UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended June 30, 2007

 

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: 1-14323

 

ENTERPRISE PRODUCTS PARTNERS L.P.

(Exact name of Registrant as Specified in Its Charter)

 

Delaware

76-0568219

(State or Other Jurisdiction of

(I.R.S. Employer Identification No.)

Incorporation or Organization)

 

 

 

 

 

1100 Louisiana, 10th Floor

 

 

Houston, Texas 77002

 

 

(Address of Principal Executive Offices, Including Zip Code)

 

 

 

 

 

(713) 381-6500

 

 

(Registrant’s Telephone Number, Including Area Code)

 

 

 

 

 

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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer x          Accelerated filer o          Non-accelerated filer o

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o    No x

 

There were 434,062,817 common units of Enterprise Products Partners L.P. outstanding at August 1, 2007. These common units trade on the New York Stock Exchange under the ticker symbol “EPD.”



 


ENTERPRISE PRODUCTS PARTNERS L.P.

TABLE OF CONTENTS

 

 

 

Page No.

PART I. FINANCIAL INFORMATION.

Item 1.

Financial Statements.

 

 

Unaudited Condensed Consolidated Balance Sheets

2

 

Unaudited Condensed Statements of Consolidated Operations

3

 

Unaudited Condensed Statements of Consolidated Comprehensive Income

4

 

Unaudited Condensed Statements of Consolidated Cash Flows

5

 

Unaudited Condensed Statements of Consolidated Partners’ Equity

6

 

Notes to Unaudited Condensed Consolidated Financial Statements:

 

 

1. Partnership Organization

7

 

2. General Accounting Policies and Related Matters

8

 

3. Accounting for Unit-Based Awards

11

 

4. Financial Instruments

13

 

5. Inventories

15

 

6. Property, Plant and Equipment

16

 

7. Investments in and Advances to Unconsolidated Affiliates

16

 

8. Intangible Assets and Goodwill

19

 

9. Debt Obligations

20

 

10. Partners’ Equity and Distributions

24

 

11. Business Segments

26

 

12. Related Party Transactions

29

 

13. Earnings Per Unit

34

 

14. Commitments and Contingencies

35

 

15. Significant Risks and Uncertainties – Weather-Related Risks

37

 

16. Supplemental Cash Flow Information

38

 

17. Condensed Financial Information of EPO

39

Item 2.

Management’s Discussion and Analysis of Financial Condition

41

 

and Results of Operations.

 

Item 3.

Quantitative and Qualitative Disclosures about Market Risk.

66

Item 4.

Controls and Procedures.

69

 

 

 

PART II. OTHER INFORMATION.

Item 1.

Legal Proceedings.

69

Item 1A.

Risk Factors.

69

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds.

70

Item 3.

Defaults upon Senior Securities.

70

Item 4.

Submission of Matters to a Vote of Security Holders.

70

Item 5.

Other Information.

70

Item 6.

Exhibits.

70

 

 

 

Signatures

77

 

 

 

 

 

 

1

 


PART I. FINANCIAL INFORMATION.

 

Item 1. Financial Statements.

 

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

 

 

 

 

 

 

June 30,

December 31,

ASSETS

2007

2006

Current assets:

 

 

 

Cash and cash equivalents

$           63,363

$           22,619

 

Restricted cash

23,359

23,667

 

Accounts and notes receivable - trade, net of allowance for doubtful accounts

 

 

 

 

of $22,868 at June 30, 2007 and $23,406 at December 31, 2006

1,491,856

1,306,290

 

Accounts receivable - related parties

91,619

16,738

 

Inventories

 

335,622

423,844

 

Prepaid and other current assets

173,327

129,000

 

 

 

Total current assets

2,179,146

1,922,158

Property, plant and equipment, net

10,734,130

9,832,547

Investments in and advances to unconsolidated affiliates

836,091

564,559

Intangible assets, net of accumulated amortization of $297,002 at

 

 

 

June 30, 2007 and $251,876 at December 31, 2006

950,260

1,003,955

Goodwill

 

590,647

590,541

Deferred tax asset

2,369

1,855

Other assets

 

77,630

74,103

 

 

 

Total assets

 

$    15,370,273

$    13,989,718

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ EQUITY

 

 

Current liabilities:

 

 

 

Accounts payable – trade

$         285,671

$         277,070

 

Accounts payable – related parties

32,846

6,785

 

Accrued gas payables

1,552,074

1,364,493

 

Accrued expenses

44,539

35,763

 

Accrued interest

94,837

90,865

 

Other current liabilities

194,894

209,945

 

 

 

Total current liabilities

2,204,861

1,984,921

Long-term debt: (see Note 9)

 

 

Senior debt obligations – principal

5,063,949

4,779,068

Junior Subordinated Notes A – principal

550,000

550,000

Junior Subordinated Notes B – principal

700,000

--

Other

(54,234)

(33,478)

Total long-term debt

6,259,715

5,295,590

Deferred tax liabilities

17,310

13,723

Other long-term liabilities

108,716

86,121

Minority interest

434,665

129,130

Commitments and contingencies

 

 

Partners’ equity:

 

 

 

Limited partners

 

 

 

 

Common units (432,466,493 units outstanding at June 30, 2007

 

 

 

 

 

and 431,303,193 units outstanding at December 31, 2006 )

6,145,945

6,320,577

 

 

Restricted common units (1,596,324 units outstanding at June 30, 2007

 

 

 

 

 

and 1,105,237 units outstanding at December 31, 2006)

11,389

9,340

 

General partner

126,037

129,175

 

Accumulated other comprehensive income

61,635

21,141

 

 

 

Total partners’ equity

6,345,006

6,480,233

 

 

 

Total liabilities and partners’ equity

 

$    15,370,273

$    13,989,718

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

 

2

 


ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

(Dollars in thousands, except per unit amounts)

 

 

For the Three Months

For the Six Months

 

Ended June 30,

Ended June 30,

 

2007

2006

2007

2006

Revenues:

 

 

 

 

Third parties

$ 4,076,573

$ 3,404,419

$ 7,335,185

$ 6,564,418

Related parties

136,233

113,434

200,475

203,509

Total

4,212,806

3,517,853

7,535,660

6,767,927

Costs and expenses:

 

 

 

 

Operating costs and expenses:

 

 

 

 

Third parties

3,875,050

3,244,576

6,915,583

6,189,796

Related parties

85,622

79,009

169,568

180,652

Total operating costs and expenses

3,960,672

3,323,585

7,085,151

6,370,448

General and administrative costs:

