XNYS:MWE MarkWest Energy Partners LP Quarterly Report 10-Q Filing - 3/31/2012

Effective Date 3/31/2012

XNYS:MWE Fair Value Estimate
Premium
XNYS:MWE Consider Buying
Premium
XNYS:MWE Consider Selling
Premium
XNYS:MWE Fair Value Uncertainty
Premium
XNYS:MWE Economic Moat
Premium
XNYS:MWE Stewardship
Premium
 

Table of Contents

 

 

 

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 March 31, 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
incorporation or organization)

 

(IRS Employer
Identification No.)

 

1515 Arapahoe Street, Tower 1, Suite 1600, Denver, Colorado 80202-2137

(Address of principal executive offices)

 

Registrant’s telephone number, including area code: 303-925-9200

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes 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 April 30, 2012, the number of the registrant’s common units and Class B units outstanding were 102,693,615 and 19,954,389, respectively.

 

 

 



Table of Contents

 

    

PART I—FINANCIAL INFORMATION

 

 

 

 

Item 1.

Financial Statements

2

 

Unaudited Condensed Consolidated Balance Sheets at March 31, 2012 and December 31, 2011

2

 

Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2012 and 2011

3

 

Unaudited Condensed Consolidated Statements of Changes in Equity for the three months ended March 31, 2012 and 2011

4

 

Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2012 and 2011

5

 

Unaudited Notes to the Condensed Consolidated Financial Statements

6

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

26

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

38

Item 4.

Controls and Procedures

40

 

 

 

PART II—OTHER INFORMATION

 

Item 1.

Legal Proceedings

41

Item 1A.

Risk Factors

41

Item 6.

Exhibits

43

SIGNATURES

44

 

Throughout this document we make statements that are classified as “forward-looking.” Please refer to the “Forward-Looking Statements” included in Part I, Item 2 for an explanation of these types of assertions. Also, in this document, unless the context requires otherwise, references to “we,” “us,” “our,” “MarkWest Energy” or the “Partnership” are intended to mean MarkWest Energy Partners, L.P., and its consolidated subsidiaries. References to “MarkWest Hydrocarbon” or the “Corporation” are intended to mean MarkWest Hydrocarbon, Inc., a wholly-owned taxable subsidiary of the Partnership. References to “General Partner” are intended to mean MarkWest Energy GP, L.L.C., the general partner of the Partnership.

 



Table of Contents

 

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

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

IFRS

 

International Financial Reporting Standards

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, excluding any derivative gain (loss), less purchased product costs, excluding any derivative gain (loss)

NGL

 

Natural gas liquids, such as ethane, propane, butanes and natural gasoline

N/A

 

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

 

1



Table of Contents

 

PART I—FINANCIAL INFORMATION

 

Item 1.  Financial Statements

 

MARKWEST ENERGY PARTNERS, L.P.

 

Condensed Consolidated Balance Sheets

 

(unaudited, in thousands)

 

 

 

March 31, 2012

 

December 31, 2011

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents ($2,460 and $2,684, respectively)

 

$

350,634

 

$

117,016

 

Restricted cash

 

25,238

 

26,193

 

Receivables, net ($1,540 and $1,569, respectively)

 

197,115

 

226,561

 

Inventories

 

17,205

 

41,006

 

Fair value of derivative instruments

 

3,797

 

8,698

 

Deferred income taxes

 

14,885

 

14,885

 

Other current assets ($122 and $169, respectively)

 

8,197

 

11,748

 

Total current assets

 

617,071

 

446,107

 

 

 

 

 

 

 

Property, plant and equipment ($161,716 and $156,808, respectively)

 

3,568,459

 

3,302,369

 

Less: accumulated depreciation ($17,115 and $15,551, respectively)

 

(478,771

)

(438,062

)

Total property, plant and equipment, net

 

3,089,688

 

2,864,307

 

 

 

 

 

 

 

Other long-term assets:

 

 

 

 

 

Investment in unconsolidated affiliate

 

26,944

 

27,853

 

Intangibles, net of accumulated amortization of $179,153 and $168,168, respectively

 

592,782

 

603,767

 

Goodwill

 

67,918

 

67,918

 

Deferred financing costs, net of accumulated amortization of $14,462 and $13,194, respectively

 

40,530

 

41,798

 

Deferred contract cost, net of accumulated amortization of $2,340 and $2,262, respectively

 

910

 

988

 

Fair value of derivative instruments

 

8,270

 

16,092

 

Other long-term assets ($102 and $102, respectively)

 

1,534

 

1,595

 

Total assets

 

$

4,445,647

 

$

4,070,425

 

 

 

 

 

 

 

LIABILITIES AND EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable ($140 and $96, respectively)

 

$

182,149

 

$

179,871

 

Accrued liabilities ($1,898 and $1,144, respectively)

 

215,930

 

171,451

 

Fair value of derivative instruments

 

105,648

 

90,551

 

Total current liabilities

 

503,727

 

441,873

 

 

 

 

 

 

 

Deferred income taxes

 

99,783

 

93,664

 

Fair value of derivative instruments

 

85,800

 

65,403

 

Long-term debt, net of discounts of $1,021 and $1,050, respectively

 

1,780,091

 

1,846,062

 

Other long-term liabilities ($75 and $73, respectively)

 

123,945

 

121,356

 

 

 

 

 

 

 

Commitments and contingencies (Note 9)

 

 

 

 

 

 

 

 

 

 

 

Equity:

 

 

 

 

 

Common units (102,694 and 94,940 common units issued and outstanding, respectively)

 

1,030,497

 

679,309

 

Class B units (19,954 units issued and outstanding)

 

752,531

 

752,531

 

Non-controlling interest in consolidated subsidiaries

 

69,273

 

70,227

 

 

 

 

 

 

 

Total equity

 

1,852,301

 

1,502,067

 

Total liabilities and equity

 

$

4,445,647

 

$

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.

