XNYS:MWE MarkWest Energy Partners LP Quarterly Report 10-Q Filing - 6/30/2012

Effective Date 6/30/2012

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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 June 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
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 July 30, 2012, the number of the registrant’s common units and Class B units outstanding were 110,693,615 and 19,954,389, respectively.

 

 

 



Table of Contents

 

PART I—FINANCIAL INFORMATION

 

 

 

 

Item 1.

Financial Statements

4

 

Unaudited Condensed Consolidated Balance Sheets at June 30, 2012 and December 31, 2011

4

 

Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2012 and 2011

5

 

Unaudited Condensed Consolidated Statements of Changes in Equity for the six months ended June 30, 2012 and 2011

6

 

Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and 2011

7

 

Unaudited Notes to the Condensed Consolidated Financial Statements

8

Item 2.

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

34

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

51

Item 4.

Controls and Procedures

53

 

 

 

PART II—OTHER INFORMATION

54

Item 1.

Legal Proceedings

54

Item 1A.

Risk Factors

54

Item 6.

Exhibits

55

SIGNATURES

56

 

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.

 

2



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

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

 

3



Table of Contents

 

PART I—FINANCIAL INFORMATION

 

Item 1.  Financial Statements

 

MARKWEST ENERGY PARTNERS, L.P.

 

Condensed Consolidated Balance Sheets

 

(unaudited, in thousands)

 

 

 

June 30, 2012

 

December 31, 2011

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents ($3,168 and $2,684, respectively)

 

$

125,462

 

$

117,016

 

Restricted cash

 

25,285

 

26,193

 

Receivables, net ($1,428 and $1,569, respectively)

 

138,371

 

226,561

 

Inventories

 

22,209

 

41,006

 

Fair value of derivative instruments

 

28,556

 

8,698

 

Deferred income taxes

 

6,544

 

14,885

 

Other current assets ($69 and $169, respectively)

 

8,915

 

11,748

 

Total current assets

 

355,342

 

446,107

 

 

 

 

 

 

 

Property, plant and equipment ($187,048 and $156,808, respectively)

 

4,164,402

 

3,302,369

 

Less: accumulated depreciation ($18,704 and $15,551, respectively)

 

(520,766

)

(438,062

)

Total property, plant and equipment, net

 

3,643,636

 

2,864,307

 

 

 

 

 

 

 

Other long-term assets:

 

 

 

 

 

Investment in unconsolidated affiliate

 

26,695

 

27,853

 

Intangibles, net of accumulated amortization of $191,388 and $168,168, respectively

 

885,183

 

603,767

 

Goodwill

 

144,582

 

67,918

 

Deferred financing costs, net of accumulated amortization of $15,726 and $13,194, respectively

 

41,581

 

41,798

 

Deferred contract cost, net of accumulated amortization of $2,418 and $2,262, respectively

 

832

 

988

 

Fair value of derivative instruments

 

35,237

 

16,092

 

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

 

1,510

 

1,595

 

Total assets

 

$

5,134,598

 

$

4,070,425

 

 

 

 

 

 

 

LIABILITIES AND EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable ($292 and $96, respectively)

 

$

208,019

 

$

179,871

 

Accrued liabilities ($14,306 and $1,144, respectively)

 

231,719

 

171,451

 

Fair value of derivative instruments

 

30,479

 

90,551

 

Total current liabilities

 

470,217

 

441,873

 

 

 

 

 

 

 

Deferred income taxes

 

156,783

 

93,664

 

Fair value of derivative instruments

 

18,951

 

65,403

 

Long-term debt, net of discounts of $992 and $1,050, respectively

 

1,997,985

 

1,846,062

 

Other long-term liabilities ($76 and $73, respectively)

 

128,231

 

121,356

 

 

 

 

 

 

 

Commitments and contingencies (Note 11)

 

 

 

 

 

 

 

 

 

 

 

Equity:

 

 

 

 

 

Common units (110,694 and 94,940 common units issued and outstanding, respectively)

 

1,540,189

 

679,309

 

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

 

752,531

 

752,531

 

Non-controlling interest in consolidated subsidiaries

 

69,711

 

70,227

 

 

 

 

 

 

 

Total equity

 

2,362,431

 

1,502,067

 

Total liabilities and equity

 

$

5,134,598

 

$

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.

 

4



Table of Contents

 

MARKWEST ENERGY PARTNERS, L.P.