 

 

 

 

Third parties

10,628

5,405

14,203

8,137

Related parties

20,733

10,830

33,788

21,838

Total general and administrative costs

31,361

16,235

47,991

29,975

Total costs and expenses

3,992,033

3,339,820

7,133,142

6,400,423

Equity in income (loss) of unconsolidated affiliates

(6,211)

8,012

(32)

12,041

Operating income

214,562

186,045

402,486

379,545

Other income (expense):

 

 

 

 

Interest expense

(71,275)

(56,333)

(134,633)

(114,410)

Interest income

2,408

1,455

4,443

3,116

Other, net

339

1,938

232

2,246

Other expense

(68,528)

(52,940)

(129,958)

(109,048)

Income before provision for income taxes, minority interest and

 

 

 

 

the cumulative effect of change in accounting principle

146,034

133,105

272,528

270,497

Provision for income taxes

1,860

(6,272)

(6,928)

(9,164)

Income before minority interest and the cumulative effect

 

 

 

 

of change in accounting principle

147,894

126,833

265,600

261,333

Minority interest

(5,740)

(538)

(11,401)

(2,736)

Income before the cumulative effect of change in

 

 

 

 

accounting principle

142,154

126,295

254,199

258,597

Cumulative effect of change in accounting principle (see Note 2)

--

--

--

1,475

Net income

$    142,154

$    126,295

$    254,199

$    260,072

 

 

 

 

 

Net income allocation: (see Note 13)

 

 

 

 

Limited partners’ interest in net income

$    113,527

$    103,192

$    198,576

$    215,561

General partner interest in net income

$      28,627

$      23,103

$      55,623

$      44,511

 

 

 

 

 

Earning per unit: (see Note 13)

 

 

 

 

Basic income per unit before change in accounting principle

$          0.26

$          0.25

$          0.46

$          0.53

Basic income per unit

$          0.26

$          0.25

$          0.46

$          0.54

Diluted income per unit before change in accounting principle

$          0.26

$          0.25

$          0.46

$          0.53

Diluted income per unit

$          0.26

$          0.25

$          0.46

$          0.54

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

 

3

 


ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED

COMPREHENSIVE INCOME

(Dollars in thousands)

 

 

 

For the Three Months

For the Six Months

 

Ended June 30,

Ended June 30,

 

2007

2006

2007

2006

 

 

 

 

 

Net income

$   142,154

$   126,295

$   254,199

$   260,072

Other comprehensive income:

 

 

 

 

Cash flow hedges:

 

 

 

 

Net commodity financial instrument gains (losses) during period

(3,121)

(7,951)

846

(7,700)

Net interest rate financial instrument gains during period

29,752

1,638

40,264

1,638

Less: Amortization of cash flow financing hedges

(1,180)

(1,052)

(2,269)

(2,093)

Total cash flow hedges

25,451

(7,365)

38,841

(8,155)

Foreign currency translation adjustment

148

--

549

--

Total other comprehensive income

25,599

(7,365)

39,390

(8,155)

Comprehensive income

$   167,753

$   118,930

$   293,589

$   251,917

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

 

4

 


ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in thousands)

 

 

 

For the Six Months

 

 

Ended June 30,

 

 

2007

2006

Operating activities:

 

 

Net income

$    254,199

$    260,072

Adjustments to reconcile net income to net cash

 

 

flows provided by operating activities:

 

 

 

Depreciation, amortization and accretion in operating costs and expenses

240,653

212,768

 

Depreciation and amortization in general and administrative costs

4,259

3,752

 

Amortization in interest expense

201

487

 

Equity in loss (income) of unconsolidated affiliates

32

(12,041)

 

Distributions received from unconsolidated affiliates

35,026

20,348

 

Cumulative effect of change in accounting principle

--

(1,475)

 

Operating lease expense paid by EPCO, Inc.

1,053

1,056

 

Minority interest

11,401

2,736

 

Loss (gain) on sale of assets

5,664

(197)

 

Deferred income tax expense

4,088

9,180

 

Changes in fair market value of financial instruments

(302)

(53)

 

Net effect of changes in operating accounts (see Note 16)

(4,225)

74,692

Net cash flows provided by operating activities

552,049

571,325

Investing activities:

 

 

Capital expenditures

(1,129,263)

(613,519)

Contributions in aid of construction costs

48,570

34,941

Proceeds from sale of assets

1,015

256

Decrease (increase) in restricted cash

308

(6,703)

Cash used for business combinations

(785)

--

Investments in unconsolidated affiliates

(294,598)

(111,882)

Advances (to) from unconsolidated affiliates

(12,434)

7,120

Net cash used in investing activities

(1,387,187)

(689,787)

Financing activities:

 

 

Borrowings under debt agreements

3,048,734

1,435,000

Repayments of debt

(2,063,374)

(1,402,000)

Debt issuance costs

(9,261)

--

Distributions paid to partners

(470,561)

(400,474)

Distributions paid to minority interests

(9,416)

(4,131)

Net proceeds from initial public offering of Duncan Energy Partners reflected

 

 

as a contribution from minority interests (see Notes 1 and 2)

291,044

--

Other contributions from minority interests

12,506

19,018

Settlement of treasury lock contracts

42,269

--

Repurchase of restricted units and options

(1,568)

--

Net proceeds from issuance of our common units

35,899

453,475

Net cash provided by financing activities

876,272

100,888

Effect of exchange rate changes on cash

(390)

--

Net change in cash and cash equivalents

41,134

(17,574)

Cash and cash equivalents, January 1

22,619

42,098

Cash and cash equivalents, June 30

$      63,363

$      24,524

 

 

 

 

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

 

5

 


ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED PARTNERS’ EQUITY

(See Note 10 for Unit History and Detail of Changes in Limited Partners’ Equity)

(Dollars in thousands)

 

 

 

 

Limited

General

 

 

 

 

Partners

Partner

AOCI

Total

Balance, December 31, 2006

$   6,329,917

$   129,175

$   21,141

$   6,480,233

 

Net income

198,576

55,623

--

254,199

 

Operating leases paid by EPCO, Inc.

1,032

21

--

1,053

 

Cash distributions to partners

(407,826)

(59,896)

--

(467,722)

 

Net proceeds from sales of common units

27,676

877

--

28,553

 

Proceeds from exercise of unit options

7,139

207

--

7,346

 

Repurchase of restricted units and options

(1,568)

--

--

(1,568)

 

Unit option reimbursements to EPCO, Inc.

