |
|
$ |
168,956 |
|
$ |
201,687 |
|
$ |
(32,731 |
) |
(16 |
)% |
Purchased product costs |
|
49,662 |
|
72,527 |
|
(22,865 |
) |
(32 |
)% | |||
Net operating margin |
|
119,294 |
|
129,160 |
|
(9,866 |
) |
(8 |
)% | |||
Facility expenses |
|
17,577 |
|
19,402 |
|
(1,825 |
) |
(9 |
)% | |||
Operating income before items not allocated to segments |
|
$ |
101,717 |
|
$ |
109,758 |
|
$ |
(8,041 |
) |
(7 |
)% |
Segment Revenue. Revenue decreased due to lower natural gas prices, as well as a contract change related to our acquisition of the Langley processing facilities and related assets (Langley Acquisition) in the first quarter of 2011. Subsequent to the Langley Acquisition, we continue to market the NGLs related to natural gas processed at the Langley plant; however we are acting as an agent and therefore record revenue net of purchased product costs. Prior to the contract change we were acting as the principal. The decrease in revenue was offset by increased NGL sales volumes, which was partly due to a key transmission pipeline feeding our processing plants that was damaged and had limited service capacity during the first nine months of 2011 but that was repaired and fully operational for the entire first nine months of 2012.
Purchased Product Costs. Purchased product costs decreased due to the contract change related to the Langley Acquisition. In addition, purchased product costs decreased due to lower prices for natural gas that is purchased to satisfy the keep-whole arrangements in the Appalachia area, which was partially offset by an increase in sales volumes.
Facility Expenses. Facility expenses decreased primarily due to timing of repairs and maintenance.
Liberty
|
|
Nine months ended September 30, |
|
|
|
% |
| |||||
|
|
2012 |
|
2011 |
|
$ Change |
|
Change |
| |||
|
|
(in thousands) |
|
|
| |||||||
Segment revenue |
|
$ |
213,906 |
|
$ |
168,142 |
|
$ |
45,764 |
|
27 |
% |
Purchased product costs |
|
48,856 |
|
51,715 |
|
(2,859 |
) |
(6 |
)% | |||
Net operating margin |
|
165,050 |
|
116,427 |
|
48,623 |
|
42 |
% | |||
Facility expenses |
|
46,135 |
|
22,875 |
|
23,260 |
|
102 |
% | |||
Portion of operating (loss) income attributable to non-controlling interests |
|
(740 |
) |
45,782 |
|
(46,522 |
) |
(102 |
)% | |||
Operating income before items not allocated to segments |
|
$ |
119,655 |
|
$ |
47,770 |
|
$ |
71,865 |
|
150 |
% |
Segment Revenue. Revenue increased due to ongoing expansion of the Liberty operations resulting in increased gathered, processed and fractionated volumes. Revenue increased approximately $43.4 million related to gathering, processing and fractionation fees and approximately $1.1 million related to increased NGL product sales under a percent of proceeds agreement with a producer and an increase in sales of propane from inventory purchased from producer customers. NGLs sales increased due to higher volumes partially offset by lower prices.
Purchased Product Costs. Purchased product costs increased primarily due to an increase in the volume of NGLs purchased from producer customers and then sold.
Facility Expenses. Facility expenses increased due to the ongoing expansion of the Liberty operations.
Portion of Operating Income Attributable to Non-controlling Interests. The portion of operating income attributable to non-controlling interests for the nine months ended September 30, 2011 represented M&Rs interest in net operating income of MarkWest Liberty Midstream. As a result of our acquisition of M&Rs interest in MarkWest Liberty Midstream, no portion of its income is attributable to non-controlling interests for the nine months ended September 30, 2012. The immaterial portion of income allocable to the non-controlling interest for the nine months ended September 30, 2012 relates to MarkWest Utica EMG and its subsidiaries.
Gulf Coast
|
|
Nine months ended September 30, |
|
|
|
% |
| |||||
|
|
2012 |
|
2011 |
|
$ Change |
|
Change |
| |||
|
|
(in thousands) |
|
|
| |||||||
Segment revenue |
|
$ |
66,703 |
|
$ |
73,310 |
|
$ |
(6,607 |
) |
(9 |
)% |
Purchased product costs |
|
|
|
|
|
|
|
N/A |
| |||
Net operating margin |
|
66,703 |
|
73,310 |
|
(6,607 |
) |
(9 |
)% | |||
Facility expenses |
|
28,173 |
|
27,100 |
|
1,073 |
|
4 |
% | |||
Operating income before items not allocated to segments |
|
$ |
38,530 |
|
$ |
46,210 |
|
$ |
(7,680 |
) |
(17 |
)% |
Segment Revenue. Revenue decreased primarily due to lower NGL prices, partially offset by an increase in volumes resulting from increased production as scheduled refinery maintenance in 2011 did not recur in 2012.
Facility Expenses. Facility expenses increased primarily due to plant turnaround costs incurred in second quarter 2012, as well as timing of other facility maintenance and repairs.
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, 2012 and 2011, respectively. The ensuing items listed below the Total segment revenue and Operating income lines are not allocated to business segments as management does not consider these items allocable to any individual segment.
