10-Q 1 a15-17820_110q.htm 10-Q

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 September 30, 2015

 

OR

 

o  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from          to

 

Commission File Number 001-31239

 


 

MARKWEST ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware

 

27-0005456

(State or other jurisdiction of

 

(IRS Employer

incorporation or organization)

 

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 October 28, 2015, the number of the registrant’s common units and Class B units outstanding were 197,937,249 and 7,981,756, respectively.

 

 

 



Table of Contents

 

PART I—FINANCIAL INFORMATION

4

Item 1.

Financial Statements

4

 

Unaudited Condensed Consolidated Balance Sheets at September 30, 2015 and December 31, 2014

4

 

Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2015 and 2014

5

 

Unaudited Condensed Consolidated Statements of Changes in Equity for the nine months ended September 30, 2015 and 2014

6

 

Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2015 and 2014

7

 

Unaudited Notes to the Condensed Consolidated Financial Statements

8

Item 2.

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

41

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

61

Item 4.

Controls and Procedures

64

PART II—OTHER INFORMATION

65

Item 1.

Legal Proceedings

65

Item 1A.

Risk Factors

66

Item 6.

Exhibits

69

SIGNATURES

71

 

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

Condensate

 

A natural gas liquid with a low vapor pressure mainly composed of propane, butane, pentane and heavier hydrocarbon fractions

Credit Facility

 

Amended and restated revolving credit agreement, as amended from time to time

DER

 

Distribution equivalent right

Dth/d

 

Dekatherms per day

ERCOT

 

Electric Reliability Council of Texas

FASB

 

Financial Accounting Standards Board

FERC

 

Federal Energy Regulatory Commission

GAAP

 

Accounting principles generally accepted in the United States of America

Gal

 

Gallon

Gal/d

 

Gallons per day

LIBOR

 

London Interbank Offered Rate

Mcf

 

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

 

United States 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)

 

 

 

September 30, 2015

 

December 31, 2014

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents ($2,214 and $73,300, respectively)

 

$

28,067

 

$

108,887

 

Restricted cash

 

10,000

 

20,000

 

Receivables, net ($28,495 and $22,722, respectively)

 

275,131

 

302,259

 

Receivables from unconsolidated affiliates, net ($5,055 and $30, respectively)

 

18,074

 

7,097

 

Inventories ($3,724 and $2,434, respectively)

 

33,699

 

31,749

 

Fair value of derivative instruments

 

18,077

 

20,921

 

Deferred income taxes

 

10

 

9

 

Other current assets ($2,107 and $9,511, respectively)

 

20,160

 

46,731

 

Total current assets

 

403,218

 

537,653

 

 

 

 

 

 

 

Property, plant and equipment ($1,509,780 and $1,411,797, respectively)

 

11,038,482

 

9,923,524

 

Less: accumulated depreciation ($104,027 and $56,987, respectively)

 

(1,617,998

)

(1,270,624

)

Total property, plant and equipment, net

 

9,420,484

 

8,652,900

 

 

 

 

 

 

 

Other long-term assets:

 

 

 

 

 

Investment in unconsolidated affiliates ($770,712 and $696,784, respectively)

 

916,331

 

805,633

 

Intangibles, net of accumulated amortization of $386,988 and $350,327, respectively

 

745,258

 

809,277

 

Goodwill

 

79,729

 

82,411

 

Deferred financing costs, net of accumulated amortization of $27,856 and $31,298, respectively

 

54,154

 

52,919

 

Deferred contract cost, net of accumulated amortization of $0 and $3,198, respectively

 

20,000

 

20,052

 

Fair value of derivative instruments

 

16,863

 

16,507

 

Other long-term assets ($659 and $664, respectively)

 

3,270

 

3,426

 

Total assets

 

$

11,659,307

 

$

10,980,778

 

 

 

 

 

 

 

LIABILITIES AND EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

 

 

 

 

Accounts payable ($14,046 and $28,021, respectively)

 

$

223,927

 

$

270,997

 

Accrued liabilities ($6,163 and $48,793, respectively)

 

285,893

 

360,006

 

Deferred income taxes

 

1,395

 

239

 

Fair value of derivative instruments

 

854

 

 

Payables to unconsolidated affiliates, net ($1 and $5,500, respectively)

 

5,934

 

8,621

 

Total current liabilities

 

518,003

 

639,863

 

 

 

 

 

 

 

Deferred income taxes

 

348,565

 

357,260

 

Fair value of derivative instruments

 

20

 

 

Long-term debt, net of discounts of $6,648 and $6,196, respectively

 

4,755,352

 

3,621,404

 

Other long-term liabilities ($977 and $0, respectively)

 

160,250

 

169,012

 

 

 

 

 

 

 

Commitments and contingencies (Note 12)

 

 

 

 

 

 

 

 

 

 

 

Equity:

 

 

 

 

 

Common units (195,195 and 186,553 common units issued and outstanding, respectively)

 

4,556,217

 

4,758,243

 

Class B units (7,982 and 11,973 units issued and outstanding, respectively)

 

301,013

 

451,519

 

Non-controlling interest in consolidated subsidiaries

 

1,019,887

 

983,477

 

Total equity

 

5,877,117

 

6,193,239

 

Total liabilities and equity

 

$

11,659,307

 

$

10,980,778

 

 

Asset and liability amounts in parentheses represent the portion of the condensed consolidated balance attributable to a VIE.

 

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 September 30,

 

Nine months ended September 30,

 

 

 

2015

 

2014

 

2015

 

2014

 

Revenue:

 

 

 

 

 

 

 

 

 

Product sales

 

$

142,422

 

$

346,461

 

$

467,002

 

$

978,749

 

Service revenue

 

316,450

 

248,796

 

911,322

 

658,070

 

Derivative gain

 

15,419

 

11,829

 

22,925

 

1,109

 

Total revenue

 

474,291

 

607,086

 

1,401,249

 

1,637,928

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

Purchased product costs

 

108,741

 

246,801

 

355,517

 

674,189

 

Derivative gain related to purchased product costs

 

(9,043

)

(13,564

)

(2,248

)

(9,398

)

Facility expenses

 

95,028

 

83,579

 

275,394

 

250,829

 

Derivative loss related to facility expenses

 

515

 

1,128

 

606

 

2,905

 

Selling, general and administrative expenses

 

35,981

 

28,860

 

105,587

 

91,851

 

Depreciation

 

128,749

 

105,072

 

370,250

 

311,079

 

Amortization of intangible assets

 

15,678

 

16,313

 

47,100

 

48,256

 

Impairment expense

 

 

 

25,523

 

 

Loss (gain) on disposal of property, plant and equipment

 

1,458

 

(766

)

3,064

 

591

 

Accretion of asset retirement obligations

 

308

 

168

 

695

 

504

 

Total operating expenses

 

377,415

 

467,591

 

1,181,488

 

1,370,806

 

Income from operations

 

96,876

 

139,495

 

219,761

 

267,122

 

 

 

 

 

 

 

 

 

 

 

Other income (expense):

 

 

 

 

 

 

 

 

 

Equity in earnings (loss) from unconsolidated affiliates

 

7,699

 

(1,555

)

11,473

 

(2,026

)

Interest expense

 

(51,498

)

(39,448

)

(153,642

)

(123,823

)

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

 

(1,632

)

(1,469

)

(4,829

)

(5,742

)

Loss on redemption of debt

 

(29

)

 

(117,889

)

 

Miscellaneous income, net

 

19

 

55

 

113

 

117

 

Income (loss) before provision for income tax

 

51,435

 

97,078

 

(45,013

)

135,648

 

 

 

 

 

 

 

 

 

 

 

Provision for income tax expense (benefit):

 

 

 

 

 

 

 

 

 

Current

 

125

 

39

 

289

 

365

 

Deferred

 

2,104

 

10,991

 

(13,637

)

20,271

 

Total provision for income tax expense (benefit)

 

2,229

 

11,030

 

(13,348

)

20,636

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

49,206

 

86,048

 

(31,665

)

115,012

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to non-controlling interest

 

(20,079

)

(8,614

)

(49,777

)

(16,109

)

Net income (loss) attributable to the Partnership’s unitholders

 

$

29,127

 

$

77,434

 

$

(81,442

)

$

98,903

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

Basic

 

$

0.15

 

$

0.43

 

$

(0.44

)

$

0.58

 

Diluted

 

$

0.15

 

$

0.41

 

$

(0.44

)

$

0.54

 

Weighted average number of outstanding common units:

 

 

 

 

 

 

 

 

 

Basic

 

191,908

 

176,757

 

188,502

 

166,792

 

Diluted

 

200,679

 

189,440

 

188,502

 

182,105

 

Cash distribution declared per common unit

 

$

0.92

 

$

0.88

 

$

2.73

 

$

2.61

 

 

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

 

Amount

 

Units

 

Amount

 

Interest

 

Total Equity

 

December 31, 2014

 

186,553

 

$

4,758,243

 

11,973

 

$

451,519

 

$

983,477

 

$

6,193,239

 

Issuance of units in public offerings, net of offering costs

 

4,451

 

237,929

 

 

 

 

237,929

 

Conversion of Class B units to common units

 

3,991

 

150,506

 

(3,991

)

(150,506

)

 

 

Distributions paid

 

 

(516,032

)

 

 

(51,028

)

(567,060

)

Contributions from non-controlling interest

 

 

 

 

 

30,712

 

30,712

 

Sale of equity interest in a joint venture

 

 

 

 

 

11,319

 

11,319

 

Transfer of interest due to sale of joint venture

 

 

4,370

 

 

 

(4,370

)

 

Share-based compensation activity

 

200

 

8,741

 

 

 

 