(2,786)

(57)

--

(2,843)

 

Change in funded status of pension and

 

 

 

 

 

postretirement plans, net of tax

--

--

1,104

1,104

 

Amortization of equity awards

5,174

87

--

5,261

 

Foreign currency translation adjustment

--

--

549

549

 

Cash flow hedges

--

--

38,841

38,841

Balance, June 30, 2007

$   6,157,334

$   126,037

$   61,635

$   6,345,006

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

 

6

 


ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 


Note 1. Partnership Organization

 

Partnership Organization

 

Enterprise Products Partners L.P. is a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” Unless the context requires otherwise, references to “we,” “us,” “our,” or “Enterprise Products Partners” are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.

 

We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO, Inc. (“EPCO”). We conduct substantially all of our business through our wholly owned subsidiary, Enterprise Products Operating LLC (“EPO”), as successor in interest by merger to Enterprise Products Operating L.P. We are owned 98% by our limited partners and 2% by Enterprise Products GP, LLC (our general partner, referred to as “Enterprise Products GP”). Enterprise Products GP is owned 100% by Enterprise GP Holdings L.P. (“Enterprise GP Holdings”), a publicly traded affiliate, the units of which are listed on the NYSE under the ticker symbol “EPE.” The general partner of Enterprise GP Holdings is EPE Holdings, LLC (“EPE Holdings”), a wholly owned subsidiary of Dan Duncan LLC, the membership interests of which are owned by Dan L. Duncan. We, Enterprise Products GP, Enterprise GP Holdings, EPE Holdings and Dan Duncan LLC are affiliates and under common control of Dan L. Duncan, the Chairman and controlling shareholder of EPCO.

 

References to “TEPPCO” mean TEPPCO Partners, L.P., a publicly traded affiliate, the units of which are listed on the NYSE under the ticker symbol “TPP.” References to “TEPPCO GP” refer to Texas Eastern Products Pipeline Company, LLC, which is the general partner of TEPPCO and is wholly owned by Enterprise GP Holdings.

 

References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries. References to “ETE GP” mean LE GP, LLC, which is the general partner of Energy Transfer Equity. On May 7, 2007, Enterprise GP Holdings acquired non-controlling interests in both ETE GP and Energy Transfer Equity.

 

References to “Employee Partnerships” mean EPE Unit L.P. (“EPE Unit I”), EPE Unit II, L.P. (“EPE Unit II”) and EPE Unit III, L.P. (“EPE Unit III”), collectively, which are private company affiliates of EPCO.

 

On February 5, 2007, a consolidated subsidiary of ours, Duncan Energy Partners L.P. (“Duncan Energy Partners”), completed an initial public offering of its common units (see Note 12). Duncan Energy Partners owns equity interests in certain of our midstream energy businesses.

 

For financial reporting purposes, we consolidate the financial statements of Duncan Energy Partners with those of our own and reflect its operations in our business segments. We control Duncan Energy Partners through our ownership of its general partner. Also, due to common control of the entities by Dan L. Duncan, the initial consolidated balance sheet of Duncan Energy Partners reflects our historical carrying basis in each of the subsidiaries contributed to Duncan Energy Partners. Public ownership of Duncan Energy Partners’ net assets and earnings are presented as a component of minority interest in our consolidated financial statements. The borrowings of Duncan Energy Partners are presented as part of our consolidated debt; however, we do not have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.

 

 

 

7

 


Basis of Presentation

 

Our results of operations for the three and six months ended June 30, 2007 are not necessarily indicative of results expected for the full year.

 

Except per unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

 

Essentially all of our assets, liabilities, revenues and expenses are recorded at EPO’s level in our consolidated financial statements. We act as guarantor of certain of EPO’s debt obligations. See Note 17 for condensed consolidated financial information of EPO.

 

In our opinion, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments consisting of normal recurring accruals necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These Unaudited Condensed Consolidated Financial Statements should be read in conjunction with our annual report on Form 10-K for the year ended December 31, 2006 (Commission File No. 1-14323).

 


Note 2. General Accounting Policies and Related Matters

 

Accounting for Employee Benefit Plans

 

Dixie Pipeline Company (“Dixie”), a consolidated subsidiary, employs the personnel that operate its pipeline system and certain of these employees are eligible to participate in a defined contribution plan and pension and postretirement benefit plans. Due to the immaterial nature of Dixie’s employee benefit plans to our consolidated financial position, results of operations and cash flows, our discussion is limited to the following:

 

Defined Contribution Plan. Dixie contributed $0.1 million to its company-sponsored defined contribution plan during each of the three month periods ended June 30, 2007 and 2006. During each of the six month periods ended June 30, 2007 and 2006, Dixie contributed $0.2 million to its company-sponsored defined contribution plan.

 

Pension and Postretirement Benefit Plans. Dixie’s net pension benefit costs were $0.1 million and $0.2 million for the three months ended June 30, 2007 and 2006, respectively. For each of the six month periods ended June 30, 2007 and 2006, Dixie’s net pension benefit costs were $0.3 million. Dixie’s net postretirement benefit costs were $0.1 million for each of the three month periods ended June 30, 2007 and 2006. For the six months ended June 30, 2007 and 2006, Dixie’s net postretirement benefit costs were $0.2 million and $0.1 million, respectively. During the remainder of 2007, Dixie expects to contribute approximately $1.2 million to its postretirement benefit plan and approximately $0.2 million to its pension plan.

 

Consolidation Policy

 

We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of intercompany accounts and transactions. We also consolidate other entities and ventures in which we possess a controlling financial interest as well as partnership interests where we are the sole general partner of the partnership.

 

8

 


 

If the investee is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50% and we exercise significant influence over the investee’s operating and financial policies. For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee’s operating and financial policies. Our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates are eliminated in consolidation to the extent such amounts remain on our balance sheet (or those of our equity method investees) in inventory or similar accounts.

 

If our ownership interest in an investee does not provide us with either control or significant influence over the investee, we account for the investment using the cost method.

 

Cumulative Effect of Change in Accounting Principle

 

In January 2006, we adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) 123(R), “Share-Based Payment.” Upon adoption of this accounting standard, we recognized, as a benefit, a cumulative effect of change in accounting principle of $1.5 million.