 

2



Table of Contents

 

MARKWEST ENERGY PARTNERS, L.P.

 

Condensed Consolidated Statements of Operations

 

(unaudited, in thousands, except per unit amounts)

 

 

 

Three months ended March 31,

 

 

 

2012

 

2011

 

Revenue:

 

 

 

 

 

Revenue

 

$

399,181

 

$

348,900

 

Derivative loss

 

(48,715

)

(85,679

)

Total revenue

 

350,466

 

263,221

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

Purchased product costs

 

154,555

 

153,629

 

Derivative loss related to purchased product costs

 

18,800

 

19,394

 

Facility expenses

 

48,840

 

39,424

 

Derivative gain related to facility expenses

 

(1,746

)

(3,011

)

Selling, general and administrative expenses

 

25,224

 

21,712

 

Depreciation

 

41,145

 

34,364

 

Amortization of intangible assets

 

10,985

 

10,817

 

Loss on disposal of property, plant and equipment

 

986

 

2,099

 

Accretion of asset retirement obligations

 

238

 

87

 

Total operating expenses

 

299,027

 

278,515

 

 

 

 

 

 

 

Income (loss) from operations

 

51,439

 

(15,294

)

 

 

 

 

 

 

Other income (expense):

 

 

 

 

 

Loss from unconsolidated affiliate

 

(9

)

(539

)

Interest income

 

72

 

89

 

Interest expense

 

(29,472

)

(28,263

)

Amortization of deferred financing costs and discount (a component of interest expense)

 

(1,270

)

(1,428

)

Loss on redemption of debt

 

 

(43,328

)

Miscellaneous income (expense), net

 

58

 

(38

)

Income (loss) before provision for income tax

 

20,818

 

(88,801

)

 

 

 

 

 

 

Provision for income tax expense (benefit):

 

 

 

 

 

Current

 

15,341

 

56

 

Deferred

 

(10,796

)

(14,186

)

Total provision for income tax

 

4,545

 

(14,130

)

 

 

 

 

 

 

Net income (loss)

 

16,273

 

(74,671

)

 

 

 

 

 

 

Net income attributable to non-controlling interest

 

(253

)

(9,358

)

 

 

 

 

 

 

Net income (loss) attributable to the Partnership

 

$

16,020

 

$

(84,029

)

 

 

 

 

 

 

Net income (loss) attributable to the Partnership’s common unitholders per common unit (Note 11):

 

 

 

 

 

Basic

 

$

0.16

 

$

(1.13

)

Diluted

 

$

0.14

 

$

(1.13

)

 

 

 

 

 

 

Weighted average number of outstanding common units:

 

 

 

 

 

Basic

 

96,840

 

74,531

 

Diluted

 

117,593

 

74,531

 

 

 

 

 

 

 

Cash distribution declared per common unit

 

$

0.76

 

$

0.65

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

3



Table of Contents

 

MARKWEST ENERGY PARTNERS, L.P.

 

Condensed Consolidated Statements of Changes in Equity

 

(unaudited, in thousands)

 

 

 

Common Units

 

Class B Units

 

Non-controlling

 

 

 

 

 

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

 

7,508

 

425,629

 

 

 

 

425,629

 

Distributions paid

 

 

(73,410

)

 

 

(1,962

)

(75,372

)

Contributions from non-controlling interest

 

 

 

 

 

755

 

755

 

Share-based compensation activity

 

246

 

(2,343

)

 

 

 

(2,343

)

Excess tax benefits related to share-based compensation

 

 

2,207

 

 

 

 

2,207

 

Deferred income tax impact from changes in equity

 

 

(16,915

)

 

 

 

(16,915

)

Net income

 

 

16,020

 

 

 

253

 

16,273

 

March 31, 2012

 

102,694

 

$

1,030,497

 

19,954

 

$

752,531

 

$

69,273

 

$

1,852,301

 

 

 

 

Common Units

 

Non-controlling

 

 

 

 

 

Units

 

Amounts

 

Interest

 

Total

 

December 31, 2010

 

71,440

 

$

993,049

 

$

465,517

 

$

1,458,566

 

Share-based compensation activity

 

270

 

314

 

 

314

 

Excess tax benefits related to share-based compensation

 

 

1,096

 

 

1,096

 

Distributions paid

 

 

(49,274

)

(13,568

)

(62,842

)

Issuance of units in public offering, net of offering costs

 

3,450

 

138,163

 

 

138,163

 

Contributions to MarkWest Liberty Midstream joint venture

 

 

 

8,000

 

8,000

 

Net (loss) income

 

 

(84,029

)

9,358

 

(74,671

)

March 31, 2011

 

75,160

 

$

999,319

 

$

469,307

 

$

1,468,626

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

4



Table of Contents

 

MARKWEST ENERGY PARTNERS, L.P.