 

Condensed Consolidated Statements of Operations

 

(unaudited, in thousands, except per unit amounts)

 

 

 

Three months ended June 30,

 

Six months ended June 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Revenue:

 

 

 

 

 

 

 

 

 

Revenue

 

$

309,986

 

$

359,849

 

$

709,167

 

$

708,749

 

Derivative gain (loss)

 

136,067

 

40,590

 

87,352

 

(45,089

)

Total revenue

 

446,053

 

400,439

 

796,519

 

663,660

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

Purchased product costs

 

112,731

 

154,580

 

267,286

 

308,209

 

Derivative (gain) loss related to purchased product costs

 

(51,579

)

(254

)

(32,779

)

19,140

 

Facility expenses

 

48,538

 

40,698

 

97,378

 

80,122

 

Derivative (gain) loss related to facility expenses

 

(1,146

)

2,927

 

(2,892

)

(84

)

Selling, general and administrative expenses

 

21,879

 

18,580

 

47,103

 

40,292

 

Depreciation

 

42,918

 

37,201

 

84,063

 

71,565

 

Amortization of intangible assets

 

12,307

 

10,830

 

23,292

 

21,647

 

Loss on disposal of property, plant and equipment

 

1,342

 

2,373

 

2,328

 

4,472

 

Accretion of asset retirement obligations

 

161

 

290

 

399

 

377

 

Total operating expenses

 

187,151

 

267,225

 

486,178

 

545,740

 

 

 

 

 

 

 

 

 

 

 

Income from operations

 

258,902

 

133,214

 

310,341

 

117,920

 

 

 

 

 

 

 

 

 

 

 

Other income (expense):

 

 

 

 

 

 

 

 

 

Earnings (loss) from unconsolidated affiliate

 

551

 

(216

)

542

 

(755

)

Interest income

 

159

 

63

 

231

 

152

 

Interest expense

 

(26,762

)

(27,874

)

(56,234

)

(56,137

)

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

 

(1,245

)

(1,443

)

(2,515

)

(2,871

)

Loss on redemption of debt

 

 

 

 

(43,328

)

Miscellaneous income, net

 

4

 

169

 

62

 

131

 

Income before provision for income tax

 

231,609

 

103,913

 

252,427

 

15,112

 

 

 

 

 

 

 

 

 

 

 

Provision for income tax expense (benefit):

 

 

 

 

 

 

 

 

 

Current

 

4,809

 

4,089

 

20,150

 

4,145

 

Deferred

 

39,664

 

10,619

 

28,868

 

(3,567

)

Total provision for income tax

 

44,473

 

14,708

 

49,018

 

578

 

 

 

 

 

 

 

 

 

 

 

Net income

 

187,136

 

89,205

 

203,409

 

14,534

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to non-controlling interest

 

(228

)

(10,708

)

(481

)

(20,066

)

Net income (loss) attributable to the Partnership

 

$

186,908

 

$

78,497

 

$

202,928

 

$

(5,532

)

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to the Partnership’s common unitholders per common unit (Note 13):

 

 

 

 

 

 

 

 

 

Basic

 

$

1.74

 

$

1.03

 

$

1.98

 

$

(0.09

)

Diluted

 

$

1.47

 

$

1.03

 

$

1.66

 

$

(0.09

)

 

 

 

 

 

 

 

 

 

 

Weighted average number of outstanding common units:

 

 

 

 

 

 

 

 

 

Basic

 

106,825

 

75,160

 

101,833

 

74,847

 

Diluted

 

127,468

 

75,266

 

122,531

 

74,847

 

 

 

 

 

 

 

 

 

 

 

Cash distribution declared per common unit

 

$

0.79

 

$

0.67

 

$

1.55

 

$

1.32

 

 

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

 

5



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

 

15,508

 

852,873

 

 

 

 

852,873

 

Distributions paid

 

 

(155,073

)

 

 

(2,937

)

(158,010

)

Contributions from non-controlling interest

 

 

 

 

 

1,940

 

1,940

 

Share-based compensation activity

 

246

 

537

 

 

 

 

537

 

Excess tax benefits related to share-based compensation

 

 

2,207

 

 

 

 

2,207

 

Deferred income tax impact from changes in equity

 

 

(42,592

)

 

 

 

(42,592

)

Net income

 

 

202,928

 

 

 

481

 

203,409

 

June 30, 2012

 

110,694

 

$

1,540,189

 