 

Environmental Costs

 

Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies, and regulatory approvals. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. Expenditures to mitigate or prevent future environmental contamination are capitalized.

 

At June 30, 2007 and December 31, 2006, our accrued liabilities for environmental remediation projects totaled $28.6 million and $24.2 million, respectively. These amounts were derived from a range of reasonable estimates based upon studies and site surveys. Unanticipated changes in circumstances and/or legal requirements could result in expenses being incurred in future periods in addition to an increase in actual cash required to remediate contamination for which we are responsible.

 

In February 2007, we reserved $6.5 million in cash received from a third party to fund anticipated future environmental remediation costs associated with certain assets that we had acquired from the third party. Previously, the third party had been obligated to indemnify us for such costs. As a result of the settlement, this indemnification was terminated.

 

Estimates

 

Preparing our Unaudited Condensed Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Our actual results could differ from these estimates. On an ongoing basis, management reviews its estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.

 

Income Taxes

 

We are organized as a pass-through entity for income tax purposes. As a result, our partners are responsible for federal income taxes on their share of our taxable income. For the three and six months ended June 30, 2007 and 2006, our provision for income taxes is applicable to state tax obligations under

 

9

 


the Texas Margin Tax and certain federal and state tax obligations of Seminole Pipeline Company (“Seminole”) and Dixie.

 

In accordance with Financial Accounting Standards Board Interpretation (“FIN”) 48, “Accounting for Uncertainty in Income Taxes,” we must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable. If a tax position meets such criteria, the tax effect to be recognized by us would be the largest amount of benefit with more than a 50% chance of being realized upon settlement. This guidance was effective January 1, 2007, and our adoption of this guidance had no material impact on our financial position, results of operations or cash flows.

 

Minority Interest

 

As presented in our Unaudited Condensed Consolidated Balance Sheets, minority interest represents third-party ownership interests in the net assets of our consolidated subsidiaries. For financial reporting purposes, the assets and liabilities of our majority owned subsidiaries are consolidated with those of our own, with any third-party ownership interests in such amounts presented as minority interest. Effective February 1, 2007, the public owners of Duncan Energy Partners’ common units are presented as a minority interest in our consolidated financial statements.

 

Minority interest, as reflected on our June 30, 2007 balance sheet, consists of $293.5 million attributable to third party owners of Duncan Energy Partners and the remainder to our other consolidated affiliates.

 

Minority interest expense for the three and six months ended June 30, 2007 includes $3.3 million and $6.1 million, respectively, attributable to third party owners of Duncan Energy Partners. The remaining minority interest expense amounts for these periods in 2007 and likewise those for 2006 are attributable to our other consolidated affiliates.

 

Contributions from minority interests for the six months ended June 30, 2007 includes $291.0 million received from third parties in connection with the initial public offering of Duncan Energy Partners in February 2007.

 

Recent Accounting Developments

 

SFAS 157, “Fair Value Measurements,” defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007 and we will be required to adopt SFAS 157 on January 1, 2008. We do not believe SFAS 157 will have a material impact on our financial position, results of operations, and cash flows since we already apply its basic concepts in measuring fair values used to record various transactions such as business combinations and asset acquisitions.

 

SFAS 159, “Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115,” permits entities to choose to measure many financial assets and financial liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected would be reported in net income. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparisons between the different measurement attributes the company elects for similar types of assets and liabilities. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We do not believe SFAS 159 will have a material impact on our financial position, results of operations, and cash flows.

 

 

10

 


Note 3. Accounting for Unit-Based Awards

 

We account for unit-based awards in accordance with SFAS 123(R). SFAS 123(R) requires us to recognize compensation expense related to equity awards based on the fair value of the award at grant date. The fair value of restricted unit awards is based on the market price of the underlying common units on the date of grant. The fair value of other unit-based awards is estimated using the Black-Scholes option pricing model. Under SFAS 123(R), the fair value of an equity-classified award is amortized to earnings on a straight-line basis over the requisite service or vesting period. Compensation expense for liability-classified awards is recognized over the requisite service or vesting period of an award based on the fair value of the award remeasured at each reporting period.

 

Unit Options and Restricted Units

 

Under EPCO’s 1998 Long-Term Incentive Plan (the “1998 Plan”), non-qualified incentive options to purchase a fixed number of our common units may be granted to EPCO’s key employees who perform management, administrative or operational functions for us.

 

The information in the following table presents unit option activity under the 1998 Plan for the periods indicated:

 

 

 

 

 

Weighted-

 

 

 

 

Weighted-

average

 

 

 

 

average

remaining

Aggregate

 

 

Number of

strike price

contractual

Intrinsic

 

 

Units

(dollars/unit)

term (in years)

Value (1)

Outstanding at December 31, 2006

2,416,000

$    23.32

 

 

Granted (2)

795,000

30.96

 

 

Exercised

(230,500)

18.89

 

 

Settled

(710,000)

24.35

 

 

Outstanding at June 30, 2007

2,270,500

26.12

8.14

$    3,502

Options exercisable at:

 

 

 

 

 

June 30, 2007

360,500

$    22.10

4.52

$    3,502

 

 

 

 

 

 

(1)   Aggregate intrinsic value reflects fully vested unit options at June 30, 2007.

(2)   The total grant date value of these awards was $2.1 million based on the following assumptions (i) expected life of the option of seven years; (ii) risk-free interest rate of 4.83%; (iii) expected distribution yield on units of 8.42%; and (iv) expected unit price volatility on units of 23.21%.

 

The total intrinsic value of unit options exercised during the three and six months ended June 30, 2007 was $1.2 million and $2.8 million, respectively. We recognized $3.9 million and $0.2 million of compensation expense associated with unit options during the three month periods ended June 30, 2007 and 2006, respectively. We recognized $4.1 million and $0.3 million of compensation expense associated with unit options during the six months ended June 30, 2007 and 2006, respectively. Compensation expense for the three and six months ended June 30 ,2007 includes $3.7 million associated with the resignation of our former chief executive officer.

 

As of June 30, 2007, there was an estimated $3.2 million of total unrecognized compensation cost related to non-vested unit options granted under the 1998 Plan. We expect to recognize our share of this cost over a weighted-average period of 3.25 years in accordance with the EPCO administrative services agreement.

 

During the six months ended June 30, 2007 and 2006, we received cash of $7.3 million and $1.6 million, respectively, from the exercise of unit options, and our option-related reimbursements to EPCO were $2.8 million and $0.7 million, respectively.