8,741

 

Deferred income tax impact from changes in equity

 

 

(6,098

)

 

 

 

(6,098

)

Net (loss) income

 

 

(81,442

)

 

 

49,777

 

(31,665

)

September 30, 2015

 

195,195

 

$

4,556,217

 

7,982

 

$

301,013

 

$

1,019,887

 

$

5,877,117

 

 

 

 

Common Units

 

Class B Units

 

Non-
controlling

 

 

 

Redeemable
Non-
controlling
Interest
(Temporary

 

 

 

Units

 

Amount

 

Units

 

Amount

 

Interest

 

Total Equity

 

Equity)

 

December 31, 2013

 

157,766

 

$

3,476,295

 

15,964

 

$

602,025

 

$

719,813

 

$

4,798,133

 

$

235,617

 

Issuance of units in public offerings, net of offering costs

 

16,057

 

1,054,195

 

 

 

 

1,054,195

 

 

Conversion of Class B units to common units

 

3,991

 

150,506

 

(3,991

)

(150,506

)

 

 

 

Distributions paid

 

 

(434,654

)

 

 

(930

)

(435,584

)

 

Redeemable non-controlling interest classified as temporary equity

 

 

 

 

 

173,210

 

173,210

 

(173,210

)

Elimination of non-controlling interest from deconsolidation of a subsidiary

 

 

 

 

 

(6,592

)

(6,592

)

 

Share-based compensation  activity

 

211

 

5,042

 

 

 

 

5,042

 

 

Deferred income tax impact from changes in equity

 

 

(30,058

)

 

 

 

(30,058

)

 

Net income

 

 

98,903

 

 

 

16,109

 

115,012

 

 

September 30, 2014

 

178,025

 

$

4,320,229

 

11,973

 

$

451,519

 

$

901,610

 

$

5,673,358

 

$

62,407

 

 

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)

 

 

 

Nine months ended September 30,

 

 

 

2015

 

2014

 

Cash flows from operating activities:

 

 

 

 

 

Net (loss) income

 

$

(31,665

)

$

115,012

 

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

 

 

 

 

 

Depreciation

 

370,250

 

311,079

 

Amortization of intangible assets

 

47,100

 

48,256

 

Impairment expense

 

25,523

 

 

Loss on redemption of debt

 

117,889

 

 

Amortization of deferred financing costs and debt discount

 

4,829

 

5,742

 

Accretion of asset retirement obligations

 

695

 

504

 

Amortization of deferred contract cost

 

52

 

1,103

 

Phantom unit compensation expense

 

14,861

 

13,989

 

Equity in (earnings) loss from unconsolidated affiliates

 

(11,473

)

2,026

 

Distributions from unconsolidated affiliates

 

46,485

 

7,186

 

Unrealized loss (gain) on derivative instruments

 

3,361

 

(18,162

)

Loss on disposal of property, plant and equipment

 

3,064

 

591

 

Deferred income taxes

 

(13,637

)

20,271

 

Changes in operating assets and liabilities:

 

 

 

 

 

Receivables

 

29,479

 

(47,570

)

Receivables from unconsolidated affiliates

 

(10,977

)

3,682

 

Inventories

 

(1,504

)

(23,437

)

Other current assets

 

26,571

 

2,094

 

Accounts payable and accrued liabilities

 

(40,225

)

35,629

 

Payables to unconsolidated affiliates

 

(2,687

)

7,147

 

Other long-term assets

 

156

 

218

 

Other long-term liabilities

 

(9,698

)

10,720

 

Net cash flows provided by operating activities

 

568,449

 

496,080

 

 

 

 

 

 

 

Cash flows from investing activities:

 

 

 

 

 

Restricted cash

 

10,000

 

 

Capital expenditures

 

(1,230,979

)

(1,771,900

)

Investment in unconsolidated affiliates

 

(145,311

)

(205,855

)

Proceeds from sale of equity interest in unconsolidated affiliate

 

 

341,137

 

Proceeds from disposal of property, plant and equipment

 

2,735

 

21,573

 

Net cash flows used in investing activities

 

(1,363,555

)

(1,615,045

)

 

 

 

 

 

 

Cash flows from financing activities:

 

 

 

 

 

Proceeds from public equity offerings, net

 

237,929

 

1,054,195

 

Proceeds from Credit Facility

 

1,844,900

 

2,484,400

 

Payments of Credit Facility

 

(1,280,500

)

(1,958,500

)

Proceeds from long-term debt

 

1,848,875

 

 

Payments of long-term debt

 

(1,280,000

)

 

Payments of premiums on redemption of long-term debt

 

(103,209

)

 

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

 

(20,558

)

(2,045

)

Proceeds from sale of equity interest in joint venture

 

11,319

 

 

Contributions from non-controlling interest

 

30,712

 

 

Payments of SMR liability

 

(2,001

)

(1,823

)

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

 

(6,121

)

(8,947

)

Payment of distributions to common unitholders

 

(516,032

)

(434,654

)

Payment of distributions to non-controlling interest

 

(51,028

)

(930

)

Net cash flows provided by financing activities

 

714,286

 

1,131,696

 

 

 

 

 

 

 

Net (decrease) increase in cash and cash equivalents

 

(80,820

)

12,731

 

Cash and cash equivalents at beginning of period

 

108,887

 

85,305

 

Cash and cash equivalents at end of period

 

$

28,067

 

$

98,036

 

 

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, processing and transportation of natural gas; the gathering, transportation, fractionation, storage and marketing of NGLs; and the gathering and transportation of crude oil. The Partnership has a leading presence in many natural gas resource plays including the Marcellus Shale, Utica Shale, Huron/Berea Shale, Haynesville Shale, Woodford Shale and Granite Wash formations.

 

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, 2014. 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 nine months ended September 30, 2015 are not necessarily indicative of results for the full year 2015 or any other future period.

 

The Partnership’s unaudited condensed consolidated financial statements include all majority-owned or controlled subsidiaries. In addition, MarkWest Utica EMG, L.L.C. (“MarkWest Utica EMG”), a VIE for which the Partnership has been determined to be the primary beneficiary, is included in the condensed consolidated financial statements (See Note 4). Intercompany investments, accounts and transactions have been eliminated. The Partnership’s investments in which the Partnership exercises significant influence but does not control and does not have a controlling financial interest, are accounted for using the equity method.  The Partnership’s investments in VIEs, in which the Partnership exercises significant influence but does not control and is not the primary beneficiary, are also accounted for using the equity method.

 

2.  Recent Accounting Pronouncements

 

In May 2014, the FASB issued ASU 2014-09 — Revenue from Contracts with Customers (“ASU 2014-09”) that will supersede current revenue recognition guidance.  ASU 2014-09 is intended to provide companies with a single comprehensive model to use for all revenue arising from contracts with customers, which would include real estate sales transactions.  ASU 2014-09 is effective for the Partnership as of January 1, 2018 and must be adopted using either a full retrospective approach for all periods presented in the period of adoption (with some limited relief provided) or a modified retrospective approach.  Early adoption as of January 1, 2017 is permitted.  The Partnership is in the early stages of evaluating ASU 2014-09 and has not yet determined the impact on the Partnership’s condensed consolidated financial statements.

 

In August 2014, the FASB issued ASU 2014-15 — Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”), that provides guidance on management’s responsibility to perform interim and annual assessments of an entity’s ability to continue as a going concern and provides related disclosure requirements. ASU 2014-15 is effective for the Partnership as of December 31, 2016 and early adoption is permitted. The Partnership evaluated ASU 2014-15 and has determined the impact is not material to the Partnership’s condensed consolidated financial statements.

 

In February 2015, the FASB issued ASU 2015-02 — Consolidation (Topic 810): Amendments to the Consolidation Analysis (“ASU 2015-02”) that will modify current consolidation guidance. ASU 2015-02 makes changes to the variable interest model, including modifying the evaluation of whether limited partnerships or similar legal entities are VIEs and amending the guidance for assessing how relationships of related parties affect the consolidation analysis of VIEs. ASU 2015-02 is effective for the Partnership as of January 1, 2016 and early adoption is permitted. The Partnership evaluated ASU 2015-02 and has determined the impact is not material to the Partnership’s condensed consolidated financial statements.

 

In April 2015 and August 2015, the FASB issued ASU 2015-03 and ASU 2015-15 — Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03 and 2015-15”) that will modify the presentation of debt issuance costs related to debt other than lines of credit such that they are presented in the balance sheet as a direct deduction from the carrying amount of the debt liability.  ASU 2015-03 and 2015-15 is effective for the Partnership as of January 1, 2016 and early adoption is permitted. The Partnership evaluated ASU 2015-03 and 2015-15 and has determined the impact is not material to the Partnership’s condensed consolidated financial statements.

 

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3.  Merger

 

Merger Agreement

 

On July 11, 2015, the Partnership entered into an Agreement and Plan of Merger (the “Merger Agreement”) with MPLX LP (“MPLX”), MPLX GP LLC, the general partner of MPLX (“MPLX GP”), Sapphire Holdco LLC, a wholly owned subsidiary of MPLX (“Merger Sub” and, together with MPLX and MPLX GP, the “MPLX Entities”), and, for certain limited purposes set forth in the Merger Agreement, Marathon Petroleum Corporation, the parent of MPLX GP (“MPC”).

 

Pursuant to the Merger Agreement, Merger Sub will be merged with and into the Partnership (the “Merger”), with the Partnership surviving the Merger as a wholly owned subsidiary of MPLX.  After the Merger, the Partnership’s common units will cease to be publicly traded.