19,954

 

$

752,531

 

$

69,711

 

$

2,362,431

 

 

 

 

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

 

3,450

 

138,163

 

 

138,163

 

Distributions paid

 

 

(100,058

)

(34,531

)

(134,589

)

Contributions to MarkWest Liberty Midstream joint venture

 

 

 

24,400

 

24,400

 

Share-based compensation activity

 

270

 

2,778

 

 

2,778

 

Excess tax benefits related to share-based compensation

 

 

1,096

 

 

1,096

 

Net (loss) income

 

 

(5,532

)

20,066

 

14,534

 

June 30, 2011

 

75,160

 

$

1,029,496

 

$

475,452

 

$

1,504,948

 

 

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

 

6



Table of Contents

 

MARKWEST ENERGY PARTNERS, L.P.

 

Condensed Consolidated Statements of Cash Flows

 

(unaudited, in thousands)

 

 

 

Six months ended June 30,

 

 

 

2012

 

2011

 

Cash flows from operating activities:

 

 

 

 

 

Net income

 

$

203,409

 

$

14,534

 

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

Depreciation

 

84,063

 

71,565

 

Amortization of intangible assets

 

23,292

 

21,647

 

Loss on redemption of debt

 

 

43,328

 

Amortization of deferred financing costs and discount

 

2,515

 

2,871

 

Accretion of asset retirement obligations

 

399

 

377

 

Amortization of deferred contract cost

 

156

 

156

 

Phantom unit compensation expense

 

8,585

 

8,093

 

Equity in (earnings) loss of unconsolidated affiliate

 

(542

)

755

 

Distributions from unconsolidated affiliate

 

1,700

 

300

 

Unrealized (gain) loss on derivative instruments

 

(145,527

)

26,265

 

Loss on disposal of property, plant and equipment

 

2,328

 

4,472

 

Deferred income taxes

 

28,868

 

(3,567

)

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

 

 

 

 

 

Receivables

 

90,664

 

(9,215

)

Inventories

 

18,895

 

(6,326

)

Other current assets

 

2,738

 

526

 

Accounts payable and accrued liabilities

 

(71,784

)

20,473

 

Other long-term assets

 

85

 

(384

)

Other long-term liabilities

 

6,593

 

10,494

 

Net cash provided by operating activities

 

256,437

 

206,364

 

 

 

 

 

 

 

Cash flows used in investing activities:

 

 

 

 

 

Restricted cash

 

1,003

 

 

Capital expenditures

 

(582,203

)

(234,116

)

Acquisition of business, net of cash acquired

 

(506,797

)

(230,728

)

Proceeds from disposal of property, plant and equipment

 

499

 

2,795

 

Net cash flows used in investing activities

 

(1,087,498

)

(462,049

)

 

 

 

 

 

 

Cash flows from financing activities:

 

 

 

 

 

Proceeds from public equity offerings, net

 

852,873

 

138,163

 

Proceeds from revolving credit facility

 

238,065

 

781,700

 

Payments of revolving credit facility

 

(86,200

)

(535,200

)

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

 

(2,315

)

(6,747

)

Contributions from non-controlling interest

 

1,940

 

24,400

 

Payments of SMR liability

 

(1,005

)

(916

)

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

 

(155,073

)

(100,058

)

Payment of distributions to non-controlling interest

 

(2,937

)

(34,531

)

Net cash flows provided by financing activities

 

839,507

 

283,270

 

 

 

 

 

 

 

Net increase in cash and cash equivalents

 

8,446

 

27,585

 

Cash and cash equivalents at beginning of year

 

117,016

 

67,450

 

Cash and cash equivalents at end of period

 

$

125,462

 

$

95,035

 

 

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

 

7



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 and six months ended June 30, 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. 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 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 6, 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 is 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 additional disclosures related to our offsetting arrangements, the adoption of the amended guidance is not expected to have a material effect on the Partnership’s 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. Keystone’s 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.

 

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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 Partnership’s 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 June 30, 2012, the purchase price for the Keystone Acquisition is $509.6 million subject to further working capital adjustments. Due to the potential changes in the purchase price and the Partnership’s 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 Partnership’s existing Marcellus Shale operations and the Partnership’s 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 the Keystone are immaterial for the quarter ended June 30, 2012.