 

Condensed Consolidated Statements of Cash Flows

 

(unaudited, in thousands)

 

 

 

Three months ended March 31,

 

 

 

2012

 

2011

 

Cash flows from operating activities:

 

 

 

 

 

Net income (loss)

 

$

16,273

 

$

(74,671

)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

Depreciation

 

41,145

 

34,364

 

Amortization of intangible assets

 

10,985

 

10,817

 

Loss on redemption of debt

 

 

43,328

 

Amortization of deferred financing costs and discount

 

1,270

 

1,428

 

Accretion of asset retirement obligations

 

238

 

87

 

Amortization of deferred contract cost

 

78

 

78

 

Phantom unit compensation expense

 

5,709

 

5,636

 

Equity in loss of unconsolidated affiliate

 

9

 

539

 

Distributions from unconsolidated affiliate

 

900

 

 

Unrealized loss on derivative instruments

 

48,217

 

80,829

 

Loss on disposal of property, plant and equipment

 

986

 

2,099

 

Deferred income taxes

 

(10,796

)

(14,186

)

Changes in operating assets and liabilities, net of working capital acquired:

 

 

 

 

 

Receivables

 

30,279

 

13,751

 

Inventories

 

23,812

 

9,148

 

Other current assets

 

3,503

 

(2,658

)

Accounts payable and accrued liabilities

 

32,556

 

(3,024

)

Other long-term assets

 

61

 

(372

)

Other long-term liabilities

 

2,688

 

8,126

 

Net cash provided by operating activities

 

207,913

 

115,319

 

 

 

 

 

 

 

Cash flows from investing activities:

 

 

 

 

 

Restricted cash

 

1,003

 

 

Capital expenditures

 

(254,263

)

(113,652

)

Acquisition of business

 

 

(230,728

)

Proceeds from disposal of property, plant and equipment

 

291

 

2,759

 

Net cash flows used in investing activities

 

(252,969

)

(341,621

)

 

 

 

 

 

 

Cash flows from financing activities:

 

 

 

 

 

Proceeds from public equity offering, net

 

425,629

 

138,163

 

Proceeds from revolving credit facility

 

13,700

 

307,600

 

Payments of revolving credit facility

 

(79,700

)

(168,400

)

Proceeds from long-term debt

 

 

499,000

 

Payments of long-term debt

 

 

(437,848

)

Payments of premiums on redemption of long-term debt

 

 

(39,520

)

Payments for debt issuance costs, deferred financing costs and registration costs

 

 

(6,524

)

Contributions from non-controlling interest

 

755

 

8,000

 

Payments of SMR liability

 

(497

)

(452

)

Cash paid for taxes related to net settlement of share-based payment awards

 

(8,048

)

(6,269

)

Excess tax benefits related to share-based compensation

 

2,207

 

1,096

 

Payment of distributions to common unitholders

 

(73,410

)

(49,274

)

Payment of distributions to non-controlling interest

 

(1,962

)

(13,568

)

Net cash flows provided by financing activities

 

278,674

 

232,004

 

 

 

 

 

 

 

Net increase in cash and cash equivalents

 

233,618

 

5,702

 

Cash and cash equivalents at beginning of year

 

117,016

 

67,450

 

Cash and cash equivalents at end of period

 

$

350,634

 

$

73,152

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

5



Table of Contents

 

MARKWEST ENERGY PARTNERS, L.P.

 

Notes to the Condensed Consolidated Financial Statements

 

(unaudited)

 

1. Organization and Basis of Presentation

 

MarkWest Energy Partners, L.P. was formed in 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 Partnership’s consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2011. In management’s opinion, the Partnership has made all adjustments necessary for a fair presentation of its results of operations, financial position and cash flows for the periods shown. These adjustments are of a normal recurring nature. Finally, results for the three months ended March 31, 2012 are not necessarily indicative of results for the full year 2012 or any other future period.

 

The Partnership’s unaudited condensed consolidated financial statements include all majority-owned or majority-controlled subsidiaries. In addition, MarkWest Utica EMG, L.L.C. (“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 3). All intercompany investments, accounts and transactions have been eliminated. The Partnership’s 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 5, the adoption of the amended guidance did not have a material effect on the Partnership’s 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 was intended to help investors and other financial statement users to better assess the effect or potential effect of offsetting arrangements on a company’s financial position and provides for increased disclosures. The amended guidance is effective for the Partnership prospectively as of January 1, 2013. Except for the additional disclosures, the adoption of the amended guidance is not expected to have a material effect on the Partnership’s consolidated financial statements.

 

3. 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 will make 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 will make 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 Utica’s 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 Utica’s 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 has not funded the Minimum EMG Investment by December 31,

 

6



Table of Contents

 

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 member’s 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 would 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 Partnership’s disproportionate economic interests as compared to its stated ownership interests and voting interests. The Partnership’s 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 Partnership’s 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 Partnership’s 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 VIEs, excluding intercompany balances, as of March 31, 2012 (in thousands):

 

 

 

As of March 31, 2012

 

 

 

MarkWest
Pioneer

 

MarkWest
Utica EMG

 

Total

 

ASSETS

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

2,097

 

$

363

 

$

2,460

 

Receivables, net

 

1,540

 

 

1,540

 

Other current assets

 

122

 

 

122

 

Property, plant and equipment, net of accumulated depreciation of $17,114 and $1, respectively

 

140,721

 