 

Under the Merger Agreement, MPC will contribute $675 million to MPLX, without receiving any new equity in exchange, and, at the effective time of the Merger (the “Effective Time”), (a) each outstanding Partnership common unit (the “Common Units”) will be converted into the right to receive 1.09 MPLX common units (the “MPLX Common Units” and, such consideration, the “Common Equity Consideration”) and an amount in cash obtained by dividing $675 million by the number of Common Units plus the number of Canceled Awards (as defined below) plus the number of Partnership Class B units (the “Class B Units”), in each case outstanding as of immediately prior to the Effective Time (together with the Common Equity Consideration, the “Common Merger Consideration”) and (b) each outstanding Class B Unit will be converted into the right to receive one MPLX Class B unit (the “MPLX Class B Units”).  Under the Merger Agreement, at the Effective Time, the Partnership Class A units, all of which are owned by wholly owned subsidiaries of the Partnership, will be converted into a specified number of MPLX Class A units, as more fully described in the Merger Agreement.

 

As a result of the Merger, each phantom unit under the Partnership’s equity plans outstanding immediately prior to the Effective Time will become fully vested and converted into an equivalent number of Common Units, which will be canceled and converted into the right to receive the Common Merger Consideration (the “Canceled Awards”). As of the Effective Time, each DER award will be canceled and the holder thereof will cease to have any rights with respect thereto, other than the right to receive distributions declared or made (but not yet paid) by the Partnership prior to the Effective Time. The payments pursuant to this paragraph are subject to any applicable withholding taxes.

 

The completion of the Merger is subject to certain customary conditions, including (a) the approval of the Merger Agreement by the Partnership’s unitholders entitled to vote thereon and (b) the approval of the MPLX Common Units comprising the Common Equity Consideration for listing on the New York Stock Exchange.  Each of the Partnership’s and MPLX’s obligation to complete the Merger is also subject to certain additional customary conditions, including (i) subject to specified standards, the accuracy of the representations and warranties of the other party and (ii) performance in all material respects by the other party of its obligations under the Merger Agreement. The registration statement filed by MPLX with respect to the Merger and Common Equity Consideration was declared effective on October 29, 2015.  The Partnership’s special unitholders meeting to consider and vote on a proposal to approve the Merger Agreement and the transactions contemplated thereby, has been scheduled to be held on December 1, 2015 at the Partnership’s offices located in Denver, Colorado.

 

The Merger Agreement contains customary representations and warranties from both the Partnership and MPLX, and also contains customary pre-closing covenants, including covenants requiring each of them to use their respective reasonable best efforts to cause the Merger to be consummated, and covenants requiring the Partnership and MPLX, subject to certain exceptions, to carry on their respective businesses in the ordinary course of business consistent with past practice during the period between the execution of the Merger Agreement and the closing of the Merger.

 

The Merger Agreement also contains a “no shop” provision that, in general, restricts the Partnership’s ability to solicit third-party acquisition proposals or provide information to or engage in discussions or negotiations with third parties that have made or that might make an acquisition proposal. The no shop provision is subject to certain limited exceptions that allow the Partnership, under certain circumstances and in compliance with certain obligations, to provide information and participate in discussions and negotiations with respect to unsolicited third-party acquisition proposals that would reasonably be expected to lead to a Superior Proposal (as defined in the Merger Agreement).

 

The Merger Agreement contains certain termination rights and provides that, upon termination of the Merger Agreement under specified circumstances, including, but not limited to, a change in the recommendation of the General Partner of the Partnership, the Partnership will pay MPLX a cash termination fee of $625 million.

 

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Under the Merger Agreement, the Partnership, MPC and the MPLX Entities have agreed that, prior to the closing of the Merger, MPLX GP will increase the size of its board of directors by two directors and will appoint two directors identified by the Partnership to such board of directors, one of which shall be independent under the NYSE rules.  MPC has also agreed to appoint one director identified by the Partnership to the board of directors of MPC.  Both such appointments shall be effective immediately following the closing of the Merger.  The partnership has identified Mr. Frank M. Semple as one of the two directors to be appointed to the MPLX GP board, and Mr. Semple has also been identified by the Partnership to be appointed to the MPC board.  The Merger Agreement also provides that MPC has agreed to fill the next vacancy on the Board of Directors of MPLX GP that arises following date of the closing of the merger, by first considering the nomination of an individual who was an independent director of the Partnership’s general partner as of the date of the Merger Agreement.  In addition, pursuant to the Merger Agreement, certain of the Partnership’s executive officers will retain their titles and become executive officers of MPLX GP and MPC, as the case may be.

 

Voting Agreement

 

On July 11, 2015, and in connection with the execution of the Merger Agreement, M&R MWE Liberty, LLC, which holds 7,352,691 Common Units (representing approximately 3.7% of the outstanding Common Units as of October 28, 2015), entered into a Voting Agreement with the MPLX Entities (the “Voting Agreement”), pursuant to which such holder has agreed, among other things, to vote (or cause to be voted) all Common Units owned by such holder in favor of approving the Merger Agreement.  The Voting Agreement shall terminate upon termination of the Merger Agreement, and certain other specified events.

 

Lock-Up Agreement

 

On July 11, 2015, and in connection with the execution of the Merger Agreement, EMG Utica, LLC (“EMG Utica”), EMG Utica Condensate, LLC, the MPLX Entities, the Partnership and M&R MWE Liberty, L.L.C. entered into a Lock-Up Agreement (the “Lock-Up Agreement”), pursuant to which the parties thereto have agreed, among other things, not to convert any Class B Units into Common Units in connection with the Merger and that certain transfer restrictions will apply, during the six-month period following consummation of the Merger, to the MPLX Common Units that the holders of Class B Units will receive as Common Merger Consideration for its Common Units.  The MPLX Class B Units will have substantially similar rights and obligations, including registration rights, as those applicable to the Class B Units, other than there will be no transfer restrictions on the MPLX Common Units into which such MPLX Class B Units are convertible.  The MPLX Class B Units will be convertible into the Common Merger Consideration on July 1, 2016 and July 1, 2017.

 

As of September 30, 2015, MWE owned a 55% ownership interest in MarkWest Utica EMG Condensate, L.L.C. (“Utica Condensate”). Under the terms of the Lock-Up Agreement, MWE will purchase the remaining 45% interest in Utica Condensate for $83 million in connection with, and conditioned upon, the consummation of the Merger. Utica Condensate’s business is conducted solely through its 60% ownership interest in Ohio Condensate Company, L.L.C. (“Ohio Condensate”). The owner of the remaining 40% interest in Ohio Condensate has certain participatory rights and as a result Ohio Condensate has been and will continue to be accounted for as an equity method investment.

 

4.  Variable Interest Entity

 

MarkWest Utica EMG

 

Effective January 1, 2012, the Partnership and EMG Utica (together the “Members”) 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.

 

In February 2013, the Members entered into the Amended and Restated Limited Liability Company Agreement of MarkWest Utica EMG (“Amended Utica LLC Agreement”) which replaced the original agreement. Pursuant to the Amended Utica LLC Agreement, the aggregate funding commitment of EMG Utica increased to $950.0 million (the “Minimum EMG Investment”).  EMG Utica was required to fund all capital until the Minimum EMG Investment was satisfied, which occurred in May 2013. After EMG Utica funded the Minimum EMG Investment, the Partnership was required to fund, as needed, 100% of future capital for MarkWest Utica EMG until such time as the aggregate capital that had been contributed by the Members reached $2.0 billion, which occurred in November 2014. 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”), EMG Utica has the right, but not the obligation, to fund up to 10% of each capital call for MarkWest Utica EMG, and the Partnership will be required to fund all remaining capital not elected to be funded by EMG Utica. After the Second Equalization Date, the Partnership and EMG Utica will have the right, but not the obligation, to fund their pro rata portion (based on their respective investment balances) of any additional required capital and may also fund additional capital that the other party elects not to fund. As of September 30, 2015, EMG Utica has contributed approximately $992.3 million and the Partnership has contributed approximately $1,430.6 million to MarkWest Utica EMG.

 

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Under the Amended Utica LLC Agreement, after EMG Utica has contributed more than $500.0 million to MarkWest Utica EMG and prior to December 31, 2016, EMG Utica’s investment balance will also be increased by a quarterly special non-cash allocation of income (“Preference Amount”) that is based upon the amount of capital contributed by EMG Utica in excess of $500.0 million. No Preference Amount will accrue to EMG Utica’s investment balance after December 31, 2016. EMG Utica received a special non-cash allocation of income of approximately $11.3 million and approximately $32.5 million for the three and nine months ended September 30, 2015, respectively. EMG Utica received a special non-cash allocation of income of approximately $9.3 million and approximately $27.2 million for the three and nine months ended September 30, 2014, respectively.  The Preference Amount along with the cash contributions result in investment balances of the Partnership and EMG Utica as of September 30, 2015 in the ratio of 56% and 44%, respectively.

 

Under the Amended Utica LLC Agreement, the Partnership will continue to receive 60% of cash generated by MarkWest Utica EMG that is available for distribution until the earlier of December 31, 2016 and the date on which the Partnership’s investment balance equals 60% of the aggregate investment balances of the Members. After the earlier of those dates, cash generated by MarkWest Utica EMG that is available for distribution will be allocated to the Members in proportion to their respective investment balances.

 

The Partnership has determined that MarkWest Utica EMG does not meet the business scope exception to be excluded as a VIE due to the unique investment structure, discussed above, which creates a de-facto agent relationship between the Members, as EMG Utica has funded portions of the Partnership’s ownership in MarkWest Utica EMG. MarkWest Utica EMG’s inability to fund its planned activities without additional subordinated financial support qualifies it to be a VIE. The Partnership has concluded that it is the primary beneficiary of MarkWest Utica EMG. As the primary beneficiary of MarkWest Utica EMG, the Partnership consolidates the entity and recognizes non-controlling interest and redeemable non-controlling interest. The decision to consolidate MarkWest Utica EMG is re-evaluated quarterly and is subject to change. Upon the earlier of December 31, 2016 and the date on which the Partnership’s investment balance equals 60% of the aggregate investment balances of the Members, the de-facto agent relationship between the Members will no longer exist.