 

 

11

 


Under the 1998 Plan, we may also issue restricted common units to key employees of EPCO and directors of our general partner. The following table summarizes information regarding our restricted common units for the periods indicated:

 

 

 

 

Weighted-

 

 

 

Average Grant

 

 

Number of

Date Fair Value

 

Units

per Unit (1)

Restricted units at December 31, 2006

1,105,237

 

 

Granted (2)

620,140

$    25.74

 

Forfeited or settled

(129,053)

$    23.28

Restricted units at June 30, 2007

1,596,324

 

 

 

 

(1)   Determined by dividing the aggregate grant date fair value of awards (including an allowance for forfeitures) by the number of awards issued.

(2)   Aggregate grant date fair value of restricted common unit awards issued during 2007 was $16.0 million based on a grant date market price of our common units ranging from $30.16 to $30.96 per unit and estimated forfeiture rates ranging from 9.2% to 17.0%.

 

During the three months ended June 30, 2007 and 2006, we recognized $2.3 million and $1.8 million, respectively, of compensation expense in connection with restricted common units. We recognized $3.7 million and $2.7 million of compensation expense in connection with restricted common units during the six months ended June 30, 2007 and 2006, respectively. No restricted units vested during the three and six months ended June 30, 2007. Compensation expense for the three and six months ended June 30 ,2007 includes $0.9 million associated with the resignation of our former chief executive officer.

 

As of June 30, 2007, there was $27.8 million of total unrecognized compensation cost related to restricted common units. We will recognize our share of such costs in accordance with the EPCO administrative services agreement. At June 30, 2007, these costs are expected to be recognized over a weighted-average period of 2.8 years.

 

The 1998 Plan provides for the issuance of up to 7,000,000 common units. As of June 30, 2007, 1,689,500 common units had been issued in connection with the exercise of unit options. After giving effect to outstanding unit options at June 30, 2007 and the issuance and forfeiture of restricted common units through June 30, 2007, a total of 3,606,303 additional common units could be issued under the 1998 Plan.

 

Employee Partnerships

 

For the three months ended June 30, 2007 and 2006, we recorded $0.7 million and $0.6 million, respectively, of compensation expense associated with EPE Unit I, EPE Unit II and EPE Unit III (“the Employee Partnerships”). We recorded $1.2 million and $1.1 million of compensation expense associated with the Employee Partnerships during the six months ended June 30, 2007 and 2006, respectively. As of June 30, 2007, there was $8.2 million of total unrecognized compensation cost related to EPE Unit I and EPE Unit II, of which we will recognize our share in accordance with the EPCO administrative services agreement.

 

EPE Unit III. EPE Unit III was formed on May 7, 2007 and owns 4,421,326 units of Enterprise GP Holdings contributed to it by a private company affiliate of EPCO, which, in turn, was made the Class A limited partner of EPE Unit III. On the date of contribution, the fair market value of the units contributed by the Class A limited partner was $170.0 million (the “Class A limited partner capital base”). Certain EPCO employees were issued Class B limited partner interests and admitted as Class B limited partners of EPE Unit III without any capital contribution. The profits interest awards (i.e., Class B limited partner interests) in EPE Unit III entitle the holder to participate in the appreciation in value of units of Enterprise GP Holdings owned by EPE Unit III.

 

 

12

 


Unless otherwise agreed to by EPCO, the Class A limited partner and a majority in interest of the Class B limited partners of EPE Unit III, EPE Unit III will be liquidated upon the earlier of: (i) May 7, 2012 or (ii) a change in control of Enterprise GP Holdings or its general partner. EPE Unit III has the following material terms regarding its quarterly cash distribution to partners:

 

 

§

Distributions of Cashflow Each quarter, 100% of the cash distributions received by EPE Unit III from Enterprise GP Holdings will be distributed to the Class A limited partner until it has received an amount equal to the Class A preferred return (as defined below), and any remaining distributions received by EPE Unit III will be distributed to the Class B limited partners. The Class A preferred return equals 3.797%, of the Class A limited partner’s capital base. The Class A limited partner’s capital base equals approximately $170.0 million plus any unpaid Class A preferred return from prior periods, less any distributions made by EPE Unit III of proceeds from the sale of Enterprise GP Holdings’ units owned by EPE Unit III (as described below).

 

 

§

Liquidating Distributions Upon liquidation of EPE Unit III, units having a fair market value equal to the Class A limited partner capital base will be distributed to a private company affiliate of EPCO, plus any accrued Class A preferred return for the quarter in which liquidation occurs. Any remaining units will be distributed to the Class B limited partners.

 

 

§

Sale Proceeds If EPE Unit III sells any of the 4,421,326 of Enterprise GP Holdings’ units that it owns, the sale proceeds will be distributed to the Class A limited partner and the Class B limited partners in the same manner as liquidating distributions described above.

 

The Class B limited partner interests in EPE Unit III that are owned by EPCO employees are subject to forfeiture if the participating employee’s employment with EPCO and its affiliates is terminated prior to May 7, 2012, with customary exceptions for death, disability and certain retirements. The risk of forfeiture associated with the Class B limited partner interests in EPE Unit III will also lapse upon certain change of control events.

 

As of June 30, 2007, there was $22.4 million of total unrecognized compensation cost related to these awards, of which we will recognize our share in accordance with the EPCO administrative services agreement.

 


Note 4. Financial Instruments

 

We are exposed to financial market risks, including changes in commodity prices and interest rates. In addition, we are exposed to fluctuations in exchange rates between the U.S. dollar and Canadian dollar. We may use financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions. In general, the type of risks we attempt to hedge are those related to (i) variability of future earnings, (ii) fair values of certain debt instruments and (iii) cash flows resulting from changes in applicable interest rates, commodity prices or exchange rates. As a matter of policy, we do not use financial instruments for speculative (or “trading”) purposes.

 

Interest Rate Risk Hedging Program

 

Our interest rate exposure results from variable and fixed interest rate borrowings under various debt agreements. We manage a portion of our interest rate exposure by utilizing interest rate swaps and similar arrangements, which allow us to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt.

 

 

 

 

13

 


Fair Value Hedges – Interest Rate Swaps. As summarized in the following table, we had eleven interest rate swap agreements outstanding at June 30, 2007 that were accounted for as fair value hedges.