3,880

 

144,601

 

Other long-term assets

 

102

 

 

102

 

Total assets

 

$

144,582

 

$

4,243

 

$

148,825

 

 

 

 

 

 

 

 

 

LIABILITIES

 

 

 

 

 

 

 

Accounts payable

 

$

104

 

$

36

 

$

140

 

Accrued liabilities

 

1,338

 

560

 

1,898

 

Other long-term liabilities

 

75

 

 

75

 

Total liabilities

 

$

1,517

 

$

596

 

$

2,113

 

 

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 7 and Note 13). 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 Partnership’s general assets, and the creditors or beneficial interest holders of the VIE do not have recourse to the general credit of the Partnership. The Partnership’s maximum exposure to loss as a result of its involvement with the VIEs includes its equity investment, any additional capital contribution commitments and any operating expense incurred by the subsidiary operator in excess of its compensation received for

 

7



Table of Contents

 

the performance of the operating services. The Partnership did not provide any financial support to the VIEs that it was not contractually obligated to provide during the three months ended March 31, 2012 and 2011.

 

The results of operations of MarkWest Utica EMG and MarkWest Pioneer are included in the Partnership’s Liberty and Southwest segments, respectively (see Note 12). The result of operations and cash flows for MarkWest Pioneer are not material to the Partnership. During the three months ended March 31, 2012, construction began for MarkWest Utica EMG assets, but operating activities have not commenced. Therefore, the results of operations and cash flows related to MarkWest Utica EMG are not material to the Partnership.

 

4. 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 Partnership’s control. The Partnership’s 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 Partnership’s 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 Partner’s 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. 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. Generally the Partnership manages its NGL price risk using crude oil contracts as 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 may vary in certain periods due to various market conditions. In periods where NGL prices and crude oil prices are not consistent with the historical relationship, the Partnership incurs increased risk and additional gains or losses. The Partnership enters into NGL derivative contracts when adequate market liquidity exists.

 

To mitigate its cash flow exposure to fluctuations in the price of natural gas, the Partnership primarily utilizes derivative financial instruments relating to the future price of natural gas and takes into account the partial offset of its long and short gas positions resulting from normal operating activities.

 

As a result of its current derivative positions, the Partnership has mitigated a 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 will 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 Partnership’s 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. The Partnership uses standardized agreements that allow for offset of positive and negative exposures (master netting arrangements).

 

The Partnership records derivative contracts at fair value in the Condensed Consolidated Balance Sheets and has not elected hedge accounting or the normal purchases and normal sales designation which may cause volatility in the Condensed Consolidated Statements of Operations as the Partnership recognizes in current earnings all unrealized gains and losses from the changes in fair value on derivatives.

 

8



Table of Contents

 

As of March 31, 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
Position

 

Notional Quantity
(net)

 

Crude Oil (bbl)

 

Short

 

8,888,207

 

Natural Gas (MMBtu)

 

Long

 

14,301,553

 

NGLs (gal)

 

Short

 

36,896,028

 

 

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 (gain) loss 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 March 31, 2012, the estimated fair value of this contract was a liability of $123.6 million and the recorded value was a liability of $70.1 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 March 31, 2012 (in thousands):

 

Fair value of commodity contract

 

$

123,573

 

Inception value for period from April 1, 2015 to December 31, 2022

 

(53,507

)

Derivative liability as of March 31, 2012

 

$

70,066

 

 

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 gain related to facility expenses. As of March 31, 2012, the estimated fair value of this contract was an asset of $9.3 million.

 

Financial Statement Impact of Derivative Instruments

 

There were no material changes to the Partnership’s policy regarding the accounting for these instruments as previously disclosed in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2011. The fair value of the Partnership’s derivative instruments recorded on its Condensed Consolidated Balance Sheets and its Condensed Consolidated Statements of Operations is summarized below (in thousands):

 

Derivative instruments not designated as hedging instruments and their balance sheet location

 

Assets

 

Liabilities

 

 

March 31, 2012

 

December 31, 2011

 

March 31, 2012

 

December 31, 2011

 

Commodity contracts(1)

 

 

 

 

 

 

 

 

 

Fair value of derivative instruments - current

 

$

3,797

 

$

8,698

 

$

(105,648

)

$

(90,551

)

Fair value of derivative instruments - long-term

 

8,270

 

16,092

 

(85,800

)

(65,403

)

Total

 

$

12,067

 

$

24,790

 

$

(191,448

)

$

(155,954

)

 


(1)          Includes Embedded Derivatives in Commodity Contracts as discussed above.

 

9



Table of Contents

 

Derivative contracts not designated as hedging instruments and the location of gain
or (loss) recognized in income

 

Three months ended March 31,

 

 

2012

 

2011

 

Revenue: Derivative loss

 

 

 

 

 

Realized loss

 

$

(10,478

)

$

(14,391

)

Unrealized loss

 

(38,237

)

(71,288

)

Total revenue: derivative loss

 

(48,715

)

(85,679

)

 

 

 

 

 

 

Derivative loss related to purchased product costs

 

 

 

 

 

Realized loss

 

(7,074

)

(7,887

)

Unrealized loss

 

(11,726

)

(11,507

)

Total derivative loss related to purchased product costs

 

(18,800

)

(19,394

)

 

 

 

 

 

 

Derivative gain related to facility expenses

 

 

 

 

 

Unrealized gain

 

1,746

 

3,011

 

Total loss

 

$

(65,769

)

$

(102,062

)

 

For the three months ended March 31, 2012 and 2011, the Realized loss—revenue includes amortization of premium payments of zero and $1.0 million, respectively.