 

The assets of MarkWest Utica EMG are the property of MarkWest Utica EMG and are not available to the Partnership for any other purpose, including as collateral for its secured debt (See Notes 10 and 16). MarkWest Utica EMG’s asset balances can only be used to settle its own obligations. The liabilities of MarkWest Utica EMG do not represent additional claims against the Partnership’s general assets and the creditors or beneficial interest holders of MarkWest Utica EMG 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 MarkWest Utica EMG includes its equity investment, any additional capital contribution commitments and any operating expenses incurred by the subsidiary operator in excess of its compensation received for the performance of the operating services. The Partnership did not provide any financial support to MarkWest Utica EMG that it was not contractually obligated to provide during the nine months ended September 30, 2015 and 2014.

 

Ohio Gathering

 

Ohio Gathering Company, L.L.C. (“Ohio Gathering”) is a subsidiary of MarkWest Utica EMG and is engaged in providing natural gas gathering services in the Utica Shale in eastern Ohio. Prior to June 1, 2014, MarkWest Utica EMG, as the primary beneficiary of a VIE, consolidated Ohio Gathering.  Effective June 1, 2014 (“Summit Investment Date”), Summit Midstream Partners (“Summit”) exercised its option (“Ohio Gathering Option”) and increased its equity ownership (“Summit Equity Ownership”) from less than 1% to approximately 40% through a cash investment of approximately $341.1 million that Ohio Gathering received in 2014.  MarkWest Utica EMG received approximately $336.1 million as a distribution from Ohio Gathering as a result of the exercise of the Ohio Gathering Option.  Summit purchased its initial 1% equity interest and the Ohio Gathering Option from Blackhawk Midstream LLC (“Blackhawk”) in January 2014.  As of the Summit Investment Date, MarkWest Utica EMG was no longer deemed the primary beneficiary due to Summit’s voting rights on significant operating matters obtained as a result of its increased equity ownership in Ohio Gathering. As of the Summit Investment Date, the Partnership accounted for Ohio Gathering as an equity method investment.  Ohio Gathering’s net assets are reported under the caption Investment in unconsolidated affiliates on the Condensed Consolidated Balance Sheets.

 

For the nine months ended September 30, 2014, the Partnership’s condensed consolidated results of operations include the consolidated results of operations of Ohio Gathering through May 31, 2014.  For the three and four months ended September 30, 2014 and for the three and nine months ended September 30, 2015, the Partnership, through its consolidation of MarkWest Utica EMG, has reported its pro rata share of Ohio Gathering’s net income under the caption Equity in earnings (loss) from unconsolidated affiliates on the Condensed Consolidated Statements of Operations.  Ohio Gathering is considered to be a related party.  The Partnership receives engineering and construction and administrative management fee revenue and other direct personnel costs (“Operational Service” revenue) for operating Ohio Gathering.  The amount of Operational Service revenue related to Ohio Gathering for the three and nine

 

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months ended September 30, 2015 was approximately $3.8 million and $12.7 million, respectively, and is reported as Service revenue in the Condensed Consolidated Statements of Operations. The amount of Operational Service revenue related to Ohio Gathering for the three and nine months ended September 30, 2014 was approximately $6.0 million and $7.0 million, respectively, and is reported as Service revenue in the Condensed Consolidated Statements of Operations.

 

5. Other Equity Interests

 

Utica Condensate

 

In December 2013, the Partnership and The Energy & Minerals Group (“EMG”) (together the “Condensate Members”) executed an agreement (“Utica Condensate LLC Agreement”) to form Utica Condensate for the purpose of engaging in wellhead condensate gathering, stabilization, terminalling, storage and marketing in the state of Ohio. If Utica Condensate requires additional capital, each Condensate Member has the right, but not the obligation, to contribute capital in proportion to its ownership interest. As of September 30, 2015, the Partnership owned 55% of Utica Condensate.

 

Ohio Condensate

 

Utica Condensate’s business is conducted solely through its subsidiary, Ohio Condensate, which was formed in December 2013 through an agreement executed between Utica Condensate and Blackhawk (“Ohio Condensate LLC Agreement”), in which Utica Condensate and Blackhawk contributed cash in exchange for equity ownership interests of 99% and 1%, respectively. In January 2014, Summit purchased Blackhawk’s less than 1% equity interest and its option to purchase up to an additional equity ownership interest of 40% in Ohio Condensate (“Ohio Condensate Option”).  Effective as of the Summit Investment Date, Summit exercised the Ohio Condensate Option and increased its equity ownership from less than 1% to 40% through a cash investment of approximately $8.6 million.

 

As of September 30, 2015, Utica Condensate owned 60% of Ohio Condensate.  The Partnership sold approximately $17 million of assets under construction to Utica Condensate in December 2013 and received the $17 million in the first quarter of 2014.  The Partnership has recorded the proceeds in the Proceeds from disposal of property, plant and equipment in the accompanying Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2014.  Ohio Condensate is considered to be a related party.  The amount of Operational Service revenue related to Ohio Condensate for the three and nine months ended September 30, 2015 was approximately $0.9 million and $3.0 million, respectively, and is reported as Service revenue in the Condensed Consolidated Statements of Operations. The amount of Operational Service revenue related to Ohio Condensate for the three and nine months ended September 30, 2014 was approximately $0.8 million and $2.1 million, respectively, and is reported as Service revenue in the Condensed Consolidated Statements of Operations.

 

6. 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 plans, the Partnership executes a strategy governed by the risk management policy approved by the General Partner’s board of directors. The Partnership has a committee comprised of senior management that oversees risk management activities, continually monitors the risk management program and adjusts its strategy as 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 the Partnership to take speculative positions with its derivative contracts.

 

To mitigate its cash flow exposure to fluctuations in the price of NGLs, the Partnership has entered into derivative financial instruments relating to the future price of NGLs and crude oil. The Partnership currently manages the majority of its NGL price risk

 

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using direct product NGL derivative contracts. The Partnership enters into NGL derivative contracts when adequate market liquidity exists and future prices are satisfactory.

 

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

 

As a result of its current derivative positions, the Partnership has mitigated a portion of its expected commodity price risk through the fourth quarter of 2016. The Partnership would be exposed to additional commodity risk in certain situations such as if producers under deliver or over deliver product or when processing facilities are operated in different recovery modes. In the event the Partnership has derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions may be terminated.

 

All of the Partnership’s financial derivative positions are with financial institutions that are participating members of the Credit Facility (“participating bank group members”). Management conducts a standard credit review on counterparties to derivative contracts. There are no collateral requirements for derivative contracts between the Partnership and any participating bank group member. Specifically, the Partnership is not required to post collateral when it enters into derivative contracts with participating bank group members, as the participating bank group members have a collateral position in substantially all the wholly owned assets of the Partnership other than MarkWest Liberty Midstream & Resources, L.L.C. (“MarkWest Liberty Midstream”) and its subsidiaries and MarkWest Panola Pipeline, L.L.C. A separate agreement with certain participating bank group members allows MarkWest Liberty Midstream to enter into derivative positions without posting cash collateral.  The Partnership uses standardized agreements that allow for offset of certain positive and negative exposures (“master netting arrangements”) in the event of default or other terminating events, including bankruptcy.

 

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

 

As of September 30, 2015, 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

 

201,800

 

Natural Gas (MMBtu)

 

Long

 

375,385

 

NGLs (Gal)

 

Short

 

80,351,908

 

 

Embedded Derivatives in Commodity Contracts

 

The Partnership has a commodity contract with a producer in the Appalachia region that creates a floor on the spread between the NGL product sales price and the purchase price of natural gas with an equivalent Btu content (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 related to purchased product costs in the Condensed Consolidated Statement of Operations. 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 with the producer’s option to extend the agreement for successive five-year terms through December 31, 2032. As of September 30, 2015, the estimated fair value of this contract was a liability of $27.4 million and the recorded value was an asset of $21.1 million. The recorded asset does not include the inception fair value of the commodity contract related to the remaining extension period of October 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. For the three months ended September 30, 2015 and period from April 1, 2015 to September 30, 2015, approximately $2.5 million and $5.1 million, respectively, of the original inception value is no longer included in the inception value below as it is deemed to have settled.  See the following table for a reconciliation of the liability recorded for the embedded derivative as of September 30, 2015 (in thousands):

 

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Fair value of commodity contract

 

$

(27,352

)

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

 

(48,407

)

Derivative asset as of September 30, 2015

 

$

21,055

 

 

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 a plant location in the Southwest segment through the fourth quarter of 2017. The contract is currently fixed through the fourth quarter of 2015 with the ability to fix the commodity contract for its remaining years. In October, the Partnership extended the contract through fourth quarter of 2016.  Changes in the fair value of the derivative component of this contract are recognized as Derivative loss related to facility expenses in the Condensed Consolidated Statements of Operations. As of September 30, 2015, the estimated fair value of this contract was a liability of $0.6 million on the Condensed Consolidated Balance Sheet.