|
|
Nine months ended September 30, |
|
|
|
% |
| |||||
|
|
2012 |
|
2011 |
|
$ Change |
|
Change |
| |||
|
|
(in thousands) |
|
|
| |||||||
Total segment revenue |
|
$ |
1,034,908 |
|
$ |
1,122,486 |
|
$ |
(87,578 |
) |
(8 |
)% |
Derivative gain not allocated to segments |
|
50,952 |
|
61,854 |
|
(10,902 |
) |
(18 |
)% | |||
Revenue deferral adjustment |
|
(5,604 |
) |
(12,854 |
) |
7,250 |
|
(56 |
)% | |||
Total revenue |
|
$ |
1,080,256 |
|
$ |
1,171,486 |
|
$ |
(91,230 |
) |
(8 |
)% |
|
|
|
|
|
|
|
|
|
| |||
Operating income before items not allocated to segments |
|
$ |
485,976 |
|
$ |
444,034 |
|
$ |
41,942 |
|
9 |
% |
Portion of operating income attributable to non-controlling interests |
|
3,839 |
|
49,527 |
|
(45,688 |
) |
(92 |
)% | |||
Derivative gain not allocated to segments |
|
70,952 |
|
46,859 |
|
24,093 |
|
51 |
% | |||
Revenue deferral adjustment |
|
(5,604 |
) |
(12,854 |
) |
7,250 |
|
(56 |
)% | |||
Compensation expense included in facility expenses not allocated to segments |
|
(826 |
) |
(1,491 |
) |
665 |
|
(45 |
)% | |||
Facility expenses adjustments |
|
8,593 |
|
8,565 |
|
28 |
|
0 |
% | |||
Selling, general and administrative expenses |
|
(69,025 |
) |
(60,454 |
) |
(8,571 |
) |
14 |
% | |||
Depreciation |
|
(132,199 |
) |
(110,280 |
) |
(21,919 |
) |
20 |
% | |||
Amortization of intangible assets |
|
(38,280 |
) |
(32,632 |
) |
(5,648 |
) |
17 |
% | |||
Loss on disposal of property, plant and equipment |
|
(2,983 |
) |
(4,619 |
) |
1,636 |
|
(35 |
)% | |||
Accretion of asset retirement obligations |
|
(540 |
) |
(934 |
) |
394 |
|
(42 |
)% | |||
Income from operations |
|
319,903 |
|
325,721 |
|
(5,818 |
) |
(2 |
)% | |||
|
|
|
|
|
|
|
|
|
| |||
Earnings (loss) from unconsolidated affiliate |
|
788 |
|
(1,262 |
) |
2,050 |
|
(162 |
)% | |||
Interest income |
|
295 |
|
214 |
|
81 |
|
38 |
% | |||
Interest expense |
|
(86,855 |
) |
(83,036 |
) |
(3,819 |
) |
5 |
% | |||
Amortization of deferred financing costs and discount (a component of interest expense) |
|
(3,943 |
) |
(3,873 |
) |
(70 |
) |
2 |
% | |||
Loss on redemption of debt |
|
|
|
(43,461 |
) |
43,461 |
|
(100 |
)% | |||
Miscellaneous income, net |
|
63 |
|
127 |
|
(64 |
) |
(50 |
)% | |||
Income before provision for income tax |
|
$ |
230,251 |
|
$ |
194,430 |
|
$ |
35,821 |
|
18 |
% |
Derivative Gain Not Allocated to Segments. Unrealized gain from the change in fair value of our derivative instruments was $101.8 million for the nine months ended September 30, 2012 compared to an unrealized gain of $102.7 million for the same period in 2011. Realized loss from the settlement of our derivative instruments was $30.9 million for the nine months ended September 30, 2012 compared to $55.8 million for the same period in 2011. The total change of $24.1 million is due mainly to volatility in commodity prices. Despite the decline in NGL prices in 2012 compared to 2011, we continued to experience realized losses on our derivative positions used to manage NGL price risk due to the decreased effectiveness of crude oil positions used as a proxy contract for NGLs. We are not able to predict the future effectiveness of our crude oil positions in managing NGL price risk, but ineffectiveness may continue for the near-term.
Revenue Deferral Adjustment. Revenue deferral adjustment relates primarily to certain contracts in which the cash consideration we receive for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as we will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore the impact of the revenue deferrals is excluded for segment reporting purposes. For the nine months ended September 30, 2012, approximately $0.6 million and $5.0 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. For the nine months ended September 30, 2011, approximately $6.9 million and $5.9 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Based on current commodity prices, management expects the deferred revenue in subsequent periods to approximate the third quarter 2012s amount until the beginning of 2015 when the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.
Selling, General and Administrative Expenses. Selling, general and administrative expenses increased primarily due to higher labor, benefits, office expense and professional services necessary to support the overall growth of our operations.
Depreciation. Depreciation increased due to additional projects completed during 2011 through the third quarter of 2012, as well as the Keystone Acquisition.
Amortization of Intangible Assets. Amortization increased due to the customer relationship intangibles acquired in the Keystone Acquisition.
Interest Expense. Interest expense increased due to an increase in outstanding debt, but was partially offset by lower interest rates and increased capitalized interest.
Loss on Redemption of Debt. The decrease in loss on redemption of debt was related to the redemption of debt which occurred in the first quarter of 2011, while no such redemptions of debt occurred during the first nine months of 2012.
Operating Data
|
|
Three months ended |
|
% |
|
Nine months ended |
|
% |
| ||||
|
|
2012 |
|
2011 |
|
Change |
|
2012 |
|
2011 |
|
Change |
|
Southwest |
|
|
|
|
|
|
|
|
|
|
|
|
|
East Texas gathering systems throughput (Mcf/d) |
|
471,200 |
|
417,400 |
|
13 |
% |
440,700 |
|
423,800 |
|
4 |
% |
East Texas natural gas processed (Mcf/d) |
|
270,200 |
|
229,700 |
|
18 |
% |
260,400 |
|
226,000 |
|
15 |
% |
East Texas NGL sales (gallons, in thousands) |
|
67,800 |
|
59,000 |
|
15 |
% |
199,300 |
|
175,200 |
|
14 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Western Oklahoma gathering system throughput (Mcf/d) (1) |
|
227,900 |
|
241,300 |
|
(6 |
)% |
247,300 |
|
224,400 |
|
10 |
% |
Western Oklahoma natural gas processed (Mcf/d) |
|
209,600 |
|
153,200 |
|
37 |
% |
210,800 |
|
156,600 |
|
35 |
% |
Western Oklahoma NGL sales (gallons, in thousands) |
|
50,900 |
|
37,000 |
|
38 |
% |
169,900 |
|
111,100 |