 

 

Number

Period Covered

Termination

Fixed to

Notional

 

Hedged Fixed Rate Debt

Of Swaps

by Swap

Date of Swap

Variable Rate (1)

Amount

 

Senior Notes B, 7.50% fixed rate, due Feb. 2011

1

Jan. 2004 to Feb. 2011

Feb. 2011

7.50% to 8.74%

$50 million

 

Senior Notes C, 6.375% fixed rate, due Feb. 2013

2

Jan. 2004 to Feb. 2013

Feb. 2013

6.38% to 7.28%

$200 million

 

Senior Notes G, 5.6% fixed rate, due Oct. 2014

6

4th Qtr. 2004 to Oct. 2014

Oct. 2014

5.60% to 6.30%

$600 million

 

Senior Notes K, 4.95% fixed rate, due June 2010

2

Aug. 2005 to June 2010

June 2010

4.95% to 5.80%

$200 million

 

 

(1) The variable rate indicated is the all-in variable rate for the current settlement period.

                

The total fair value of these eleven interest rate swaps at June 30, 2007 and December 31, 2006, was a liability of $49.7 million and $29.1 million, respectively, with an offsetting decrease in the fair value of the underlying debt. Interest expense for the three months ended June 30, 2007 and 2006 includes a $2.3 million and $1.1 million loss from these swap agreements, respectively. For the six months ended June 30, 2007 and 2006, interest expense reflects a loss of $4.6 million and $0.9 million from these swap agreements, respectively.

 

Cash Flow Hedges – Treasury Locks. During the fourth quarter of 2006, EPO entered into treasury lock transactions having a notional value of $562.5 million. EPO entered into these transactions to hedge the underlying U.S. treasury rates related to its anticipated issuances of debt during the second and fourth quarters of 2007. On February 27, 2007, EPO entered into additional treasury lock transactions having a notional value of $437.5 million. EPO entered into these transactions to hedge the underlying U.S. treasury rates related to its anticipated issuances of debt during 2007. Each of the treasury lock transactions was designated as a cash flow hedge under SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended and interpreted.

 

During the second quarter of 2007, treasury locks having a notional amount of $875.0 million were terminated. Treasury locks having a notional amount of $500.0 million were terminated concurrent with the issuance of EPO’s Junior Notes B (see Note 9). An additional $375.0 million notional amount of treasury locks related to the anticipated issuance of debt in the fourth quarter of 2007 were also terminated. The termination of the treasury locks resulted in gains of $42.3 million of which $10.6 million is related to EPO’s Junior Notes B and the remaining $31.7 million is related to a future debt issuance. The $10.6 million gain is being amortized into income using the effective interest method as reductions to future interest expense over the fixed rate term of the Junior Notes B, which is ten years. The remaining $31.7 million gain will be amortized into income over the life of the future debt issuance using the effective interest rate method.

 

At June 30, 2007, there was one treasury lock outstanding which has a notional amount of $125.0 million and a fair value of $9.3 million.

 

Commodity Risk Hedging Program

 

The prices of natural gas, NGLs and certain petrochemical products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. In order to manage the price risks associated with such products, we may enter into commodity financial instruments.

 

The primary purpose of our commodity risk management activities is to hedge our exposure to price risks associated with (i) natural gas purchases, (ii) the value of NGL production and inventories, (iii) related firm commitments, (iv) fluctuations in transportation revenues where the underlying fees are based on natural gas index prices and (v) certain anticipated transactions involving either natural gas, NGLs or certain petrochemical products. From time to time, we inject natural gas into storage and utilize hedging instruments to lock in the value of our inventory positions. The commodity financial instruments we utilize may be settled in cash or with another financial instrument.

 

 

14

 


At June 30, 2007 and December 31, 2006, we had a limited number of commodity financial instruments in our portfolio, which primarily consisted of cash flow hedges. The fair value of our commodity financial instrument portfolio at June 30, 2007 and December 31, 2006 was a liability of $1.0 million and $3.2 million, respectively. During the three and six months ended June 30, 2007, we recorded income of $1.1 million and expense of $1.3 million, respectively, related to our commodity financial instruments. During the three and six months ended June 30, 2006 we recorded $5.9 million and $5.5 million, respectively, of expense related to our commodity financial instruments.

 

Foreign Currency Hedging Program

 

We own an NGL marketing business located in Canada and have entered into construction agreements where payments are indexed to the Canadian dollar. As a result, we could be adversely affected by fluctuations in the foreign currency exchange rate between the U.S. dollar and the Canadian dollar. We attempt to hedge this risk using foreign exchange purchase contracts to fix the exchange rate. Due to the limited duration of these contracts, we utilize mark-to-market accounting for these transactions, the effect of which has had a minimal impact on our earnings. We had $3.1 million of such contracts outstanding at June 30, 2007 that settled in July 2007.

 


Note 5. Inventories

 

 

Our inventory amounts were as follows at the dates indicated:

 

 

 

June 30,

December 31,

 

 

2007

2006

Working inventory

$      325,539

$      387,973

Forward-sales inventory

10,083

35,871

Inventory

$      335,622

$      423,844

 

Our regular trade (or “working”) inventory is comprised of inventories of natural gas, NGLs, and certain petrochemical products that are available-for-sale or used by us in the provision of services. Our forward sales inventory consists of segregated NGL and natural gas volumes dedicated to the fulfillment of forward-sales contracts. Our inventory values reflect payments for product purchases, freight charges associated with such purchase volumes, terminal and storage fees, vessel inspection costs, demurrage charges and other related costs. We value our inventories at the lower of average cost or market.

 

Operating costs and expenses, as presented on our Unaudited Condensed Statements of Consolidated Operations, include cost of sales amounts related to the sale of inventories. Our cost of sales was $3.6 billion and $3.0 billion for the three months ended June 30, 2007 and 2006, respectively. For the six months ended June 30, 2007 and 2006, our cost of sales was $6.4 billion and $5.7 billion, respectively.

 

Due to fluctuating commodity prices in the NGL, natural gas and petrochemical industry, we recognize lower of cost or market (“LCM”) adjustments when the carrying value of our inventories exceed their net realizable value. These non-cash charges are a component of cost of sales in the period they are recognized. For the three months ended June 30, 2007 and 2006, we recognized LCM adjustments of approximately $2.1 million and $0.3 million, respectively. We recognized LCM adjustments of $13.1 million and $12.0 million for the six months ended June 30, 2007 and 2006, respectively.