 

5. Fair Value

 

Fair value measurements and disclosures relate primarily to the Partnership’s derivative positions discussed in Note 4. The following table presents the derivative instruments carried at fair value as of March 31, 2012 and December 31, 2011 (in thousands):

 

As of March 31, 2012

 

Assets

 

Liabilities

 

Significant other observable inputs (Level 2)

 

 

 

 

 

Commodity contracts

 

$

583

 

$

(101,710

)

Significant unobservable inputs (Level 3)

 

 

 

 

 

Commodity contracts

 

2,222

 

(19,672

)

Embedded derivatives in commodity contracts

 

9,262

 

(70,066

)

Total carrying value in Condensed Consolidated Balance Sheet

 

$

12,067

 

$

(191,448

)

 

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

)

 

10



Table of Contents

 

The following table provides additional information about the significant unobservable inputs used in the valuation of Level 3 instruments as of March 31, 2012:

 

Level 3 Instrument

 

Balance Sheet
Classification

 

Valuation
Technique

 

Unobservable Inputs

 

Value Range (2)(3)(4)

 

Time Period

 

Commodity contracts

 

Assets

 

Market approach

 

Forward propane prices (per gallon)

 

$1.23

-

$1.33

 

Jan. 2013 - Dec. 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward natural gasoline prices (per gallon)

 

$2.18

-

$2.38

 

Jan. 2013 - Dec. 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude option volatilities (%)

 

14.80 %

-

37.42%

 

Apr. 2012 - Dec. 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

Market approach

 

Forward propane prices (per gallon)

 

$1.23

-

$1.33

 

Jan. 2013 - Dec. 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward isobutane prices (per gallon)

 

$1.76

-

$2.05

 

Jan. 2013 - Dec. 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward normal butane prices (per gallon)

 

$1.68

-

$1.90

 

Jan. 2013 - Dec. 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward natural gasoline prices (per gallon)

 

$2.18

-

$2.38

 

Jan. 2013 - Dec. 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude option volatilities (%)

 

14.80 %

-

37.42%

 

Apr. 2012 - Dec. 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Embedded derivatives in commodity contracts

 

Liability

 

Market Approach

 

Forward propane prices (per gallon)

 

$1.16

-

$1.33

 

Apr. 2012 - Dec. 2022

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward isobutane prices (per gallon)

 

$1.64

-

$2.05

 

Apr. 2012 - Dec. 2022

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward normal butane prices (per gallon)

 

$1.58

-

$1.90

 

Apr. 2012 - Dec. 2022

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward natural gasoline prices (per gallon)

 

$2.05

-

$2.38

 

Apr. 2012 - Dec. 2022

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward natural gas prices (per mmbtu)

 

$2.16

-

$6.36

 

Apr. 2012 - Dec. 2022

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Probability of renewal (1)

 

 

0 %

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Asset

 

Market Approach

 

ERCOT Pricing (per MegaWatt Hour)

 

$22.74

-

$66.30

 

Apr. 2012 - Dec. 2014

 

 


(1)

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 counterparty’s 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.

 

11



Table of Contents

 

(2)          The forward NGL prices utilized in the valuations are at the higher end of the range in the earlier years and are generally declining slightly through the later years presented.

 

(3)          The forward natural gas prices utilized in the valuations are at the low end of the range in the earlier years and are generally increasing through the later years presented.

 

(4)          The forward ERCOT prices utilized in the valuations are generally increasing over time with a seasonal spike in pricing in the summer months.

 

Fair Value Sensitivity Related to Unobservable Inputs

 

Commodity contracts (assets and liabilities) - For the Partnership’s commodity contracts, increases in forward NGL prices result in a decrease in the fair value of the derivative assets and an increase 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 Partnership’s 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 4. 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 the electricity purchase agreement discussed further in Note 4. 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 Partnership’s Risk Management Department (the “Risk Department”) is responsible for the valuation of the Partnership’s 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 Partnership’s 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 4, 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 March 31, 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 Partnership’s estimated price curves. The fair value of the Partnership’s commodity derivative contracts and embedded derivatives in commodity contracts are reviewed quarterly by the Hedge Committee.

 

12



Table of Contents

 

Changes in Level 3 Fair Value Measurements

 

The table below includes a rollforward of the balance sheet amounts for the three months ended March 31, 2012 and 2011 for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands).

 

 

 

Three months ended March 31, 2012

 

 

 

Commodity
Derivative
Contracts (net)

 

Embedded
Derivatives in
Commodity
Contracts (net)

 

Fair value at beginning of period

 

$

(2,965

)

$

(53,904

)

Total loss (realized and unrealized) included in earnings (1)

 

(12,076

)

(10,438

)

Settlements

 

(2,409

)

3,538

 

Fair value at end of period

 

$

(17,450

)

$

(60,804

)

 

 

 

 

 

 

The amount of total losses 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)

 

$

(14,050

)

$

(10,620

)

 

 

 

Three months ended March 31, 2011

 

 

 

Commodity
Derivative
Contracts (net)

 

Embedded
Derivatives in
Commodity
Contracts (net)

 

Fair value at beginning of period

 

$

(14,357

)

$

(34,936

)

Total loss (realized and unrealized) included in earnings (1)

 

(22,993

)

(19,280

)

Settlements

 

1,444

 

3,609

 

Fair value at end of period

 

$

(35,906

)

$

(50,607

)

 

 

 

 

 

 

The amount of total losses 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)

 

$

(22,779

)

$

(18,692

)

 


(1)                                 Gains and losses on Commodity Derivative Contracts classified as Level 3 are recorded in Derivative loss related to revenue. Gains and losses on Embedded Derivatives in Commodity Contracts are recorded in Purchased product costs, Derivative loss related to purchased product costs and Derivative gain related to facility expenses.