|
53 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southeast Oklahoma gathering systems throughput (Mcf/d) |
|
484,400 |
|
512,600 |
|
(6 |
)% |
496,200 |
|
507,500 |
|
(2 |
)% |
Southeast Oklahoma natural gas processed (Mcf/d) (2) |
|
128,600 |
|
105,400 |
|
22 |
% |
116,700 |
|
103,100 |
|
13 |
% |
Southeast Oklahoma NGL sales (gallons, in thousands) |
|
46,700 |
|
30,600 |
|
53 |
% |
121,000 |
|
92,100 |
|
31 |
% |
Arkoma Connector Pipeline throughput (Mcf/d) |
|
310,400 |
|
298,600 |
|
4 |
% |
323,400 |
|
294,300 |
|
10 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Southwest gathering system throughput (Mcf/d) |
|
23,600 |
|
29,900 |
|
(21 |
)% |
25,000 |
|
31,500 |
|
(21 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas processed (Mcf/d) (3) |
|
318,500 |
|
277,400 |
|
15 |
% |
322,800 |
|
300,700 |
|
7 |
% |
NGLs fractionated (Bbl/d) (4) |
|
16,500 |
|
19,300 |
|
(15 |
)% |
16,800 |
|
21,400 |
|
(21 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Keep-whole sales (gallons, in thousands) |
|
23,200 |
|
21,700 |
|
7 |
% |
96,500 |
|
82,600 |
|
17 |
% |
Percent-of-proceeds sales (gallons, in thousands) |
|
33,700 |
|
31,600 |
|
7 |
% |
103,500 |
|
95,600 |
|
8 |
% |
Total NGL sales (gallons, in thousands) (5) |
|
56,900 |
|
53,300 |
|
7 |
% |
200,000 |
|
178,200 |
|
12 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil transported for a fee (Bbl/d) |
|
8,700 |
|
9,900 |
|
(12 |
)% |
9,100 |
|
10,500 |
|
(13 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liberty |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas processed (Mcf/d) |
|
479,400 |
|
366,200 |
|
31 |
% |
424,300 |
|
306,700 |
|
38 |
% |
Gathering system throughput (Mcf/d) |
|
444,700 |
|
258,300 |
|
72 |
% |
373,700 |
|
228,900 |
|
63 |
% |
NGLs fractionated (Bbl/d) (6) |
|
22,300 |
|
12,400 |
|
80 |
% |
20,700 |
|
9,300 |
|
123 |
% |
NGL sales (gallons, in thousands) (7) |
|
90,800 |
|
61,100 |
|
49 |
% |
264,200 |
|
163,500 |
|
62 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast |
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery off-gas processed (Mcf/d) |
|
123,800 |
|
122,000 |
|
1 |
% |
120,000 |
|
113,200 |
|
6 |
% |
Liquids fractionated (Bbl/d) |
|
23,800 |
|
23,100 |
|
3 |
% |
23,000 |
|
21,400 |
|
7 |
% |
NGL sales (gallons excluding hydrogen, in thousands) |
|
92,100 |
|
89,200 |
|
3 |
% |
264,400 |
|
245,500 |
|
8 |
% |
(1) Includes natural gas gathered in Western Oklahoma and from the Granite Wash formation in the Texas Panhandle as it is one integrated area of operations.
(2) The natural gas processing in Southeast Oklahoma is outsourced to Centrahoma, our equity investment, or third-party processors.
(3) Includes throughput from the Kenova, Cobb, Boldman and Langley processing plants. We acquired the Langley processing plant in February 2011. The volumes reported for the nine months ended September 30, 2011 are the average daily rates for the days of operation.
(4) Amount includes zero barrels per day and 4,400 barrels per day fractionated on behalf of Liberty for the three months ended September 30, 2012 and 2011, respectively and includes zero barrels per day and 5,100 barrels per day fractionated on behalf of Liberty for the nine months ended September 30, 2012 and 2011, respectively. Beginning in the fourth quarter of 2011, Siloam no longer fractionates NGLs on behalf of Liberty due to the operation of Libertys fractionation facility that began in September 2011, except during outages or force majeure events.
(5) Represents sales from the Siloam facilities. The total sales exclude approximately 600,000 gallons and 17,100,000 gallons sold by the Northeast on behalf of Liberty for the three months ended September 30, 2012 and 2011, respectively and 975,000 gallons and 58,600,000 gallons sold for the nine months ended September 30, 2012 and 2011, respectively. These volumes are included as part of NGLs sold at Liberty.
(6) Amount includes all NGLs that were produced at the Liberty processing facilities and fractionated into purity products at our Liberty fractionation facility.
(7) Includes sale of all purity products fractionated at the Liberty facilities and sale of all unfractionated NGLs. Also includes the sale of purity products fractionated and sold from the Siloam facilities on behalf of Liberty.
Liquidity and Capital Resources
Our primary strategy is to expand our asset base through organic growth projects and selective third-party acquisitions that are accretive to our cash available for distribution per common unit.
Our 2012 capital plan is summarized in the table below (in millions):
|
|
|
|
Actual |
| ||
|
|
2012 Full Year Plan |
|
Nine months ended |
| ||
Consolidated growth capital (1) |
|
$ |
2,200 |
|
$ |
1,227 |
|
Utica joint venture partners estimated share of growth capital |
|
(400 |
) |
(55 |
) | ||
Partnership share of growth capital |
|
1,800 |
|
1,172 |
| ||
Acquisition (2) |
|
510 |
|
510 |
| ||
Partnership share of growth capital and acquisitions |
|
$ |
2,310 |
|
$ |
1,682 |
|
Consolidated maintenance capital (1) |
|
$ |
20 |
|
$ |
14 |
|
(1) Growth capital includes expenditures made to expand the existing operating capacity, to increase the efficiency of our existing assets, and to facilitate an increase in volumes within our operations. Growth capital also includes costs associated with new well connections. Growth capital excludes expenditures for third-party acquisitions and equity investments. Maintenance capital includes capital expenditures made to maintain our operating capacity and asset base.
(2) As discussed in Note 3 to the accompanying Condensed Consolidated Financial Statements, MarkWest Liberty Midstream and its wholly owned subsidiary acquired Keystone for a purchase price of approximately $509.6 million.
Management believes that the cash requirements to meet operating expenses and pay distributions to our unitholders will be funded by cash generated from our operations.