 

Financial Statement Impact of Derivative Contracts

 

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, 2014. The impact of the Partnership’s derivative instruments on its Condensed Consolidated Balance Sheets is summarized below (in thousands):

 

 

 

Assets

 

Liabilities

 

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

 

Fair Value at
September 30,
2015

 

Fair Value at
December 31,
2014

 

Fair Value at
September 30,
2015

 

Fair Value at
December 31,
2014

 

Commodity contracts(1)

 

 

 

 

 

 

 

 

 

Fair value of derivative contracts — current

 

$

18,077

 

$

20,921

 

$

(854

)

$

 

Fair value of derivative contracts — long-term

 

16,863

 

16,507

 

(20

)

 

Total

 

$

34,940

 

$

37,428

 

$

(874

)

$

 

 


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

 

Although certain derivative positions are subject to master netting agreements, the Partnership has elected not to offset any derivative assets and liabilities. The gross amounts in the table below equal the balances presented in the Condensed Consolidated Balance Sheets. The table below summarizes the impact if the Partnership had elected to net its derivative positions that are subject to master netting arrangements (in thousands):

 

 

 

Assets

 

Liabilities

 

As of September 30, 2015

 

Gross
Amounts of
Assets in the
Condensed
Consolidated
Balance
Sheet

 

Gross
Amounts
Not Offset in
the
Condensed
Consolidated
Balance
Sheet

 

Net
Amount

 

Gross
Amounts of
Liabilities in
the
Condensed
Consolidated
Balance
Sheet

 

Gross
Amounts
Not Offset in
the
Condensed
Consolidated
Balance
Sheet

 

Net
Amount

 

Current

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

$

13,356

 

$

(248

)

$

13,108

 

$

(248

)

$

248

 

$

 

Embedded derivatives in commodity contracts

 

4,721

 

 

4,721

 

(606

)

 

(606

)

Total current derivative instruments

 

18,077

 

(248

)

17,829

 

(854

)

248

 

(606

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Non-current

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

529

 

 

529

 

(20

)

 

(20

)

Embedded derivatives in commodity contracts

 

16,334

 

 

16,334

 

 

 

 

Total non-current derivative instruments

 

16,863

 

 

16,863

 

(20

)

 

(20

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total derivative instruments

 

$

34,940

 

$

(248

)

$

34,692

 

$

(874

)

$

248

 

$

(626

)

 

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Assets

 

Liabilities

 

As of December 31, 2014

 

Gross
Amounts of
Assets in the
Condensed
Consolidated
Balance
Sheet

 

Gross
Amounts
Not Offset in
the
Condensed
Consolidated
Balance
Sheet

 

Net
Amount

 

Gross
Amounts of
Liabilities in
the
Condensed
Consolidated
Balance
Sheet

 

Gross
Amounts
Not Offset in
the
Condensed
Consolidated
Balance
Sheet

 

Net
Amount

 

Current

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity contracts

 

$

18,652

 

$

 

$

18,652

 

$

 

$

 

$

 

Embedded derivatives in commodity contracts

 

2,269

 

 

2,269

 

 

 

 

Total current derivative instruments

 

20,921

 

 

20,921

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Non-current

 

 

 

 

 

 

 

 

 

 

 

 

 

Embedded derivatives in commodity contracts

 

16,507

 

 

16,507

 

 

 

 

Total non-current derivative instruments

 

16,507

 

 

16,507

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total derivative instruments

 

$

37,428

 

$

 

$

37,428

 

$

 

$

 

$

 

 

In the tables above, the Partnership does not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although the Partnership’s master netting arrangements would allow current and non-current positions to be offset in the event of default. Additionally, in the event of a default, the Partnership’s master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting tables presented above.

 

The impact of the Partnership’s derivative instruments on its Condensed Consolidated Statements of Operations is summarized below (in thousands):

 

Derivative contracts not designated as
hedging instruments and the location of gain

 

Three months ended September 30,

 

Nine months ended September 30,

 

or (loss) recognized in income

 

2015

 

2014

 

2015

 

2014

 

Revenue: Derivative gain (loss)

 

 

 

 

 

 

 

 

 

Realized gain (loss)

 

$

11,745

 

$

(254

)

$

27,865

 

$

(9,635

)

Unrealized gain (loss)

 

3,674

 

12,083

 

(4,940

)

10,744

 

Total revenue: derivative gain

 

15,419

 

11,829

 

22,925

 

1,109

 

 

 

 

 

 

 

 

 

 

 

Derivative gain (loss) related to purchased product costs

 

 

 

 

 

 

 

 

 

Realized gain (loss)

 

43

 

(667

)

63

 

(925

)

Unrealized gain

 

9,000

 

14,231

 

2,185

 

10,323

 

Total derivative gain related to purchased product costs

 

9,043

 

13,564

 

2,248

 

9,398

 

 

 

 

 

 

 

 

 

 

 

Derivative loss related to facility expenses

 

 

 

 

 

 

 

 

 

Unrealized (loss)

 

(515

)

(1,128

)

(606

)

(2,905

)

Total gain

 

$

23,947

 

$

24,265

 

$

24,567

 

$

7,602

 

 

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7. Fair Value

 

Fair value measurements and disclosures relate primarily to the Partnership’s derivative positions discussed in Note 6. Money market funds, which are included in Cash and cash equivalents on the Condensed Consolidated Balance Sheets, are measured at fair value and are included in Level 1 measurements of the valuation hierarchy. The following table presents the derivative instruments carried at fair value as of September 30, 2015 and December 31, 2014 (in thousands):

 

As of September 30, 2015

 

Assets

 

Liabilities

 

Significant other observable inputs (Level 2)

 

 

 

 

 

Commodity contracts

 

$

5,405

 

$

(95

)

Significant unobservable inputs (Level 3)

 

 

 

 

 

Commodity contracts

 

8,480

 

(173

)

Embedded derivatives in commodity contracts

 

21,055

 

(606

)

Total carrying value in Condensed Consolidated Balance Sheets

 

$

34,940

 

$

(874

)

 

As of December 31, 2014

 

Assets

 

Liabilities

 

Significant other observable inputs (Level 2)

 

 

 

 

 

Commodity contracts

 

$

14,812

 

$

 

Significant unobservable inputs (Level 3)

 

 

 

 

 

Commodity contracts

 

3,840

 

 

Embedded derivatives in commodity contracts

 

18,776

 

 

Total carrying value in Condensed Consolidated Balance Sheets

 

$

37,428

 

$

 

 

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The following table provides additional information about the significant unobservable inputs used in the valuation of Level 3 instruments as of September 30, 2015. The market approach is used for valuation of all instruments.

 

Level 3 Instrument

 

Balance
Sheet
Classification

 

Unobservable Inputs

 

Value Range

 

Time Period

 

 

 

 

 

 

 

 

 

Commodity contracts

 

Asset

 

Forward ethane prices (per gallon)

 

$0.20 - $0.21

 

Jan. 2016 - Dec. 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward propane prices (per gallon)

 

$0.46 - $0.48

 

Oct. 2015 - Sep. 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward isobutane prices (per gallon)

 

$0.61 - $0.64

 

Oct. 2015 - Mar. 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward normal butane prices (per gallon)

 

$0.56 - $0.62

 

Oct. 2015 - Mar. 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward natural gasoline prices (per gallon)

 

$0.94 - $0.99

 

Oct. 2015 - Dec. 2016

 

 

 

 

 

 

 

 

 

 

 

Liability

 

Forward ethane prices (per gallon)

 

$0.20 - $0.20

 

Oct. 2015 - Dec. 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward propane prices (per gallon)

 

$0.46 - $0.50

 

Oct. 2015 - Dec. 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward normal butane prices (per gallon)

 

$0.62 - $0.62

 

Oct. 2015 - Dec. 2015

 

 

 

 

 

 

 

 

 

Embedded derivatives in commodity contract

 

Asset

 

Forward propane prices (per gallon) (1)

 

$0.46 - $0.53

 

Oct. 2015 - Dec. 2022

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward isobutane prices (per gallon) (1)

 

$0.59 - $0.66

 

Oct. 2015 - Dec. 2022

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward normal butane prices (per gallon) (1)

 

$0.53 - $0.64

 

Oct. 2015 - Dec. 2022

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward natural gasoline prices (per gallon) (1)

 

$0.94 - $1.11

 

Oct. 2015 - Dec. 2022

 

 

 

 

 

 

 

 

 

 

 

 

 

Forward natural gas prices (per MMBtu) (2)

 

$2.37 - $3.42

 

Oct. 2015 - Dec. 2022

 

 

 

 

 

 

 

 

 

 

 

 

 

Probability of renewal (3)

 

0%

 

 

 

 

 

 

 

 

 

 

 

 

 

Liability

 

ERCOT Pricing (per MegaWatt Hour)

 

$23.07 - $25.68

 

Oct. 2015 - Dec. 2015

 


(1)         NGL prices used in the valuations are generally at the lower end of the range in the early years and increase over time.

 

(2)         Natural gas prices used in the valuations are generally at the lower end of the range in the early years and increase over time.

 

(3)         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

 

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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.

 

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 in the fair value of the derivative liabilities. The forward prices for the individual NGL products generally increase or decrease in a positive correlation with one another. An increase in crude option volatilities will generally result in an increase in the fair value of the Partnership’s derivative assets and derivative liabilities in commodity contracts.

 

Embedded derivative in commodity contracts (asset) - The embedded derivative asset relates to the natural gas purchase agreement embedded in a keep-whole processing agreement as discussed further in Note 6. Increases (decreases) in forward NGL prices result in an increase (decrease) in the fair value of the embedded derivative. An increase in the probability of renewal would result in a decrease in the fair value of the related embedded derivative asset.

 

Embedded derivative in commodity contracts (liability) - The embedded derivative liability relates to utilities costs discussed further in Note 6.  Increases in the forward ERCOT prices result in a decrease in the fair value of the embedded derivative liability.