 

6. Inventories

 

Inventories consist of the following (in thousands):

 

 

 

March 31, 2012

 

December 31, 2011

 

NGLs

 

$

7,359

 

$

32,352

 

Spare parts, materials and supplies

 

9,846

 

8,654

 

Total inventories

 

$

17,205

 

$

41,006

 

 

13



Table of Contents

 

7. Long-Term Debt

 

Debt is summarized below (in thousands):

 

 

 

March 31, 2012

 

December 31, 2011

 

Credit Facility

 

 

 

 

 

Revolving credit facility, 4.25% interest, due September 2016

 

$

 

$

66,000

 

 

 

 

 

 

 

Senior Notes (1)

 

 

 

 

 

2018 Senior Notes, 8.75% interest, net of discount of $124 and $129, respectively, issued April and May 2008 and due April 2018

 

80,988

 

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 $897 and $921, respectively, issued February and March 2011 and due August 2021

 

499,103

 

499,079

 

2022 Senior Notes, 6.25% interest, issued October 2011 and due June 2022

 

700,000

 

700,000

 

Total long-term debt

 

$

1,780,091

 

$

1,846,062

 

 


(1)          The estimated aggregate fair value of the senior notes (collectively, the “Senior Notes”) was approximately $1,895.1 million and $1,880.7 million as of March 31, 2012 and December 31, 2011, respectively, based on quoted prices in an inactive market. The fair value of the Partnership’s Senior Notes is considered a Level 3 measurement.

 

Credit Facility

 

Under the provisions of the Credit Facility, the Partnership is subject to a number of restrictions and covenants. These covenants are used to calculate the available borrowing capacity on a quarterly basis. The Credit Facility is guaranteed by the Partnership’s wholly-owned subsidiaries and collateralized by substantially all of the Partnership’s assets and those of its wholly-owned subsidiaries. As of March 31, 2012, the Partnership had $22.3 million of letters of credit outstanding under the Credit Facility and $877.7 million available for borrowing.

 

8. Equity

 

Equity Offerings

 

In January 2012, the Partnership issued approximately 0.7 million units 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 will be used to partially fund the Partnership’s 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 will be used to partially fund the Partnership’s ongoing capital expenditure program.

 

Distributions of Available Cash

 

Quarter Ended

 

Distribution Per
Common Unit

 

Declaration Date

 

Record Date

 

Payment Date

 

March 31, 2012

 

$

0.79

 

April 26, 2012

 

May 7, 2012

 

May 15, 2012

 

December 31, 2011

 

$

0.76

 

January 26, 2012

 

February 6, 2012

 

February 14, 2012

 

 

14



Table of Contents

 

9. Commitments and Contingencies

 

Legal

 

The Partnership is subject to a variety of risks and disputes, and is a party to various legal proceedings in the normal course of its business. The Partnership maintains insurance policies in amounts and with coverage and deductibles as it believes reasonable and prudent. However, the Partnership cannot assure that the insurance companies will promptly honor their policy obligations or that the coverage or levels of insurance will be adequate to protect the Partnership from all material expenses related to future claims for property loss or business interruption to the Partnership, or for third-party claims of personal and property damage, or that the coverages or levels of insurance it currently has will be available in the future at economical prices. While it is not possible to predict the outcome of the legal actions with certainty, management is of the opinion that appropriate provisions and accruals for potential losses associated with all legal actions have been made in the 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 Partnership’s financial condition, liquidity or results of operations.

 

Contract Contingencies

 

Certain natural gas processing arrangements in the Partnership’s 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 Partnership’s Liberty Segment due to events of force majeure including inabilities or delays in obtaining requisite permits, as well as due to extreme weather events. The requisite permits were subsequently issued several months later than expected and construction has re-commenced but those delays exacerbated construction conditions. In addition, the Partnership has continued to experience extraordinary weather events which have resulted in additional delays. Delay charges for delays other than due to force majeure events are up to $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 for other than 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 are force majeure events under the applicable contract. The customer has reserved its rights to dispute the Partnership’s force majeure claim, but has not requested the payment of any delay charges. The Partnership’s management believes it has a convincing legal position and believes that its force majeure claim would be recognized as valid if contested. The Partnership is also developing solutions to provide alternative processing capabilities for its customers to mitigate the impact of these delays.