Management believes that expenditures for our currently planned capital projects will be funded with cash flows from operations, current cash balances, contributions by our joint venture partner for capital projects encompassed by MarkWest Utica EMG, our current borrowing capacity under the Credit Facility, additional long-term borrowings, and proceeds from equity or debt offerings. Our access to capital markets can be impacted by factors outside our control, which include but are not limited to general economic conditions and the rights of our Class B unitholders to participate in future equity offerings after July 1, 2013; 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 October 31, 2012, our credit ratings were Ba2 with a Stable outlook by Moodys Investors Service, BB with a Stable outlook by Standard & Poors, and BB with a Stable outlook by Fitch Ratings. 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 June 29, 2012, we amended our Credit Facility to increase the borrowing capacity to $1.2 billion and extend the maturity date by one year to September 7, 2017, providing us with the additional financial flexibility to continue to execute our growth strategy. See Note 9 of the accompanying Notes to Condensed Consolidated Financial Statements included in Item 1 of this Form 10-Q for further details of our Credit Facility.
Under the provisions of the Credit Facility, we are subject to a number of restrictions and covenants. As of September 30, 2012, we were in compliance with all of our debt covenants and we expect to remain in compliance for at least the next twelve months. These covenants are used to calculate the available borrowing capacity on a quarterly basis. As of October 31, 2012, we had no borrowings outstanding and approximately $21.6 million of letters of credit outstanding under the Credit Facility, leaving approximately $1,178.4 million available for borrowing.
The Credit Facility and indentures governing the Senior Notes limit our and our restricted subsidiaries activity and ability 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 our restricted subsidiaries to pay dividends or distributions, make loans or transfer property to us; engage in transactions with our affiliates; sell assets, including equity interests of our 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 also limits our ability to enter into transactions with parties that require margin calls under certain derivative instruments. The Credit Facility prevents participating bank group members from requiring margin calls. As of October 31, 2012, all of our derivative positions are with participating bank group members 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.
On August 10, 2012, we completed a public offering of $750 million in aggregate principal amount of 5.5% senior unsecured notes (2023 Senior Notes), which were issued at 99.015% of par. The 2023 Senior Notes mature on February 15, 2023, and interest is payable semi-annually in arrears on February 15 and August 15, commencing February 15, 2013. We received net proceeds of approximately $731 million from the 2023 Senior Notes offering after deducting the underwriting fees and other third-party expenses. We used a portion of the net proceeds from the offering to repay borrowings under our Credit Facility and the remainder were used for general partnership purposes, including, but not limited to, funding capital expenditures and general working capital.
Equity Offerings
During the first nine months of 2012, we completed three public offerings and issued approximately 22.4 million common units representing limited partner interests, which includes any units issued for the exercise of the underwriters over-allotment option. Net proceeds after deducting underwriting fees and other third-party offering expenses were approximately $1.2 billion and were used to fund the Keystone Acquisition, to partially fund the our on-going capital expenditure program, to fund general working capital requirements, and for other general partnership purposes.
Liquidity Risks and Uncertainties
Our ability to pay distributions to our unit-holders, 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.
Due to lower demand caused primarily by the mild winter at the end of 2011 and beginning of 2012, NGL prices have declined significantly in 2012 compared to 2011, which has adversely impacted our liquidity and operating results and will continue to have an adverse impact if price declines are sustained.
Additionally, we execute a risk management strategy to mitigate our exposure to downward fluctuations in commodity prices. We primarily use derivative financial instruments relating to the future price of crude oil to mitigate our exposure to NGL price risk. During the first nine months of 2012, the correlation between the price of NGLs and crude oil has weakened significantly and as
a result, our derivative financial instruments have not been as effective in offsetting the impact of NGL price declines. If the pricing relationship between crude oil and NGLs does not return to the historical correlation or continues to weaken, our derivative financial instruments will continue to be less effective.
Cash Flow
The following table summarizes cash inflows (outflows) (in thousands):
|
|
Nine months ended September 30, |
|
|
| |||||
|
|
2012 |
|
2011 |
|
Change |
| |||
Net cash provided by operating activities |
|
$ |
389,718 |
|
$ |
331,249 |
|
$ |
58,469 |
|
Net cash flows used in investing activities |
|
(1,746,071 |
) |
(587,686 |
) |
(1,158,385 |
) | |||
Net cash flows provided by financing activities |
|
1,654,401 |
|
348,164 |
|
1,306,237 |
| |||
Net cash provided by operating activities increased primarily due to a $41.9 million increase in operating income, excluding derivative gains and losses, in our operating segments. The increase in cash provided by operating activities was also due to changes in working capital.
Net cash used in investing activities increased primarily due to the $506.8 million net cash spent for the Keystone Acquisition which occurred in the second quarter of 2012 and a $880.9 million increase in capital expenditures primarily related to our expansion of Liberty operations, partially offset by the $230.7 million Langley Acquisition which occurred in the first quarter of 2011.
Net cash provided by financing activities increased primarily due to an $867.6 million increase in proceeds from public equity offerings and a $512.8 million increase in net borrowings, partially offset by an $88.2 million increase in distributions to unit holders.
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, 2012, our purchase obligations for the remainder of 2012 were $507.0 million compared to our 2012 obligations of $181.0 million as of December 31, 2011. The increase is due primarily to obligations related to the ongoing expansion in our Liberty segment. Purchase obligations represent purchase orders and contracts related to property, plant and equipment.
Effective July 2012, we amended our lease for our corporate offices in Denver, Colorado to include additional space and extend the term of the lease through 2024. The following table shows the increase in minimum future lease payments as of September 30, 2012 compared to the amount disclosed in Item 7 of the Form 10-K for the year ended December 31, 2011 (in thousands):
Payments Due by Period |
|
|
| |
Due in 2012 |
|
$ |
569 |
|
Due in 2013-2014 |
|
8,290 |
| |
Due in 2015-2016 |
|
8,673 |
| |
Thereafter |
|
58,221 |
| |
Total Obligation |
|
$ |
75,753 |
|
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 identified intangible assets; evaluating impairments of long-lived assets, goodwill and equity investments; risk management activities and derivative financial instruments; VIEs; and acquisitions.
There have not been any material changes during the nine months ended September 30, 2012 to the methodology applied by management for critical accounting policies previously disclosed in Item 7. Managements Discussion and Analysis of Financial
Condition and Results of OperationsCritical Accounting Policies in our Annual Report on Form 10-K for the year ended December 31, 2011.
Recent Accounting Pronouncements
Refer to Note 2 of the accompanying Notes to the Condensed Consolidated Financial Statements for information regarding recent accounting pronouncements.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity price changes and, to a lesser extent, interest rate changes and nonperformance by our customers and counterparties.