 

 

 

 

 

 

15

 


Note 6. Property, Plant and Equipment

 

Our property, plant and equipment values and accumulated depreciation balances were as follows at the dates indicated:

 

 

Estimated

 

 

 

Useful Life

June 30,

December 31,

 

in Years

2007

2006

Plants and pipelines (1)

3-35 (5)

$      9,454,757

$    8,774,683

Underground and other storage facilities (2)

5-35 (6)

679,147

596,649

Platforms and facilities (3)

20-31

591,272

161,839

Transportation equipment (4)

3-10

28,964

27,008

Land

 

41,945

40,010

Construction in progress

 

1,632,248

1,734,083

Total

 

12,428,333

11,334,272

Less accumulated depreciation

 

1,694,203

1,501,725

Property, plant and equipment, net

 

$    10,734,130

$    9,832,547

 

 

 

 

(1)   Plants and pipelines include processing plants; NGL, petrochemical, oil and natural gas pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings; laboratory and shop equipment; and related assets.

(2)   Underground and other storage facilities include underground product storage caverns; storage tanks; water wells; and related assets.

(3)   Platforms and facilities include offshore platforms and related facilities and other associated assets.

(4)   Transportation equipment includes vehicles and similar assets used in our operations.

(5)   In general, the estimated useful lives of major components of this category are as follows: processing plants, 20-35 years; pipelines, 18-35 years (with some equipment at 5 years); terminal facilities, 10-35 years; office furniture and equipment, 3-20 years; buildings 20-35 years; and laboratory and shop equipment, 5-35 years.

(6)   In general, the estimated useful lives of major components of this category are as follows: underground storage facilities, 20-35 years (with some components at 5 years); storage tanks, 10-35 years; and water wells, 25-35 years (with some components at 5 years).

 

Depreciation expense for the three months ended June 30, 2007 and 2006 was $99.1 million and $86.9 million, respectively. For the six months ended June 30, 2007 and 2006, depreciation expense was $194.1 million and $170.4 million, respectively. We capitalized $20.4 million and $12.4 million of interest in connection with capital projects during the three months ended June 30, 2007 and 2006, respectively. During the six months ended June 30, 2007 and 2006, we capitalized $41.1 million and $21.6 million, respectively, in connection with capital projects.

 


Note 7. Investments In and Advances to Unconsolidated Affiliates

 

We own interests in a number of related businesses that are accounted for using the equity method of accounting. Our investments in and advances to unconsolidated affiliates are grouped according to the business segment to which they relate. See Note 11 for a general discussion of our business segments.

 

 

 

 

 

 

 

16

 


 

The following table presents our investments in and advances to unconsolidated affiliates at the dates indicated:

 

 

 

 

Ownership

Investments in and advances to

 

 

 

Percentage at

unconsolidated affiliates at

 

 

 

June 30,

June 30,

December 31,

 

 

 

2007

2007

2006

NGL Pipelines & Services:

 

 

 

 

Venice Energy Service Company L.L.C. (“VESCO”)

13.1%

$    42,340

$    39,618

 

K/D/S Promix, L.L.C. (“Promix”)

50%

55,091

46,140

 

Baton Rouge Fractionators LLC (“BRF”)

32.3%

25,057

25,471

Onshore Natural Gas Pipelines & Services:

 

 

 

 

Jonah Gas Gathering Company (“Jonah”)

19.6%

200,649

120,370

 

Evangeline (1)

49.5%

3,641

4,221

Offshore Pipelines & Services:

 

 

 

 

Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)

36%

59,161

62,324

 

Cameron Highway Oil Pipeline Company (“Cameron Highway”) (2)

50%

259,369

60,216

 

Deepwater Gateway, L.L.C. (“Deepwater Gateway”)

50%

113,345

117,646

 

Neptune Pipeline Company, L.L.C. (“Neptune”)

25.7%

56,676

58,789

 

Nemo Gathering Company, LLC (“Nemo”) (3)

33.9%

2,637

11,161

Petrochemical Services:

 

 

 

 

Baton Rouge Propylene Concentrator, LLC (“BRPC”)

30%

13,896

13,912

 

La Porte (4)

50%

4,229

4,691

Total

 

 

$    836,091

$    564,559

 

 

 

 

 

 

(1)    Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively.

(2)    During the second quarter of 2007, we contributed $216.5 million to Cameron Highway to fund our portion of the repayment of Cameron Highway’s debt. See “Cameron Highway” discussion within this Note 7.

(3)    During the three months ended June 30, 2007, we recorded a $7.0 million non-cash impairment charge attributable to our investment in Nemo. See “Nemo” discussion within this Note 7.

(4)    Refers to our ownership interests in La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively.

 

On occasion, the price we pay to acquire an ownership interest in a company exceeds the underlying book value of the capital accounts we acquire. Such excess cost amounts are included within the carrying values of our investments in and advances to unconsolidated affiliates. At June 30, 2007 and December 31, 2006, our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway, Nemo and Jonah included excess cost amounts totaling $42.9 million and $38.7 million, respectively. These amounts are attributable to the excess of the fair value of each entity’s tangible assets over their respective book carrying values at the time we acquired an interest in each entity. We amortize such excess cost amounts as a reduction in equity earnings. Amortization of such excess cost amounts was $0.5 million and $0.6 million during the three months ended June 30, 2007 and 2006, respectively. For the six months ended June 30, 2007 and 2006, amortization of such amounts was $1.0 million and $1.1 million, respectively.

 

The following table presents our equity in income (loss) of unconsolidated affiliates by business segment for the periods indicated:

 

 

 

For the Three Months

For the Six Months

 

 

Ended June 30,

Ended June 30,

 

 

2007

2006

2007

2006

NGL Pipelines & Services

$    1,089

$    1,924

$    1,680

$    3,442

Onshore Natural Gas Pipelines & Services

1,212

904

2,241

1,506

Offshore Pipelines & Services (1) (2)

(8,846)

4,769

(4,771)

6,703

Petrochemical Services

334

415

818

390

 

Total

$  (6,211)

$    8,012

$       (32)

$  12,041

 

 

 

 

 

 

(1)    Equity earnings from Nemo for the three and six months ended June 30, 2007 includes a $7.0 million non-cash impairment charge. See “Nemo” discussion within this Note 7.

(2)    Equity earnings from Cameron Highway for the three and six months ended June 30, 2007 were reduced by a charge of $8.8 million for costs associated with the early retirement of Cameron Highway’s debt.