 

Pro forma financial results that give effect to the Keystone Acquisition are not presented as they are not material to the Partnership’s 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 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, 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 will be made in accordance with those adjusted

 

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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 MarkWest Pioneer and MarkWest Utica EMG, excluding intercompany balances, as of June 30, 2012 (in thousands).

 

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As of June 30, 2012

 

 

 

MarkWest
Pioneer

 

MarkWest Utica
EMG

 

Total

 

ASSETS

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

3,089

 

$

79

 

$

3,168

 

Receivables, net

 

1,428

 

 

1,428

 

Other current assets

 

69

 

 

69

 

Property, plant and equipment, net of accumulated depreciation of $18,696 and $8, respectively

 

139,246

 

29,098

 

168,344

 

Other long-term assets

 

102

 

 

102

 

Total assets

 

$

143,934

 

$

29,177

 

$

173,111

 

 

 

 

 

 

 

 

 

LIABILITIES

 

 

 

 

 

 

 

Accounts payable

 

$

42

 

$

250

 

$

292

 

Accrued liabilities

 

1,171

 

13,135

 

14,306

 

Other long-term liabilities

 

76

 

 

76

 

Total liabilities

 

$

1,289

 

$

13,385

 

$

14,674

 

 

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 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 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 six months ended June 30, 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 14). The result of operations and cash flows for MarkWest Pioneer are not material to the Partnership. During the six months ended June 30, 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.

 

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 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 and fixed price forward contracts. The risk management policy does not allow for trading derivative contracts.

 

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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, which may vary in certain periods due to various market conditions, has significantly weakened during the first half 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 enters into NGL derivative contracts when adequate market liquidity exists and 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 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 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 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.

 

As of June 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
Position

 

Notional Quantity
(net)

 

Crude Oil (bbl)

 

Short

 

7,241,527

 

Natural Gas (MMBtu)

 

Long

 

11,308,002

 

NGLs (gal)

 

Short

 

40,771,965

 

 

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 June 30, 2012, the estimated fair value of this contract was a liability of $74.3 million and the recorded value was a liability of $20.8 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 June 30, 2012 (in thousands):

 

Fair value of commodity contract

 

$

74,311

 

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

 

(53,507

)

Derivative liability as of June 30, 2012

 

$

20,804

 

 

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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 June 30, 2012, the estimated fair value of this contract was an asset of $10.4 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):

 

 

 

Assets

 

Liabilities

 

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

 

June 30,
2012

 

December 31,
2011

 

June 30,
2012

 

December 31,
2011

 

Commodity contracts(1)

 

 

 

 

 

 

 

 

 

Fair value of derivative instruments — current

 

$

28,556

 

$

8,698

 

$

(30,479

)

$

(90,551

)

Fair value of derivative instruments - long-term

 

35,237

 

16,092

 

(18,951

)

(65,403

)

Total

 

$

63,793

 

$

24,790

 

$

(49,430

)

$

(155,954

)

 


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

 

Derivative contracts not designated as hedging instruments and the

 

Three months ended June 30,

 

Six months ended June 30,

 

location of gain or (loss) recognized in income

 

2012

 

2011

 

2012

 

2011

 

Revenue: Derivative gain (loss)

 

 

 

 

 

 

 

 

 

Realized gain (loss)

 

$

2,841

 

$

(12,186

)

$

(7,637

)

$

(26,577

)

Unrealized gain (loss)

 

133,226

 

52,776

 

94,989

 

(18,512

)

Total revenue: derivative gain (loss)

 

136,067

 

40,590

 

87,352

 

(45,089

)

 

 

 

 

 

 

 

 

 

 

Derivative gain (loss) related to purchased product costs

 

 

 

 

 

 

 

 

 

Realized loss

 

(7,793

)

(5,560

)

(14,867

)

(13,447

)

Unrealized gain (loss)

 

59,372

 

5,814

 

47,646

 

(5,693

)

Total derivative gain (loss) related to purchased product costs

 

51,579

 

254

 

32,779

 

(19,140

)

 

 

 

 

 

 

 

 

 

 

Derivative gain (loss) related to facility expenses

 

 

 

 

 

 

 

 

 

Unrealized gain (loss)

 

1,146

 

(2,927

)

2,892

 

84

 

Total gain (loss)

 

$

188,792

 

$

37,917

 

$

123,023

 

$

(64,145

)

 

For the three months ended June 30, 2012 and 2011, the Realized gain (loss)—revenue includes amortization of premium payments of zero and $1.1 million, respectively. For the six months ended June 30, 2012 and 2011, the Realized gain (loss)—revenue includes amortization of premium payments of zero and $2.1 million, respectively.