Commodity Price Risk
The information about commodity price risk for the nine months ended September 30, 2012 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, 2011.
Outstanding Derivative Contracts
The following table provides information on the volume of our derivative activity for positions related to long liquids and keep-whole price risk at September 30, 2012, including the weighted average prices (WAVG):
WTI Crude Collars |
|
Volumes |
|
WAVG Floor |
|
WAVG Cap |
|
Fair Value |
| |||
2012 |
|
3,364 |
|
$ |
78.84 |
|
$ |
99.73 |
|
$ |
(509 |
) |
2013 |
|
3,714 |
|
88.08 |
|
107.45 |
|
4,008 |
| |||
2014 |
|
1,418 |
|
90.36 |
|
108.73 |
|
2,968 |
| |||
WTI Crude Swaps |
|
Volumes |
|
WAVG Price |
|
Fair Value |
| ||
2012 |
|
7,111 |
|
$ |
86.81 |
|
$ |
(3,730 |
) |
2013 |
|
5,416 |
|
93.48 |
|
(155 |
) | ||
2014 (Jul - Dec) |
|
573 |
|
93.17 |
|
238 |
| ||
Natural Gas Swaps |
|
Volumes |
|
WAVG Price |
|
Fair Value |
| ||
2012 |
|
16,435 |
|
$ |
4.34 |
|
$ |
(1,795 |
) |
2013 |
|
1,453 |
|
4.66 |
|
(527 |
) | ||
The following tables provide information on the volume of our taxable subsidiarys commodity derivative activity for positions related to keep-whole price risk at September 30, 2012, including the WAVG:
WTI Crude Collars |
|
Volumes |
|
WAVG Floor |
|
WAVG Cap |
|
Fair Value |
| |||
2012 |
|
1,624 |
|
$ |
82.00 |
|
$ |
106.48 |
|
$ |
49 |
|
WTI Crude Swaps |
|
Volumes |
|
WAVG Price |
|
Fair Value |
| ||
2012 |
|
2,368 |
|
$ |
86.84 |
|
$ |
(1,295 |
) |
2013 |
|
1,304 |
|
94.32 |
|
347 |
| ||
Natural Gas Swaps |
|
Volumes |
|
WAVG Price |
|
Fair Value |
| ||
2012 |
|
14,130 |
|
$ |
6.18 |
|
$ |
(3,689 |
) |
2013 |
|
9,793 |
|
5.34 |
|
(5,239 |
) | ||
2014 |
|
4,249 |
|
5.69 |
|
(2,301 |
) | ||
Propane Swaps |
|
Volumes |
|
WAVG Price |
|
Fair Value |
| ||
2013 (Jan-Mar, Oct-Dec) |
|
36,885 |
|
$ |
1.29 |
|
$ |
2,164 |
|
2014 (Jan-Mar, Oct-Dec) |
|
87,837 |
|
1.25 |
|
4,266 |
| ||
IsoButane Swaps |
|
Volumes |
|
WAVG Price |
|
Fair Value |
| ||
2013 |
|
3,081 |
|
$ |
1.70 |
|
$ |
89 |
|
2014 |
|
3,885 |
|
1.67 |
|
56 |
| ||
Normal Butane Swaps |
|
Volumes |
|
WAVG Price |
|
Fair Value |
| ||
2013 |
|
8,512 |
|
$ |
1.61 |
|
$ |
517 |
|
2014 |
|
10,711 |
|
1.61 |
|
625 |
| ||
Natural Gasoline Swaps |
|
Volumes |
|
WAVG Price |
|
Fair Value |
| ||
2013 |
|
5,600 |
|
$ |
2.26 |
|
$ |
540 |
|
2014 |
|
7,106 |
|
2.32 |
|
1,029 |
| ||
Propane Fixed Physical |
|
Volumes |
|
WAVG Price |
|
Fair Value |
| ||
2012 |
|
1,413 |
|
$ |
1.01 |
|
$ |
10 |
|
2013 (Jan-Mar) |
|
5,222 |
|
1.02 |
|
35 |
| ||
The following tables provide information on the volume of MarkWest Liberty Midstreams commodity derivative activity for positions related to long liquids price risk at September 30, 2012, including the WAVG:
WTI Crude Collars |
|
Volumes |
|
WAVG Floor |
|
WAVG Cap |
|
Fair Value |
| |||
2012 |
|
700 |
|
$ |
90.00 |
|
$ |
109.13 |
|
$ |
138 |
|
2013 |
|
1,062 |
|
89.33 |
|
106.78 |
|
1,271 |
| |||
Propane Swaps |
|
Volumes |
|
WAVG Price |
|
Fair Value |
| ||
2012 |
|
73,155 |
|
$ |
0.89 |
|
$ |
(246 |
) |
2013 (Jan-Mar) |
|
30,897 |
|
0.86 |
|
(238 |
) | ||
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 commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. This contract is accounted for as an embedded derivative and is recorded at fair value. The changes in fair value of this commodity contract are based on the difference between the contractual and index pricing and are recorded in earnings through Derivative gain (loss) related to purchased product costs. In February 2011, we executed agreements with the producer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022. As of September 30, 2012, the estimated fair value of this contract was a liability of $87.9 million and the recorded value was a liability of $34.4 million. The recorded liability does not include the inception fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception on February 1, 2011 is deemed to be allocable to the host processing contract and therefore not
recorded as a derivative liability. See the following table for a reconciliation of the liability recorded for the embedded derivative as of September 30, 2012 (in thousands):
Fair value of commodity contract |
|
$ |
87,863 |
|
Inception value for period from April 1, 2015 to December 31, 2022 |
|
(53,507 |
) | |
Derivative liability as of September 30, 2012 |
|
$ |
34,356 |
|
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 through the fourth quarter of 2014. The value of the derivative component of this contract is marked to market through Derivative gain (loss) related to facility expenses. As of September 30, 2012, the estimated fair value of this contract was an asset of $6.4 million.
Interest Rate Risk
The information about interest rate risk for the nine months ended September 30, 2012 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, 2011.