 

10. Income Taxes

 

A reconciliation of the provision for income tax and the amount computed by applying the federal statutory rate to income (loss) before provision for income tax for the three months ended March 31, 2012 and 2011 is as follows (in thousands):

 

 

 

Three months ended March 31, 2012

 

 

 

Corporation

 

Partnership

 

Eliminations

 

Consolidated

 

Income before provision for income tax

 

$

7,525

 

$

14,097

 

$

(804

)

$

20,818

 

Federal statutory rate

 

35

%

0

%

0

%

 

 

Federal income tax at statutory rate

 

2,634

 

 

 

2,634

 

Permanent items

 

4

 

 

 

4

 

State income taxes net of federal benefit

 

339

 

66

 

 

405

 

Provision on income from Class A units (1)

 

1,502

 

 

 

1,502

 

Provision for income tax

 

$

4,479

 

$

66

 

$

 

$

4,545

 

 

15



Table of Contents

 

 

 

Three months ended March 31, 2011

 

 

 

Corporation

 

Partnership

 

Eliminations

 

Consolidated

 

Loss before provision for income tax

 

$

(19,996

)

$

(67,436

)

$

(1,369

)

$

(88,801

)

Federal statutory rate

 

35

%

0

%

0

%

 

 

Federal income tax at statutory rate

 

(6,999

)

 

 

(6,999

)

Permanent items

 

(77

)

 

 

(77

)

State income taxes net of federal benefit

 

(682

)

(343

)

 

(1,025

)

Provision on income from Class A units (1)

 

(6,029

)

 

 

(6,029

)

Provision for income tax

 

$

(13,787

)

$

(343

)

$

 

$

(14,130

)

 


(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 Partnership’s ownership of or sale of shares of the Corporation’s common stock. The provision on income from Class A units includes intra period allocations to continued operations and excludes allocations to equity.

 

11. Earnings (Loss) Per Common Unit

 

The following table shows the computation of basic and diluted net income (loss) per common unit for the three months ended March 31, 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 March 31,

 

 

 

2012

 

2011

 

Net income (loss) attributable to the Partnership

 

$

16,020

 

$

(84,029

)

Less: Income allocable to phantom units

 

520

 

420

 

Income (loss) available for common unitholders - basic

 

15,500

 

(84,449

)

Add: Income allocable to phantom units and DER expense

 

535

 

 

Income (loss) available for common unitholders - diluted

 

$

16,035

 

$

(84,449

)

 

 

 

 

 

 

Weighted average common units outstanding — basic

 

96,840

 

74,531

 

Potential common shares (Class B and phantom units)

 

20,753

 

 

Weighted average common units outstanding — diluted

 

117,593

 

74,531

 

 

 

 

 

 

 

Net income (loss) attributable to the Partnership’s common unitholders per common unit (1)

 

 

 

 

 

Basic

 

$

0.16

 

$

(1.13

)

Diluted

 

$

0.14

 

$

(1.13

)

 


(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.

 

12. 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 Partnership’s segment profit measure, Operating income before items not allocated to segments, and capital expenditures for the reported segments for the three months ended March 31, 2012 and 2011 (in thousands).

 

16



Table of Contents

 

Three months ended March 31, 2012:

 

 

 

Southwest

 

Northeast

 

Liberty

 

Gulf Coast

 

Total

 

Segment revenue

 

$

214,725

 

$

86,918

 

$

75,577

 

$

24,229

 

$

401,449

 

Purchased product costs

 

104,233

 

25,687

 

24,635

 

 

154,555

 

Net operating margin

 

110,492

 

61,231

 

50,942

 

24,229

 

246,894

 

Facility expenses

 

22,992

 

6,378

 

12,247

 

9,638

 

51,255

 

Portion of operating income attributable to non-controlling interests

 

1,446

 

 

 

 

1,446

 

Operating income before items not allocated to segments

 

$

86,054

 

$

54,853

 

$

38,695

 

$

14,591

 

$

194,193

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures

 

$

48,040

 

$

23,302

 

$

178,689

 

$

2,543

 

$

252,574

 

Capital expenditures not allocated to segments

 

 

 

 

 

 

 

 

 

1,689

 

Total capital expenditures

 

 

 

 

 

 

 

 

 

$

254,263

 

 

Three months ended March 31, 2011:

 

 

 

Southwest

 

Northeast

 

Liberty

 

Gulf Coast

 

Total

 

Segment revenue

 

$

201,774

 

$

92,091

 

$

41,219

 

$

21,759

 

$

356,843

 

Purchased product costs

 

103,196

 

40,878

 

9,555

 

 

153,629

 

Net operating margin

 

98,578

 

51,213

 

31,664

 

21,759

 

203,214

 

Facility expenses

 

20,157

 

5,594

 

6,498

 

8,990

 

41,239

 

Portion of operating income attributable to non-controlling interests

 

1,172

 

 

12,377

 

 

13,549

 

Operating income before items not allocated to segments

 

$

77,249

 

$

45,619

 

$

12,789

 

$

12,769

 

$

148,426

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures

 

$

17,156

 

$

709

 

$

94,146

 

$

294

 

$

112,305

 

Capital expenditures not allocated to segments

 

 

 

 

 

 

 

 

 

1,347

 

Total capital expenditures

 

 

 

 

 

 

 

 

 

$

113,652

 

 

17



Table of Contents

 

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 March 31, 2012 and 2011 (in thousands):

 

 

 

Three months ended March 31,

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Total segment revenue

 

$

401,449

 

$

356,843

 

Derivative loss not allocated to segments

 

(48,715

)

(85,679

)

Revenue deferral adjustment (1)

 

(2,268

)

(7,943

)

Total revenue

 

$

350,466

 

$

263,221

 

 

 

 

 

 

 