 

During the second quarter 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 hedges 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 $8.8 million which was recorded as a realized gain in Revenue: Derivative gain (loss) in the accompanying Consolidated Statements of Operations.

 

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6. Fair Value

 

Fair value measurements and disclosures relate primarily to the Partnership’s derivative positions discussed in Note 5. The following table presents the derivative instruments carried at fair value as of June 30, 2012 and December 31, 2011 (in thousands):

 

As of June 30, 2012

 

Assets

 

Liabilities

 

Significant other observable inputs (Level 2)

 

 

 

 

 

Commodity contracts

 

$

22,846

 

$

(27,644

)

Significant unobservable inputs (Level 3)

 

 

 

 

 

Commodity contracts

 

30,538

 

(982

)

Embedded derivatives in commodity contracts

 

10,409

 

(20,804

)

Total carrying value in Condensed Consolidated Balance Sheet

 

$

63,793

 

$

(49,430

)

 

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

)

 

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Table of Contents

 

The following table provides additional information about the significant unobservable inputs used in the valuation of Level 3 instruments as of June 30, 2012. The market approach is used for valuation of all instruments.

 

Level 3 Instrument

 

Balance Sheet
Classification

 

Unobservable
Inputs

 

Value Range

 

Time Period

 

Commodity contracts

 

Assets

 

Forward propane prices (per gallon)

 

$0.84

-

$0.92

 

Jan. 2013 - Dec. 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward isobutane prices (per gallon)

 

$1.32

-

$1.44

 

Jan. 2013 - Dec. 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward normal butane prices (per gallon)

 

$1.22

-

$1.30

 

Jan. 2013 - Dec. 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward natural gasoline prices (per gallon)

 

$1.75

-

$1.83

 

Jan. 2013 - Dec. 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude option volatilities (%)

 

18.41%

-

39.55%

 

Jul. 2012 - Dec. 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

Forward propane prices (per gallon)

 

$0.87

-

$0.89

 

Dec. 2012 - Mar. 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude option volatilities (%)

 

18.41%

-

39.55%

 

Jul. 2012 - Dec. 2012

 

 

 

 

 

 

 

 

 

 

 

 

 

Embedded derivatives in commodity contracts

 

Liability

 

Forward propane prices (per gallon)

 

$0.83

-

$0.92

 

Jul. 2012 - Dec. 2022

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward isobutane prices (per gallon)

 

$1.31

-

$1.44

 

Jul. 2012 - Dec. 2022

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward normal butane prices (per gallon)

 

$1.18

-

$1.30

 

Jul. 2012 - Dec. 2022

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward natural gasoline prices (per gallon)

 

$1.74

-

$1.83

 

Jul. 2012 - Dec. 2022

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward natural gas prices (per mmbtu)

 

$2.75

-

$5.79

 

Jul. 2012 - Dec. 2022

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Probability of renewal (1)

 

 

0%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Asset

 

ERCOT Pricing (per MegaWatt Hour) (2)

 

$25.38

-

$94.26

 

Jul. 2012 - Dec. 2014

 

 

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(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.

 

(2)          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 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 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 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 June 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 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.

 

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Table of Contents

 

Changes in Level 3 Fair Value Measurements

 

The table below includes a rollforward of the balance sheet amounts for the three and six months ended June 30, 2012 and 2011 for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands).

 

 

 

Three months ended June 30, 2012

 

 

 

Commodity
Derivative
Contracts (net)

 

Embedded
Derivatives in
Commodity
Contracts (net)

 

Fair value at beginning of period

 

$

(17,450

)

$

(60,804

)

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

 

46,290

 

48,109

 

Settlements

 

716

 

2,300

 

Fair value at end of period

 

$

29,556

 

$

(10,395

)

 

 

 

 

 

 

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)

 

$

43,894

 

$

47,300

 

 

 

 

Three months ended June 30, 2011

 

 

 

Commodity
Derivative

Contracts (net)

 

Embedded
Derivatives in
Commodity
Contracts (net)

 

Fair value at beginning of period

 

$

(35,906

)

$

(50,607

)

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

 

10,456

 

(2,825

)

Settlements

 

3,160

 

3,985

 

Fair value at end of period

 

$

(22,290

)