Credit Risk
The information about our credit risk for the nine months ended September 30, 2012 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, 2011.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
An evaluation was performed under the supervision and with the participation of the Partnerships 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, 2012. Based on this evaluation, the Partnerships management, including our Chief Executive Officer and Chief Financial Officer, concluded that as of September 30, 2012, 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 SECs 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, 2012 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
MarkWest Liberty Midstream & Resources, L.L.C. (MarkWest Liberty Midstream) received a draft Consent Order dated August 14, 2012 from the West Virginia Department of Environmental Protection (WVDEP) alleging violations of West Virginias stormwater and erosion and sediment control regulations in connection with the construction of MarkWest Liberty Midstreams Mobley processing complex near Mobley, West Virginia. The draft Consent Order asserts a civil administrative penalty in the amount of approximately $380,000 as well as requests that MarkWest submit corrective action and stream restoration plans. The Partnership
believes that it has viable and mitigating defenses to the alleged violations and will vigorously defend against the draft Consent Order and the allegations made by the WVDEP.
Refer to Note 11 of the accompanying Notes to the Condensed Consolidated Financial Statements for all other information regarding legal proceedings.
In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2011, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no significant changes to our risk factors as set forth in our Annual Report on form 10-K for the year ended December 31, 2011, except for the additional or updated risk factors set forth below:
Recently approved final rules regulating air emissions from natural gas processing operations could cause us to incur increased capital expenditures and operating costs, which may be significant.
On April 17, 2012, the EPA approved final rules that establish new air emission controls for natural gas and NGLs production, processing and transportation activities, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with production and processing activities. Among other things, the rules establish specific requirements regarding emissions from compressors and controllers at natural gas gathering and boosting stations and processing plants together with dehydrators and storage tanks at natural gas processing plants, compressor stations and gathering and boosting stations. In addition, the rules establish new requirements for leak detection and repair of leaks at natural gas processing plants that exceed 500 parts per million in concentration. We are currently reviewing this new rule and assessing its potential impacts. Compliance with these requirements may require modifications to certain of our operations, including the installation of new equipment to control emissions from our compressors that could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.
Our commodity derivative activities may reduce our earnings, profitability and cash flows.
Our operations expose us to fluctuations in commodity prices. We utilize derivative financial instruments related to the future price of crude oil, natural gas and certain NGLs with the intent of reducing volatility in our cash flows due to fluctuations in commodity prices.
The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. We have a policy to enter into derivative transactions related to only a portion of the volume of our expected production or fuel requirements and, as a result, we expect to continue to have some direct commodity price exposure. Our actual future production or fuel requirements may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to settle all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, which could result in a substantial diminution of our liquidity. Alternatively, we may seek to amend the terms of our derivative financial instruments, including to extend the settlement date of such instruments. Additionally, because we use derivative financial instruments relating to the future price of crude oil to mitigate our exposure to NGL price risk, the volatility of our future cash flows and net income may increase if there is a change in the pricing relationship between crude oil and NGLs. As a result of these factors, our risk management activities may not be as effective as we intend in reducing the downside volatility of our cash flows and, in certain circumstances, may actually increase the volatility of our cash flows. In addition, our risk management activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect and our risk management policies and procedures are not properly followed. It is possible that the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.
4.1(1) |
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Eighth Supplemental Indenture, dated as of August 10, 2012, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee. |
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|
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4.2(1) |
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Form of 5.5% Senior Notes due 2023 with attached notation of Guarantees (incorporated by reference to Exhibits A and B of Exhibit 4.1). |
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|
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31.1* |
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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. |
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31.2* |
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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. |
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32.1* |
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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. |
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32.2* |
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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. |
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|
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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, 2012, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Statements of Operations, (ii) Condensed Consolidated Balance Sheets, (iii) Condensed Consolidated Statements of Cash Flows, (iv) Condensed Consolidated Statements of Changes in Equity, and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text. |
* Filed herewith
+ Application has been made to the Securities and Exchange Commission for confidential treatment of certain provisions of these exhibits. Omitted material for which confidential treatment has been requested and has been filed separately with the Securities and Exchange Commission.
(1) Incorporated by reference to the Current Report on Form 8-K filed August 10, 2012.
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.
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MarkWest Energy Partners, L.P. | |
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(Registrant) | |
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| |
|
By: |
MarkWest Energy GP, L.L.C., |
|
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Its General Partner |
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| |
|
| |
Date: November 7, 2012 |
/s/ FRANK M. SEMPLE | |
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Frank M. Semple | |
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Chairman, President & Chief Executive Officer | |
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(Principal Executive Officer) | |
|
| |
|
| |
Date: November 7, 2012 |
/s/ NANCY K. BUESE | |
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Nancy K. Buese | |
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Senior Vice President & Chief Financial Officer | |
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(Principal Financial Officer) | |
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| |
|
| |
Date: November 7, 2012 |
/s/ PAULA L. ROSSON | |
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Paula L. Rosson | |
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Vice President & Chief Accounting Officer | |
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(Principal Accounting Officer) |
Exhibit 31.1
CERTIFICATION
I, Frank M. Semple, certify that:
1. I have reviewed this quarterly report on Form 10-Q of MarkWest Energy Partners, L.P.
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report.
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report.
4. The registrants other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f), for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c) Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and
5. The registrants other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of registrants board of directors (or persons performing the equivalent function):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting.
Date: November 7, 2012 |
By: |
/s/ FRANK M. SEMPLE |
|
|
Frank M. Semple |
|
|
Chairman, President and Chief Executive Officer |
|
|
(Principal Executive Officer) |
Exhibit 31.2
CERTIFICATION
I, Nancy K. Buese, certify that:
1. I have reviewed this quarterly report on Form 10-Q of MarkWest Energy Partners, L.P.
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report.
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report.
4. The registrants other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f), for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c) Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and
5. The registrants other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of registrants board of directors (or persons performing the equivalent function):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting.
Date: November 7, 2012 |
By: |
/s/ NANCY K. BUESE |
|
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Nancy K. Buese |
|
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Senior Vice President & Chief Financial Officer |
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(Principal Financial Officer) |
Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of MarkWest Energy Partners, L.P. (the Partnership), on Form 10-Q for the period ending September 30, 2012, as filed with the Securities and Exchange Commission on the date hereof (the Report), I, Frank M. Semple, Chief Executive Officer of the General Partner of the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:
(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership.