 

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 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 Level 3 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 at least one other independent third-party pricing service. The valuations for the embedded derivative in the commodity contract 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 6, the Risk Department must develop forward price curves for NGLs and natural gas for periods in which price curves are not available from third-party pricing services due to insufficient market data. As of September 30, 2015, the Risk Department utilized internally developed price curves for the period of October 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 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 Risk Department’s estimated price curves.

 

Changes in Level 3 Fair Value Measurements

 

The tables below include a roll forward of the balance sheet amounts for the three and nine months ended September 30, 2015 and 2014 (including the change in fair value) for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands):

 

 

 

Three months ended September 30, 2015

 

 

 

Commodity Derivative
Contracts (net)

 

Embedded Derivatives
in Commodity
Contracts (net)

 

Fair value at beginning of period

 

$

4,778

 

$

11,736

 

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

 

11,388

 

7,671

 

Settlements

 

(7,859

)

1,042

 

Fair value at end of period

 

$

8,307

 

$

20,449

 

 

 

 

 

 

 

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)

 

$

6,276

 

$

10,103

 

 

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Table of Contents

 

 

 

Three months ended September 30, 2014

 

 

 

Commodity Derivative
Contracts (net)

 

Embedded Derivatives
in Commodity
Contracts (net)

 

Fair value at beginning of period

 

$

(2,092

)

$

(42,831

)

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

 

5,626

 

10,715

 

Settlements

 

(380

)

2,203

 

Fair value at end of period

 

$

3,154

 

$

(29,913

)

 

 

 

 

 

 

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)

 

$

4,109

 

$

11,609

 

 

 

 

Nine months ended September 30, 2015

 

 

 

Commodity Derivative
Contracts (net)

 

Embedded Derivatives
in Commodity
Contracts (net)

 

Fair value at beginning of period

 

$

3,840

 

$

18,776

 

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

 

18,311

 

(2,527

)

Settlements

 

(13,844

)

4,200

 

Fair value at end of period

 

$

8,307

 

$

20,449

 

 

 

 

 

 

 

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)

 

$

8,307

 

$

2,943

 

 

 

 

Nine months ended September 30, 2014

 

 

 

Commodity Derivative
Contracts (net)

 

Embedded Derivatives
in Commodity
Contracts (net)

 

Fair value at beginning of period

 

$

(5,460

)

$

(35,032

)

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

 

1,387

 

(1,352

)

Settlements

 

7,227

 

6,471

 

Fair value at end of period

 

$

3,154

 

$

(29,913

)

 

 

 

 

 

 

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)

 

$

3,926

 

$

716

 

 


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

 

8. Inventories

 

Inventories consist of the following (in thousands):

 

 

 

September 30, 2015

 

December 31, 2014

 

NGLs

 

$

4,771

 

$

9,687

 

Line fill

 

4,311

 

6,241

 

Spare parts, materials and supplies

 

24,617

 

15,821

 

Total inventories

 

$

33,699

 

$

31,749

 

 

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9. Impairment of Long-Lived Assets and Goodwill

 

Long-Lived Assets.  The Partnership’s policy is to evaluate whether there has been an impairment in the value of long-lived assets when certain events have taken place that indicate that the remaining balance may not be recoverable. The Partnership evaluates the carrying value of its long-lived assets and intangibles on at least a segment level and at lower levels when cash flows for specific assets can be identified.

 

An analysis completed during the first quarter of 2015 indicated a potential impairment of the Appleby asset grouping in the Southwest segment. Appleby is a gathering system in Nacogdoches County, Texas (“Appleby”).  In the first quarter of 2015, Appleby’s expected future cash flows were adversely impacted by declines in the forward price strip of natural gas and condensate.  The Partnership used a combination of the income and market approaches for determining the fair value of Appleby and recognized an impairment totaling approximately $22.8 million, of which approximately $16.8 million relates to intangibles and $6.0 million to property, plant and equipment for the nine months ended September 30, 2015.  This impairment is recorded as Impairment expense on the Condensed Consolidated Statements of Operations.

 

Goodwill.  The Partnership annually evaluates goodwill for impairment as of November 30, as well as whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount.

 

Management considered the decline in commodity prices and resulting decline in projected operating income to be an indicator of impairment of goodwill of the Western Oklahoma assets in our Southwest segment (“Western Oklahoma Reporting Unit”). The Partnership performed the first step of our goodwill impairment analysis as of February 28, 2015 and determined that the carrying value of the Western Oklahoma Reporting Unit exceeded its fair value. The Partnership completed the second step of its goodwill impairment analysis comparing the implied fair value of that reporting unit’s goodwill to the carrying amount of that goodwill and determined goodwill related to the Western Oklahoma Reporting Unit was fully impaired and recorded an impairment charge of $2.7 million during the three months ended March 31, 2015.

 

In completing these evaluations, management’s best estimates of the expected future results are the primary driver in determining the fair value. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of the goodwill impairment test will prove to be an accurate prediction of the future. Management estimated the fair value of the Partnership’s reporting units and asset grouping using a combination of the income and market approaches based on discounted future cash flows using significant unobservable inputs (Level 3).

 

There were no impairments recorded related to the Partnership’s other reporting units as a result of its analyses for the nine months ended September 30, 2015.

 

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10. Long-Term Debt

 

Debt is summarized below (in thousands):

 

 

 

September 30, 2015

 

December 31, 2014

 

Credit Facility

 

 

 

 

 

Credit Facility, variable interest, due March 2019 (1)

 

$

662,000

 

$

97,600

 

 

 

 

 

 

 

Senior Notes (2)

 

 

 

 

 

2020 Senior Notes, 6.75% interest, issued November 2010 and due November 2020

 

 

500,000

 

2021 Senior Notes, 6.5% interest, net of discount of $— and $413, respectively, issued February and March 2011 and due August 2021

 

 

324,587

 

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

 

 

455,000

 

2023A Senior Notes, 5.5% interest, net of discount of $5,280 and $5,783, respectively, issued August 2012 and due February 2023

 

744,720

 

744,217

 

2023B Senior Notes, 4.5% interest, issued January 2013 and due July 2023

 

1,000,000

 

1,000,000

 

2024 Senior Notes, 4.875% interest, including premium of $9,934, issued November 2014 and March 2015 and due December 2024

 

1,159,934

 

500,000

 

2025 Senior Notes, 4.875% interest, including discount of $11,302, issued June 2015 and due June 2025

 

1,188,698

 

 

Total long-term debt (3)

 

$

4,755,352

 

$

3,621,404

 

 


(1)         Applicable interest rate was 2.5% for $300.0 million and 4.5% for $362.0 million at September 30, 2015.  The applicable interest rate was 4.5% at December 31, 2014.  The carrying amount of the Credit Facility approximates fair value due to the short-term and variable nature of the borrowings.  The fair value of the Partnership’s Credit Facility is considered a Level 2 measurement.

(2)         The estimated aggregate fair value of the senior notes (collectively, the “Senior Notes”) was approximately $3,820 million and $3,563 million as of September 30, 2015 and December 31, 2014, respectively, based on recent actual prices for OTC secondary market transactions. The fair value of the Partnership’s Senior Notes is considered a Level 2 measurement.

(3)         Accrued interest payable related to the long-term debt was approximately $57.9 million for the nine months ended September 30, 2015, and is included in Accrued liabilities on the accompanying Condensed Consolidated Balance Sheets.

 

Credit Facility

 

On March 20, 2014, the Partnership amended the Credit Facility to increase total borrowing capacity to $1.3 billion, extend the maturity by approximately 18 months to March 20, 2019, amend the pricing terms, expand the existing accordion option from $250 million to $500 million and provide the Partnership with the right to release the collateral securing the Credit Facility.  The right to release collateral will occur once the Partnership’s long-term, senior unsecured debt (“Index Debt”) has received an investment grade rating from Standard & Poor’s equal to or more favorable than BBB- (stable) and from Moody’s equal to or more favorable than Baa3 (stable) and the Partnership’s Total Leverage Ratio (as defined in the Credit Facility) is not greater than 5.00 to 1.00 (“Collateral Release Date”). The Partnership incurred approximately $2.0 million of deferred financing costs associated with modifications of the Credit Facility during the nine months ended September 30, 2014.

 

The borrowings under the Credit Facility bear interest at a variable interest rate, plus a margin. The variable interest rate is based either on the London interbank market rate (“LIBO Rate Loans”) or the higher of (a) the prime rate set by the Credit Facility’s administrative agent, (b) the Federal Funds Rate plus 0.50% and (c) the rate for LIBO Rate Loans for a one month interest period plus 1% (“Alternate Base Rate Loans”). Prior to the Collateral Release Date, the margin is determined by the Partnership’s Total Leverage Ratio, ranging from 0.5% to 1.5% for Alternate Base Rate Loans and from 1.5% to 2.5% for LIBO Rate Loans. After the Collateral Release Date, the margin is determined by the credit rating for the Partnership’s Index Debt issued by Moody’s and Standard & Poor’s, ranging from 0.125% to 1% for Alternate Base Rate Loans and from 1.125% to 2% for LIBO Rate Loans.  The Partnership may utilize up to $150.0 million of the Credit Facility for the issuance of letters of credit and $10.0 million for shorter-term swingline loans.