$

(49,447

)

 

 

 

 

 

 

The amount of total gains (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)

 

$

10,206

 

$

(2,429

)

 

 

 

Six months ended June 30, 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)

 

34,214

 

37,671

 

Settlements

 

(1,693

)

5,838

 

Fair value at end of period

 

$

29,556

 

$

(10,395

)

 

 

 

 

 

 

The amount of total gain 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)

 

$

30,304

 

$

36,698

 

 

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Six months ended June 30, 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)

 

(12,537

)

(22,105

)

Settlements

 

4,604

 

7,594

 

Fair value at end of period

 

$

(22,290

)

$

(49,447

)

 

 

 

 

 

 

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)

 

$

(10,578

)

$

(20,277

)

 


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

 

7. Inventories

 

Inventories consist of the following (in thousands):

 

 

 

June 30, 2012

 

December 31, 2011

 

NGLs

 

$

12,470

 

$

32,352

 

Spare parts, materials and supplies

 

9,739

 

8,654

 

Total inventories

 

$

22,209

 

$

41,006

 

 

8. Goodwill

 

Changes in goodwill for the six months ended June 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 June 30, 2012

 

24,324

 

62,445

 

76,664

 

9,854

 

173,287

 

Cumulative impairment (2)

 

(18,851

)

 

 

(9,854

)

(28,705

)

Balance as of June 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.

 

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9. Long-Term Debt

 

Debt is summarized below (in thousands):

 

 

 

June 30, 2012

 

December 31, 2011

 

Credit Facility

 

 

 

 

 

Revolving credit facility, 4% interest, due September 2017

 

$

217,865

 

$

66,000

 

 

 

 

 

 

 

Senior Notes (1)

 

 

 

 

 

2018 Senior Notes, 8.75% interest, net of discount of $119 and $129, respectively, issued April and May 2008 and due April 2018

 

80,993

 

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 $873 and $921, respectively, issued February and March 2011 and due August 2021

 

499,127

 

499,079

 

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

 

700,000

 

700,000

 

Total long-term debt

 

$

1,997,985

 

$

1,846,062

 

 


(1)          The estimated aggregate fair value of the senior notes (collectively, the “Senior Notes”) was approximately $1,853.3 million and $1,880.7 million as of June 30, 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

 

On June 29, 2012, the Partnership amended the 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 quarter ended June 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 Partnership’s wholly-owned subsidiaries, other than MarkWest Liberty Midstream and its subsidiaries, and collateralized by substantially all of the Partnership’s assets and those of its wholly-owned subsidiaries, other than MarkWest Liberty Midstream and its subsidiaries. As of June 30, 2012, the Partnership had approximately $217.9 million of borrowings outstanding and approximately $22.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $959.8 million available for borrowing.

 

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 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 were used to partially fund the Partnership’s 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, which were used to partially fund the Keystone Acquisition.

 

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Table of Contents

 

Distributions of Available Cash

 

Quarter Ended

 

Distribution Per
Common Unit

 

Declaration Date

 

Record Date

 

Payment Date

 

June 30, 2012

 

$

0.80

 

July 26, 2012

 

August 6, 2012

 

August 14, 2012

 

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

 

 

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 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 that management considers 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 however those delays exacerbated construction conditions. In addition, the Partnership continued to experience extraordinary weather events in the first quarter of 2012 which have 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 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 has completed construction of interim compression and transportation facilities and is providing alternative processing services to mitigate the impact of these delays.

 

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Table of Contents

 

12. 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 six months ended June 30, 2012 and 2011 is as follows (in thousands):

 

 

 

Six months ended June 30, 2012

 

 

 

Corporation

 

Partnership

 

Eliminations

 

Consolidated

 

Income before provision for income tax

 

$

94,600

 

$

155,621

 

$

2,206

 

$

252,427

 

Federal statutory rate

 

35

%

0

%

0

%

 

 

Federal income tax at statutory rate

 

33,110

 

 

 

33,110

 

Permanent items

 

16

 

 

 

16

 

State income taxes, net of federal benefit

 

4,259

 

765

 

 

5,024

 

Provision on income from Class A units (1)

 

10,868

 

 

 

10,868

 

Provision for income tax

 

$

48,253

 

$

765

 

$

 

$

49,018

 

 

 

 

Six months ended June 30, 2011

 

 

 

Corporation

 

Partnership

 

Eliminations

 

Consolidated

 

(Loss) income before provision for income tax

 

$

(2,541

)

$

20,951

 

$

(3,298

)

$

15,112

 

Federal statutory rate

 

35

%

0

%

0

%

 

 

Federal income tax at statutory rate

 

(889

)

 

 

(889

)

Permanent items

 

(5

)

 

 

(5

)

State income taxes, net of federal benefit

 

(72

)

107

 

 

35

 

Provision on income from Class A units (1)

 

1,311

 

 

 

1,311

 

Other

 

126

 

 

 

126

 

Provision for income tax

 

$

471

 

$

107

 

$

 

$

578

 

 


(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.