Date: November 7, 2012 |
By: |
/s/ FRANK M. SEMPLE |
|
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Frank M. Semple |
|
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Chairman, President and Chief Executive Officer |
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(Principal Executive Officer) |
This certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document. This certification shall not be deemed filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the Exchange Act), or otherwise subject to liability under that section. This certification shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act except to the extent this Exhibit 32.1 is expressly and specifically incorporated by reference in any such filing.
A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.
Exhibit 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of MarkWest Energy Partners, L.P. (the Partnership) on Form 10-Q for the period ending September 30, 2012, as filed with the Securities and Exchange Commission on the date hereof (the Report), I, Nancy K. Buese, Chief Financial Officer of the General Partner of the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:
(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership.
Date: November 7, 2012 |
By: |
/s/ NANCY K. BUESE |
|
|
Nancy K. Buese |
|
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Senior Vice President & Chief Financial Officer |
|
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(Principal Financial Officer) |
This certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document. This certification shall not be deemed filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the Exchange Act), or otherwise subject to liability under that section. This certification shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act except to the extent this Exhibit 32.2 is expressly and specifically incorporated by reference in any such filing.
A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.
Commitments and Contingencies (Details) (USD $)
|
9 Months Ended |
---|---|
Sep. 30, 2012
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Contract Contingencies
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Commitments and Contingencies | |
Charges if milestones are not achieved | $ 1,000,000 |
Contract Contingencies | Maximum
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Commitments and Contingencies | |
Maximum period of delay | 6 months |
Lease amendment
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|
Commitments and Contingencies | |
2012 | 569,000 |
2013 | 4,295,000 |
2014 | 3,995,000 |
2015 | 3,926,000 |
2016 | 4,747,000 |
2017 and thereafter | 58,221,000 |
Total | $ 75,753,000 |
Long-Term Debt (Details) (USD $)
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9 Months Ended | 9 Months Ended | 1 Months Ended | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Sep. 30, 2012
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Sep. 30, 2011
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Dec. 31, 2011
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Sep. 30, 2012
Credit Facility
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Jun. 29, 2012
Credit Facility
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Dec. 31, 2011
Credit Facility
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Sep. 30, 2012
Senior Notes
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Dec. 31, 2011
Senior Notes
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Sep. 30, 2012
2018 Senior Notes, 8.75% interest, issued April and May 2008 and due April 2018
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Dec. 31, 2011
2018 Senior Notes, 8.75% interest, issued April and May 2008 and due April 2018
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Sep. 30, 2012
2020 Senior Notes, 6.75% interest, issued November 2010 and due November 2020
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Dec. 31, 2011
2020 Senior Notes, 6.75% interest, issued November 2010 and due November 2020
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Sep. 30, 2012
2021 Senior Notes, 6.5% interest, issued February and March 2011 and due August 2021
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Dec. 31, 2011
2021 Senior Notes, 6.5% interest, issued February and March 2011 and due August 2021
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Sep. 30, 2012
2022 Senior Notes, 6.25% interest, issued October 2011 and due June 2022
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Dec. 31, 2011
2022 Senior Notes, 6.25% interest, issued October 2011 and due June 2022
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Aug. 31, 2012
2023 Senior Notes, 5.5% interest, issued August 2012 and due February 2023
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Sep. 30, 2012
2023 Senior Notes, 5.5% interest, issued August 2012 and due February 2023
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Aug. 10, 2012
2023 Senior Notes, 5.5% interest, issued August 2012 and due February 2023
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Long-Term Debt | |||||||||||||||||||
Long-term debt, net of discounts | $ 2,522,854,000 | $ 1,846,062,000 | $ 66,000,000 | $ 80,998,000 | $ 80,983,000 | $ 500,000,000 | $ 500,000,000 | $ 499,151,000 | $ 499,079,000 | $ 700,000,000 | $ 700,000,000 | $ 742,705,000 | |||||||
Debt instrument, stated interest rate percentage | 4.25% | 8.75% | 6.75% | 6.50% | 6.25% | 5.50% | 5.50% | ||||||||||||
Long-term debt, discounts | 8,258,000 | 1,050,000 | 114,000 | 129,000 | 849,000 | 921,000 | 7,295,000 | ||||||||||||
Estimate aggregate fair value of debt | 2,706,700,000 | 1,880,700,000 | |||||||||||||||||
Credit facility current lending capacity | 1,200,000,000 | ||||||||||||||||||
Accordion option to increase borrowing capacity under the Credit Facility | 250,000,000 | ||||||||||||||||||
Deferred financing costs associated with modifications of the Credit Facility | 14,184,000 | 7,795,000 | 2,500,000 | ||||||||||||||||
Extension of maturity date | 1 year | ||||||||||||||||||
Letters of credit outstanding amount | 21,600,000 | ||||||||||||||||||
Credit facility remaining borrowing capacity | 1,178,400,000 | ||||||||||||||||||
Aggregate principal amount of debt issued | 750,000,000 | ||||||||||||||||||
Issue price as percentage of par value | 99.015% | ||||||||||||||||||
Proceeds from issuance of senior notes, net of underwriting fees and the other expenses of the offering | $ 731,000,000 |
Earnings (Loss) Per Common Unit (Tables)
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9 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Sep. 30, 2012
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Earnings (Loss) Per Common Unit | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Computation of basic and diluted net income (loss) per common unit |
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Supplemental Cash Flow Information (Details) (USD $)
In Thousands, unless otherwise specified |
9 Months Ended | |
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Sep. 30, 2012
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Sep. 30, 2011
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Supplemental Cash Flow Information | ||
Cash paid for interest, net of amounts capitalized | $ 73,624 | $ 76,876 |
Cash paid for income taxes, net | 18,925 | 5,051 |