 

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Under the provisions of the Credit Facility and indentures, the Partnership is subject to a number of restrictions and covenants. The Credit Facility and indentures place limits on the ability of the Partnership and its restricted subsidiaries to incur additional indebtedness; declare or pay dividends or distributions or redeem, repurchase or retire equity interests or subordinated indebtedness; make investments; incur liens; create any consensual limitation on the ability of the Partnership’s restricted subsidiaries to pay dividends or distributions, make loans or transfer property to the Partnership; engage in transactions with the Partnership’s affiliates; sell assets, including equity interests of the Partnership’s subsidiaries; make any payment on or with respect to or purchase, redeem, defease or otherwise acquire or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets. The Credit Facility also limits the Partnership’s ability to enter into transactions with parties that require margin calls under certain derivative instruments. Under the Credit Facility, neither the Partnership nor the bank can require margin calls for outstanding derivative positions.

 

Significant financial covenants under the Credit Facility include the Interest Coverage Ratio (as defined in the Credit Facility), which must be greater than 2.5 to 1.0 and the Total Leverage Ratio (as defined in the Credit Facility).  Prior to the February 2015 amendment, the Total Leverage Ratio was required to be less than 5.5 to 1.0 prior to January 1, 2015, and thereafter until the Collateral Release Date the maximum permissible Total Leverage Ratio was 5.25 to 1.0.  In February 2015, the Partnership entered into an amendment which permanently increased the maximum permissible leverage ratio to 5.5 to 1.0 until the Collateral Release Date. The Total Leverage Ratio at any fiscal quarter-end on or after the Collateral Release Date shall not be greater than 5.00 to 1.00.

 

As of September 30, 2015, the Partnership was in compliance with these financial covenants. These covenants are used to calculate the available borrowing capacity on a quarterly basis. The Credit Facility is guaranteed by and collateralized by substantially all assets of the Partnership’s wholly owned subsidiaries, other than MarkWest Liberty Midstream and its subsidiaries and MarkWest Panola Pipeline, L.L.C. As of September 30, 2015, the Partnership had $662.0 million borrowings outstanding and approximately $8.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $629.7 million of unused capacity all of which was available for borrowing based on financial covenant requirements.  Additionally, the full amount of unused capacity is available for borrowing on a short-term basis to provide financial flexibility within a given fiscal quarter.

 

Senior Notes

 

In March 2015, the Partnership completed a public offering for $650 million in additional aggregate principal amount of 4.875% unsecured notes due December 2024 (“new notes”), which are additional notes under an indenture pursuant to which the Partnership issued $500 million aggregate principal amount of 4.875% Senior Notes due 2024 on November 21, 2014 (“existing notes”). The new notes and the existing notes are treated as a single class of securities under the indenture (“2024 Senior Notes”). The 2024 Senior Notes mature December 1, 2024. Interest on the new notes commenced accruing on November 21, 2014, and the Partnership pays interest on the notes twice a year on June 1 and December 1. The Partnership received aggregate net proceeds of approximately $653.6 million from the new notes offering, after deducting underwriting fees and third-party expenses and excluding approximately $9.0 million for accrued interest.

 

In June 2015, the Partnership completed a public offering for $1.2 billion in additional aggregate principal amount of 4.875% unsecured notes due June 2025 (“2025 Senior Notes”). The 2025 Senior Notes mature June 1, 2025. Interest on the 2025 Senior Notes commenced accruing on June 2, 2015, and the Partnership will pay interest on the notes twice a year, beginning on December 1, 2015. The Partnership received aggregate net proceeds of approximately $1,174.9 million from the 2025 Senior Notes offering, after deducting discounts, underwriting fees and third-party expenses and excluding approximately $23.0 million for accrued interest.  The proceeds from the issuance of the 2025 Senior Notes, along with the Credit Facility, were used to repurchase $500.0 million of the Partnership’s 6.754% Senior Notes due 2020 (the “2020 Senior Notes”), $325.0 million of the Partnership’s 6.5% Senior Notes due 2021 (the “2021 Senior Notes”) and $455.0 million of the Partnership’s 6.25% Senior Notes due 2022 (the “2022 Senior Notes”).

 

The Partnership recorded a total pre-tax loss during the nine months ended September 30, 2015 of approximately $117.9 million related to the repurchases of the 2020 Senior Notes, 2021 Senior Notes and 2022 Senior Notes. The pre-tax loss recorded in the second quarter of 2015 consisted of approximately $14.7 million related to the non-cash write-off of the unamortized discount and deferred finance costs and approximately $103.2 million related to the payment of redemption premiums and third party expenses.  The loss was recorded in Loss on redemption of debt in the accompanying Condensed Consolidated Statement of Operations.

 

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11. Equity

 

Equity Offerings

 

Our public equity offerings are summarized in the table below for the three and nine months ended September 30, 2015 and 2014 (in millions):

 

 

 

Three months ended
September 30, 2015

 

Three months ended
September 30, 2014

 

Nine months ended
September 30, 2015

 

Nine months ended
September 30, 2014

 

 

 

Common
units

 

Net
Proceeds

 

Common
units

 

Net
Proceeds

 

Common
units

 

Net
Proceeds

 

Common
units

 

Net
Proceeds

 

September 2013 ATM (1)

 

 

$

 

 

$

 

 

$

 

4.2

 

$

272

 

March 2014 ATM (2)

 

 

 

4.9

 

342

 

 

 

11.9

 

782

 

November 2014 ATM (3)

 

3.8

 

198

 

 

 

4.4

 

238

 

 

 

Total

 

3.8

 

$

198

 

4.9

 

$

342

 

4.4

 

$

238

 

16.1

 

$

1,054

 

 


(1)         In September 2013, the Partnership entered into an Equity Distribution Agreement with a financial institution (the “2013 Manager”) that established an At the Market offering program (the “September 2013 ATM”) pursuant to which the Partnership could have sold from time to time through the 2013 Manager, as its sales agent, common units having an aggregate offering price of up to $1 billion. During the nine months ended September 30, 2014, the Partnership incurred approximately $4 million in manager fees and other third-party expenses.  The proceeds from sales were used to fund capital expenditures and for general Partnership purposes. The Partnership completed the September 2013 ATM on March 31, 2014.

 

(2)         In March 2014, the Partnership entered into an Equity Distribution Agreement with financial institutions (the “2014 Managers”) that established an At the Market offering program (the “March 2014 ATM”) pursuant to which the Partnership may sell from time to time through the 2014 Managers, as its sales agents, common units having an aggregate offering price of up to $1.2 billion.  During the three and nine months ended September 30, 2014, the Partnership incurred approximately $2 million and approximately $5 million, respectively, in manager fees and other third-party expenses.  The proceeds from sales were used to fund capital expenditures and for general Partnership purposes.  The Partnership completed the March 2014 ATM in October 2014.

 

(3)         In November 2014, the Partnership entered into an Equity Distribution Agreement with financial institutions (the “November 2014 Managers”) that established an At the Market offering program (the “November 2014 ATM”) pursuant to which the Partnership may sell from time to time through the November 2014 Managers, as its sales agents, common units having an aggregate offering price of up to $1.5 billion.  As of September 30, 2015, the Partnership has issued 6.9 million units receiving net proceeds of approximately $413 million under the November 2014 ATM.

 

All of the Partnership’s Class B units were issued to and are held by M&R MWE Liberty, LLC, an affiliate of EMG, as part of the Partnership’s December 31, 2011 acquisition of the non-controlling interest in MarkWest Liberty Midstream. Approximately four million Class B units converted to common units on July 1, 2015. The remaining Class B units will convert to common units on a one-for-one basis in two equal installments on July 1, 2016 and 2017. After the units are converted to common units, M&R MWE Liberty, LLC may sell common units as part of the November 2014 ATM program.  See the voting agreement section of Note 3 for further information regarding the voting of M&R MWE Liberty, LLC’s common units with respect to the Merger Agreement. Class B units converted to common units prior to the applicable record date will participate in the distributions relating to such date.

 

Distributions of Available Cash and Range of Unit Prices

 

 

 

Common Unit Price

 

Distribution
Per
Common

 

 

 

 

 

 

 

Quarter Ended

 

High

 

Low

 

Unit

 

Declaration Date

 

Record Date

 

Payment Date

 

September 30, 2015

 

$

70.81

 

$

41.62

 

$

0.93

 

October 22, 2015

 

November 4, 2015

 

November 13, 2015

 

June 30, 2015

 

$

69.50

 

$

56.20

 

$

0.92

 

July 20, 2015

 

August 6, 2015

 

August 14, 2015

 

March 31, 2015

 

$

69.16

 

$

54.04

 

$

0.91

 

April 22, 2015

 

May 7, 2015

 

May 15, 2015

 

December 31, 2014

 

$

77.31

 

$

58.67

 

$

0.90

 

January 21, 2015

 

February 5, 2015

 

February 13, 2015

 

 

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12. 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 that it believes are 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 injury and property damage, or that the coverage 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 associated with all legal actions have been made in the accompanying Condensed Consolidated Financial Statements and that 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.

 

On July 6, 2015, officials from the United States Environmental Protection Agency and the Department of Justice entered a MarkWest Liberty Midstream pipeline launcher/receiver site in Washington County, Pennsylvania pursuant to a search warrant issued by the United States District Court for the Western District of Pennsylvania.  At the conclusion of the search, the governmental officials presented MarkWest Liberty Midstream with a subpoena to provide documents related to the design, construction, operation, maintenance, modification, inspection, assessment, repair of, and/or emissions from MarkWest Liberty Midstream’s pipeline facilities located in Pennsylvania.  MarkWest Liberty Midstream is providing information in response to the subpoena and related requests for information from the relevant agencies, and is in discussions with the relevant agencies regarding issues associated with the search and subpoena and its operations of, or supplementary permitting obligations for, its pipeline facilities in the Northeast.  Immediately following the July 6 search, MarkWest Liberty Midstream commenced its own assessment of its operations of launcher/receiver facilities.  MarkWest Liberty Midstream’s review to date has determined that other than potentially having to obtain minor source permits at a small number of individual sites, MarkWest Liberty Midstream’s operations have been conducted in a manner fully protective of its employees and the public, and in compliance with applicable laws and regulations.  It is possible that, in connection with any enforcement action associated with this matter, MarkWest Liberty Midstream will incur material assessments, penalties or fines, incur material defense costs and expenses, be required to modify our operations or construction activities which could increase operating costs and capital expenditures, or be subject to other obligations or restrictions that could restrict or prohibit our activities, any or all of which could adversely affect our results of operations and cash available for distribution.  The amount of any potential assessments, penalties, fines, costs or expenses that may be incurred in connection with the inspection and subpoena cannot be reasonably estimated at this time.