 

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Table of Contents

 

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 six months ended June 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 June 30,

 

Six months ended June 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Net income (loss) attributable to the Partnership

 

$

186,908

 

$

78,497

 

$

202,928

 

$

(5,532

)

Less: Income allocable to phantom units

 

1,209

 

719

 

1,391

 

847

 

Income (loss) available for common unitholders - basic

 

185,699

 

77,778

 

201,537

 

(6,379

)

Add: Income allocable to phantom units and DER expense

 

1,218

 

 

1,414

 

 

Income (loss) available for common unitholders - diluted

 

$

186,917

 

$

77,778

 

$

202,951

 

$

(6,379

)

 

 

 

 

 

 

 

 

 

 

Weighted average common units outstanding - basic

 

106,825

 

75,160

 

101,833

 

74,847

 

Potential common shares (Class B and phantom units)

 

20,643

 

106

 

20,698

 

 

Weighted average common units outstanding - diluted

 

127,468

 

75,266

 

122,531

 

74,847

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

Basic

 

$

1.74

 

$

1.03

 

$

1.98

 

$

(0.09

)

Diluted

 

$

1.47

 

$

1.03

 

$

1.66

 

$

(0.09

)

 


(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.

 

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 Partnership’s segment profit measure, Operating income before items not allocated to segments, for the three and six months ended June 30, 2012 and 2011 and capital expenditures for the six months ended June 30, 2012 and 2011 for the reported segments (in thousands).

 

Three months ended June 30, 2012:

 

 

 

Southwest

 

Northeast

 

Liberty

 

Gulf Coast

 

Total

 

Segment revenue

 

$

189,162

 

$

42,051

 

$

59,477

 

$

20,997

 

$

311,687

 

Purchased product costs

 

91,792

 

12,921

 

8,018

 

 

112,731

 

Net operating margin

 

97,370

 

29,130

 

51,459

 

20,997

 

198,956

 

Facility expenses

 

23,034

 

4,932

 

13,647

 

9,607

 

51,220

 

Portion of operating income (loss) attributable to non-controlling interests

 

1,590

 

 

(113

)

 

1,477

 

Operating income before items not allocated to segments

 

$

72,746

 

$

24,198

 

$

37,925

 

$

11,390

 

$

146,259

 

 

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Three months ended June 30, 2011:

 

 

 

Southwest

 

Northeast

 

Liberty

 

Gulf Coast

 

Total

 

Segment revenue

 

$

235,575

 

$

53,676

 

$

48,337

 

$

24,683

 

$

362,271

 

Purchased product costs

 

128,988

 

15,702

 

9,890

 

 

154,580

 

Net operating margin

 

106,587

 

37,974

 

38,447

 

24,683

 

207,691

 

Facility expenses

 

20,855

 

6,929

 

7,269

 

8,312

 

43,365

 

Portion of operating income attributable to non-controlling interests

 

1,346

 

 

15,182

 

 

16,528

 

Operating income before items not allocated to segments

 

$

84,386

 

$

31,045

 

$

15,996

 

$

16,371

 

$

147,798

 

 

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 June 30, 2012 and 2011 (in thousands):

 

 

 

Three months ended June 30,

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Total segment revenue

 

$

311,687

 

$

362,271

 

Derivative gain not allocated to segments

 

136,067

 

40,590

 

Revenue deferral adjustment (1)

 

(1,701

)

(2,422

)

Total revenue

 

$

446,053

 

$

400,439

 

 

 

 

 

 

 

Operating income before items not allocated to segments

 

$

146,259

 

$

147,798

 

 

 

 

 

 

 

Portion of operating income attributable to non-controlling interests

 

1,477

 

16,528

 

Derivative gain not allocated to segments

 

188,792

 

37,917

 

Revenue deferral adjustment (1)