Supplemental schedule of non-cash investing and financing activities: | ||
Accrued property, plant and equipment | 389,601 | 85,666 |
Interest capitalized on construction in progress | 16,353 | 571 |
Issuance of common units for vesting of share-based payment awards | $ 2,506 | $ 5,412 |
Derivative Financial Instruments (Tables)
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9 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Sep. 30, 2012
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Derivative Financial Instruments | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Volume of Derivative Activity |
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Reconciliation of liability recorded for embedded derivative |
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Derivative contracts not designated as hedging instruments |
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Business Combination (Details) (Keystone Acquisition, USD $)
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9 Months Ended | |
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Sep. 30, 2012
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May 29, 2012
sqmi
MMcf
item
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Keystone Acquisition
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Business Combination | ||
Purchase price | $ 509,600,000 | $ 509,600,000 |
Number of cryogenic natural gas processing plants acquired | 2 | |
Capacity of cryogenic natural gas processing plant (in MMcf/d) | 90 | |
Area of land (in square miles) | 900 | |
Assets | ||
Cash | 2,837,000 | |
Accounts receivable | 1,756,000 | |
Property, plant and equipment | 136,593,000 | |
Goodwill | 76,664,000 | |
Intangible asset | 304,708,000 | |
Liabilities | ||
Accounts payable | (12,117,000) | |
Other short-term liabilities | (175,000) | |
Other long-term liabilities | (632,000) | |
Total | $ 509,634,000 | |
Estimated useful life of intangibles | 19 years |
Segment Information (Details 2) (USD $)
In Thousands, unless otherwise specified |
3 Months Ended | 9 Months Ended | ||
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Sep. 30, 2012
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Sep. 30, 2011
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Sep. 30, 2012
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Sep. 30, 2011
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Segment information | ||||
Revenue | $ 320,137 | $ 400,883 | $ 1,029,304 | $ 1,109,632 |
Derivative gain (loss) not allocated to segments | (36,400) | 106,943 | 50,952 | 61,854 |
Revenue deferral adjustment | (1,635) | (2,489) | (5,604) | (12,854) |
Total revenue | 283,737 | 507,826 | 1,080,256 | 1,171,486 |
Selling, general and administrative expenses | (21,922) | (20,162) | (69,025) | (60,454) |
Depreciation | (48,136) | (38,715) | (132,199) | (110,280) |
Amortization of intangible assets | (14,988) | (10,985) | (38,280) | (32,632) |
Loss on disposal of property, plant and equipment | (655) | (147) | (2,983) | (4,619) |
Accretion of asset retirement obligations | (141) | (557) | (540) | (934) |
Income from operations | 9,562 | 207,801 | 319,903 | 325,721 |
Earnings (loss) from unconsolidated affiliate | 246 | (507) | 788 | (1,262) |
Interest income | 64 | 62 | 295 | 214 |
Interest expense | (30,621) | (26,899) | (86,855) | (83,036) |
Amortization of deferred financing costs and discount (a component of interest expense) | (1,428) | (1,002) | (3,943) | (3,873) |
Loss on redemption of debt | (133) | (43,461) | ||
Miscellaneous income, net | 1 | (4) | 63 | 127 |
(Loss) Income before provision for income tax | (22,176) | 179,318 | 230,251 | 194,430 |
Total reportable segments
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Segment information | ||||
Revenue | 321,772 | 403,372 | 1,034,908 | 1,122,486 |
Portion of operating income (loss) attributable to non-controlling interests | 916 | 19,450 | 3,839 | 49,527 |
Income from operations | 145,524 | 147,810 | 485,976 | 444,034 |
Southwest Segment
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Segment information | ||||
Revenue | 181,456 | 241,998 | 585,343 | 679,347 |
Revenue deferral adjustment | 200 | 200 | 600 | 6,900 |
Portion of operating income (loss) attributable to non-controlling interests | 1,543 | 1,227 | 4,579 | 3,745 |
Income from operations | 67,274 | 78,661 | 226,074 | 240,296 |
Northeast Segment
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Segment information | ||||
Revenue | 39,987 | 55,920 | 168,956 | 201,687 |
Revenue deferral adjustment | 1,400 | 2,300 | 5,000 | 5,900 |
Income from operations | 22,666 | 33,094 | 101,717 | 109,758 |
Unallocated Segment
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Segment information | ||||
Derivative gain (loss) not allocated to segments | (52,071) | 111,004 | 70,952 | 46,859 |
Revenue deferral adjustment | (1,635) | (2,489) | (5,604) | (12,854) |
Compensation expense included in facility expenses not allocated to segments | (193) | (263) | (826) | (1,491) |
Facility expenses adjustments | $ 2,863 | $ 2,855 | $ 8,593 | $ 8,565 |
Equity (Details) (USD $)
In Thousands, except Per Share data, unless otherwise specified |
1 Months Ended | 3 Months Ended | 9 Months Ended | |||||||
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Aug. 31, 2012
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May 31, 2012
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Mar. 31, 2012
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Jan. 31, 2012
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Sep. 30, 2012
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Jun. 30, 2012
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Mar. 31, 2012
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Dec. 31, 2011
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Sep. 30, 2012
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Sep. 30, 2011
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Equity Offerings | ||||||||||
Issuance of units in public offering, net of offering costs (in units) | 6,900 | 8,000 | 6,800 | 700 | ||||||
Net proceeds from public offering after deducting underwriters fees and other third-party expenses | $ 338,000 | $ 427,000 | $ 388,000 | $ 38,000 | $ 1,191,066 | $ 323,492 | ||||
Distributions of Available Cash and Range of Unit Prices | ||||||||||
Distribution per common unit (in dollars per unit) | $ 0.81 | $ 0.80 | $ 0.79 | $ 0.76 | ||||||
Declaration Date | Oct. 25, 2012 | Jul. 26, 2012 | Apr. 26, 2012 | Jan. 26, 2012 | ||||||
Record Date | Nov. 07, 2012 | Aug. 06, 2012 | May 07, 2012 | Feb. 06, 2012 | ||||||
Payment Date | Nov. 14, 2012 | Aug. 14, 2012 | May 15, 2012 | Feb. 14, 2012 | ||||||
Minimum
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Equity | ||||||||||
Common Unit Price (in dollars per share) | $ 53.51 | $ 49.01 | $ 45.36 | $ 53.51 | $ 42.18 | $ 49.01 | ||||
Maximum
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Equity | ||||||||||
Common Unit Price (in dollars per share) | $ 61.60 | $ 55.04 | $ 60.32 | $ 61.60 | $ 56.82 | $ 55.04 |
Business Combination
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9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Sep. 30, 2012
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Business Combination | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Combination |
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