Operating income before items not allocated to segments

 

$

194,193

 

$

148,426

 

Portion of operating income attributable to non-controlling interests

 

1,446

 

13,549

 

Derivative loss not allocated to segments

 

(65,769

)

(102,062

)

Revenue deferral adjustment (1)

 

(2,268

)

(7,943

)

Compensation expense included in facility expenses not allocated to segments

 

(449

)

(1,040

)

Facility expenses adjustments (2)

 

2,864

 

2,855

 

Selling, general and administrative expenses

 

(25,224

)

(21,712

)

Depreciation

 

(41,145

)

(34,364

)

Amortization of intangible assets

 

(10,985

)

(10,817

)

Loss on disposal of property, plant and equipment

 

(986

)

(2,099

)

Accretion of asset retirement obligations

 

(238

)

(87

)

Income (loss) from operations

 

51,439

 

(15,294

)

 

 

 

 

 

 

Loss from unconsolidated affiliate

 

(9

)

(539

)

Interest income

 

72

 

89

 

Interest expense

 

(29,472

)

(28,263

)

Amortization of deferred financing costs and discount (a component of interest expense)

 

(1,270

)

(1,428

)

Loss on redemption of debt

 

 

(43,328

)

Miscellaneous income (expense), net

 

58

 

(38

)

Income (loss) before provision for income tax

 

$

20,818

 

$

(88,801

)

 


(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 Partnership’s 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 March 31, 2012, approximately $0.2 million and $2.1 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. For the three months ended March 31, 2011, approximately $6.5 million and $1.4 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 Gulf Coast segment.

 

18



Table of Contents

 

The tables below present information about segment assets as of March 31, 2012 and December 31, 2011 (in thousands):

 

 

 

 

March 31, 2012

 

December 31, 2011

 

Southwest

 

$

1,693,321

 

$

1,701,919

 

Northeast

 

498,185

 

533,591

 

Liberty

 

1,279,066

 

1,114,654

 

Gulf Coast

 

551,313

 

553,043

 

Total segment assets

 

4,021,885

 

3,903,207

 

Assets not allocated to segments:

 

 

 

 

 

Certain cash and cash equivalents

 

342,684

 

66,212

 

Fair value of derivatives

 

12,067

 

24,790

 

Investment in unconsolidated affiliate

 

26,944

 

27,853

 

Other (1)

 

42,067

 

48,363

 

Total assets

 

$

4,445,647

 

$

4,070,425

 

 


(1)                                  Includes corporate fixed assets, deferred financing costs, income tax receivable, receivables and other corporate assets not allocated to segments.

 

13. Supplemental Condensed Consolidating Financial Information

 

The Partnership has no operations independent of its subsidiaries. As of March 31, 2012, the Partnership’s obligations under the outstanding Senior Notes (see Note 7) were fully, jointly and severally guaranteed, by all of its wholly-owned subsidiaries other than MarkWest Liberty Midstream. 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 Partnership’s other subsidiaries that do not guarantee the outstanding Senior Notes, have significant assets and operations in aggregate. For the purpose of the following financial information, the Partnership’s investments in its subsidiaries and the guarantor subsidiaries’ investments in their subsidiaries are presented in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities. The operations, cash flows and financial position of the co-issuer of the Senior Notes, MarkWest Energy Finance Corporation, are minor and therefore have been included with the Parent’s financial information. Condensed consolidating financial information for the Partnership, its combined guarantor subsidiaries and combined non-guarantor subsidiaries as of March 31, 2012 and December 31, 2011 and for the three months ended March 31, 2012 and 2011 is as follows (in thousands):

 

19



Table of Contents

 

Condensed Consolidating Balance Sheets

 

 

 

As of March 31, 2012

 

 

 

Parent

 

Guarantor
Subsidiaries

 

Non-Guarantor
Subsidiaries

 

Consolidating
Adjustments

 

Consolidated

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

270,022

 

$

77,759

 

$

2,853

 

$

 

$

350,634

 

Restricted cash

 

 

 

25,238

 

 

25,238

 

Receivables and other current assets

 

7,401

 

187,646

 

42,355

 

 

237,402

 

Intercompany receivables

 

30,017

 

12,597

 

12,159

 

(54,773

)

 

Fair value of derivative instruments

 

 

3,797

 

 

 

3,797

 

Total current assets

 

307,440

 

281,799

 

82,605

 

(54,773

)

617,071

 

 

 

 

 

 

 

 

 

 

 

 

 

Total property, plant and equipment, net

 

3,915

 

1,771,460

 

1,334,520

 

(20,207

)

3,089,688

 

 

 

 

 

 

 

 

 

 

 

 

 

Other long-term assets:

 

 

 

 

 

 

 

 

 

 

 

Investment in unconsolidated affiliate

 

 

26,944

 

 

 

26,944

 

Investment in consolidated affiliates

 

3,109,581

 

1,185,801

 

 

(4,295,382

)

 

Intangibles, net of accumulated amortization

 

 

592,248

 

534

 

 

592,782

 

Fair value of derivative instruments

 

 

8,270

 

 

 

8,270

 

Intercompany notes receivable

 

184,300

 

 

 

(184,300

)

 

Other long-term assets

 

40,231

 

70,314

 

347

 

 

110,892

 

Total assets (1)

 

$

3,645,467

 

$

3,936,836

 

$

1,418,006

 

$