 

As more fully described in Note 3 of the Notes to the Condensed Consolidated Financial Statements, on July 11, 2015, the Partnership entered into the Merger Agreement with MPLX, MPLX GP, Merger Sub, and, for certain limited purposes set forth in the Merger Agreement, MPC.  Pursuant to the Merger Agreement, Merger Sub will be merged with and into the Partnership, with the Partnership surviving the Merger as a wholly owned subsidiary of MPLX.  After the Merger, the Partnership’s common units will cease to be publicly traded.

 

On July 24, 2015, a putative unitholder class action complaint was filed by a single plaintiff who purports to be a unitholder of the Partnership in the Court of Chancery for the State of Delaware (Case No. 11332-VCG) against the individual members of the General Partner’s board of directors (the “Board”), the General Partner, MPLX, MPC and Merger Sub. The complaint, styled Katsman v. Frank M. Semple, et al., (the “Katsman lawsuit”) alleges that the Board breached its duties in approving the Merger with MPLX. Generally, the Katsman lawsuit alleges that the Board breached its duties to the Partnership’s common unitholders because the Merger does not provide the Partnership’s common unitholders with adequate consideration, the Board did not seek to maximize value for the benefit of the Partnership’s common unitholders, certain members of the Partnership’s management team will remain executive officers of MPLX after the consummation of the Merger and the Merger Agreement contains preclusive deal protective devices and does not provide for appraisal rights.  The Katsman lawsuit also alleges that MPC, MPLX and Merger Sub aided and abetted in such breaches. The Katsman lawsuit seeks, among other relief, to enjoin the Merger, or in the event the Merger is consummated, rescission of the Merger or monetary damages. The Katsman lawsuit also seeks an accounting and recovery of attorneys’ fees, experts’ fees, and other litigation costs.

 

On August 10, 2015, another purported unitholder of the Partnership filed a putative class action complaint, captioned Schein v. Semple, et al., (the “Schein lawsuit”) in the Court of Chancery of the State of Delaware, advancing substantially similar allegations and claims, and seeking substantially the same relief against the same defendants named in the Katsman lawsuit.

 

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On August 14, 2015, another purported unitholder of the Partnership filed a putative class action complaint, captioned Kleinfeldt v. Semple, et al., (the “Kleinfeldt lawsuit”) in the Court of Chancery of the State of Delaware.  The Kleinfeldt lawsuit asserts substantially the same allegations and claims against the same defendants named in the Katsman and Schein lawsuits.

 

On September 9, 2015, the Katsman, Schein and Kleinfeldt lawsuits were consolidated into one action pending in the Court of Chancery of the State of Delaware, now captioned In re MarkWest Energy Partners, L.P. Unitholder Litigation.  The Chancery Court’s consolidation order contemplates that any future Delaware class action suits will be consolidated into this action.  On October 1, 2015, the Delaware plaintiffs filed a consolidated complaint against the individual members of the Board, MPLX, the general partner of MPLX, MPC and Merger Sub asserting that in connection with the Merger and related disclosures, among other things, (i) the Board breached its duties in approving the Merger with MPLX and (ii) MPC, MPLX, the general partner of MPLX, and Merger Sub aided and abetted these breaches.  The complaint seeks, among other relief, to enjoin the Merger, or in the event the Merger is consummated, rescission of the Merger or monetary damages.

 

The Partnership intends to vigorously defend this consolidated lawsuit. However, one of the conditions to the completion of the Merger is that no law, order, decree, judgment or injunction of any court, agency or other governmental authority shall be in effect that enjoins, prohibits or makes illegal consummation of any of the transactions contemplated by the Merger Agreement.  A preliminary injunction could delay or jeopardize the completion of the Merger, and an adverse judgment granting permanent injunctive relief could indefinitely enjoin completion of the Merger.  An adverse judgment for rescission or for monetary damages could have a material adverse effect on the Partnership and MPLX following the Merger.

 

Contract Contingencies

 

Certain natural gas processing and gathering arrangements require the Partnership to construct new natural gas processing plants, natural gas gathering pipelines and NGL pipelines and contain certain fees and charges if specified construction milestones are not achieved for reasons other than force majeure. In certain cases, certain producers may have the right to cancel the processing arrangements if there are significant delays that are not due to force majeure. As of September 30, 2015, management does not believe there are any indications that the Partnership will not be able to meet the construction milestones, that force majeure does not apply, or that such fees and charges will otherwise be triggered.

 

13. Income Taxes

 

A reconciliation of the provision for income tax and the amount computed by applying the federal statutory rate to income before provision for income tax for the nine months ended September 30, 2015 and 2014 is as follows (in thousands):

 

 

 

Nine months ended September 30, 2015

 

 

 

Corporation

 

Partnership

 

Eliminations

 

Consolidated

 

Loss before provision for income tax

 

$

(28,878

)

$

(16,064

)

$

(71

)

$

(45,013

)

Federal statutory rate

 

35

%

0

%

0

%

 

 

Federal income tax at statutory rate

 

(10,107

)

 

 

(10,107

)

Permanent items

 

23

 

 

 

23

 

Change in state statutory rate

 

 

(1,517

)

 

(1,517

)

State income taxes net of federal benefit

 

(864

)

(549

)

 

(1,413

)

Provision on income from Class A units (1)

 

(334

)

 

 

(334

)

Provision for income tax

 

$

(11,282

)

$

(2,066

)

$

 

$

(13,348

)

 

 

 

Nine months ended September 30, 2014

 

 

 

Corporation

 

Partnership

 

Eliminations

 

Consolidated

 

Income before provision for income tax

 

$

25,973

 

$

110,156

 

$

(481

)

$

135,648

 

Federal statutory rate

 

35

%

0

%

0

%

 

 

Federal income tax at statutory rate

 

9,091

 

 

 

9,091

 

Permanent items

 

32

 

 

 

32

 

State income taxes net of federal benefit

 

652

 

1,037

 

 

1,689

 

Federal and state tax rate change

 

4,250

 

 

 

4,250

 

Provision on income from Class A units (1)

 

5,574

 

 

 

5,574

 

Provision for income tax

 

$

19,599

 

$

1,037

 

$

 

$

20,636

 

 


(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

 

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Corporation’s common stock. The provision for income tax on income from Class A units includes intra period allocations to continued operations and excludes allocations to equity.

 

14. Earnings Per Common Unit

 

The following table shows the computation of basic and diluted net income (loss) per common unit, and the weighted-average units used to compute basic and diluted net income (loss) per common unit for the three and nine months ended September 30, 2015 and 2014 (in thousands, except per unit data):

 

 

 

Three months ended September 30,

 

Nine months ended September 30,

 

 

 

2015

 

2014

 

2015

 

2014

 

Net income (loss) attributable to the Partnership’s unitholders

 

$

29,127

 

$

77,434

 

$

(81,442

)

$

98,903

 

Less: Income allocable to phantom units

 

657

 

560

 

1,943

 

1,656

 

Income (loss) available for common unitholders - basic

 

28,470

 

76,874

 

(83,385

)

97,247

 

Add: Income allocable to phantom units and DER expense (1)

 

687

 

583

 

 

1,724

 

Income (loss) available for common unitholders - diluted

 

$

29,157

 

$

77,457

 

$

(83,385

)

$

98,971

 

 

 

 

 

 

 

 

 

 

 

Weighted average common units outstanding - basic

 

191,908

 

176,757

 

188,502

 

166,792

 

Potential common shares (Class B and phantom units) (1)

 

8,771

 

12,683

 

 

15,313

 

Weighted average common units outstanding - diluted

 

200,679

 

189,440

 

188,502

 

182,105

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to the Partnership’s common unitholders per common unit (2) 

 

 

 

 

 

 

 

 

 

Basic

 

$

0.15

 

$

0.43

 

$

(0.44

)

$

0.58

 

Diluted

 

$

0.15

 

$

0.41

 

$

(0.44

)

$

0.54

 

 


(1)         For the nine months ended September 30, 2015, approximately 11,393 potential common shares were excluded from the calculation because the impact was anti-dilutive.

 

(2)    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.

 

15. Segment Information

 

The Partnership prepares segment information in accordance with GAAP. However, 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. As disclosed in Note 4, Ohio Gathering was deconsolidated effective June 1, 2014 and its financial position as of September 30, 2015 and results of operations are reported under the equity method of accounting. However, the Partnership’s Chief Executive Officer and chief operating decision maker continues to view the Utica Segment inclusive of Ohio Gathering, and reviews its financial information as if it were consolidated.  In addition, the Partnership’s Chief Executive Officer and chief operating decision maker views all Partnership operated, non-wholly owned subsidiaries as if they are consolidated, as these subsidiaries are operated by the Partnership.

 

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The tables below present the Partnership’s segment profit measure, Operating income before items not allocated to segments for the three months ended September 30, 2015 and 2014 for the reported segments (in thousands):

 

Three months ended September 30, 2015:

 

 

 

Marcellus

 

Utica

 

Northeast

 

Southwest

 

Elimination (1)

 

Total