 

17

 


 

Summarized Financial Information of Unconsolidated Affiliates

 

The following tables present unaudited income statement data for our current unconsolidated affiliates, aggregated by business segment, for the periods indicated (on a 100% basis).

 

 

 

 

Summarized Income Statement Information for the Three Months Ended

 

 

 

June 30, 2007

 

June 30, 2006

 

 

 

 

Operating

Net

 

 

Operating

Net

 

 

 

Revenues

Income (Loss)

Income (Loss)

 

Revenues

Income (Loss)

Income (Loss)

NGL Pipelines & Services (1)

$   59,056

$   (779)

$   (74)

 

$   60,220

$   (2,238)

$   (1,785)

Onshore Natural Gas Pipelines & Services

125,132

25,198

24,102

 

117,636

20,127

16,315

Offshore Pipelines & Services

40,433

24,146

1,894

 

39,554

20,166

12,804

Petrochemical Services

4,969

1,403

1,429

 

5,557

1,645

1,665

(1)    During the three months ended June 30, 2006, VESCO earnings were reduced due to the lingering effects of Hurricane Katrina, including significant storm-related repair expenses.

 

 

 

 

Summarized Income Statement Information for the Six Months Ended

 

 

 

June 30, 2007

 

June 30, 2006

 

 

 

 

Operating

Net

 

 

Operating

Net

 

 

 

Revenues

Income

Income

 

Revenues

Income (Loss)

Income (Loss)

NGL Pipelines & Services (1)

$   100,788

$   2,481

$   3,755

 

$   80,506

$   (24,363)

$   (23,463)

Onshore Natural Gas Pipelines & Services

234,030

46,813

44,415

 

226,424

59,023

50,759

Offshore Pipelines & Services

77,626

43,864

14,230

 

71,250

31,096

16,484

Petrochemical Services

10,522

3,290

3,340

 

9,425

1,831

1,875

(1)    During the six months ended June 30, 2006, VESCO earnings were reduced due to the lingering effects of Hurricane Katrina, including significant storm-related repair expenses.

 

Cameron Highway

 

We own a 50.0% interest in Cameron Highway, which owns a crude oil pipeline that gathers production from deepwater areas of the Gulf of Mexico, primarily the South Green Canyon area, for delivery to refineries and terminals in southeast Texas. In May 2007, we made an approximate $191.0 million cash contribution to Cameron Highway. This capital contribution, along with an equal amount contributed by our joint venture partner in Cameron Highway, was used by Cameron Highway to repay $365.0 million outstanding under its Senior Notes A and $14.1 million of related make-whole premiums and accrued interest. In June 2007, we and our joint venture partner in Cameron Highway, made an additional capital contribution of approximately $25.5 million each. These capital contributions were used by Cameron Highway to repay its Series B notes on June 7, 2007. The amount of the repayment was $50.9 million, which included $0.9 million of related make-whole premiums and accrued interest. As of June 30, 2007, Cameron Highway no longer has any outstanding debt.

 

Nemo

 

Nemo was formed in 1999 to construct, own and operate the Nemo Gathering System, a 24-mile natural gas gathering system in the Gulf of Mexico offshore Louisiana. The Nemo Gathering System, which began operations in 2001, gathers natural gas from certain developments in the Green Canyon area of the Gulf of Mexico to a pipeline interconnect with the Manta Ray Gathering System. Due to a recent decrease in throughput volumes on the Nemo Gathering System, we evaluated our 33.9% investment in Nemo for impairment during the second quarter of 2007. The decrease in throughput volumes is primarily due to underperformance of certain fields and natural depletion.

 

At December 31, 2006, the carrying value of our investment in Nemo was $11.2 million, which included $0.6 million of excess cost related to its original acquisition in 2001. Our review of Nemo’s estimated future cash flows during the second quarter of 2007 indicated that the carrying value of our investment exceeded its fair value, which resulted in a non-cash charge of $7.0 million. This loss is recorded as a component of “Equity in income of unconsolidated affiliates” in our Unaudited Condensed Statements of Consolidated Operations for the three and six months ended June 30, 2007. Equity earnings from our investment in Nemo are classified under our Offshore Pipelines & Services business segment.

 

18

 


After recording this impairment charge, the carrying value of our investment in Nemo at June 30, 2007 was $2.6 million, which reflects $0.5 million in losses and $2.0 million of distributions we recorded during the first six months of 2007.

 

Our investment in Nemo was written down to fair value, which management prepared using recognized business valuation techniques. The fair value analysis is based upon management’s expectation of future cash flows. Such expectation of future cash flows incorporates industry information and assumptions made by management. For example, the review of Nemo included management estimates regarding the remaining natural gas reserves of producers served by the Nemo Gathering System. If the assumptions underlying our fair value analysis change and expected cash flows are reduced, additional impairment charges may result.

 


Note 8. Intangible Assets and Goodwill

 

Identifiable Intangible Assets

 

The following table summarizes our intangible assets at the dates indicated:

 

 

June 30, 2007

 

December 31, 2006

 

Gross

Accum.

Carrying

 

Gross

Accum.

Carrying

 

Value

Amort.

Value

 

Value

Amort.

Value

NGL Pipelines & Services (1)

$     520,025

$  (128,577)

$  391,448

 

$     528,594

$  (110,644)

$     417,950

Onshore Natural Gas Pipelines & Services

463,551

(93,611)

369,940

 

463,551

(77,402)

386,149

Offshore Pipelines & Services

207,012

(64,624)

142,388

 

207,012

(54,636)

152,376

Petrochemical Services

56,674

(10,190)

46,484

 

56,674

(9,194)

47,480

Total

$  1,247,262

$  (297,002)

$  950,260

 

$  1,255,831

$ (251,876)

$  1,003,955

 

 

 

 

 

 

 

 

(1)    During the second quarter of 2007, we adjusted our preliminary purchase price allocation related to the Piceance Creek Acquisition. This adjustment resulted in the reclassification of $8.5 million from intangible assets to property, plant and equipment.

 

The following table presents the amortization expense of our intangible assets by segment for the periods indicated:

 

 

 

For the Three Months

For the Six Months

 

 

Ended June 30,

Ended June 30,

 

 

2007

2006

2007

2006

NGL Pipelines & Services

$      8,801

$      6,304

$    18,042

$    12,665

Onshore Natural Gas Pipelines & Services

8,049

8,348

16,209

16,806

Offshore Pipelines & Services

4,908

5,633

9,988

11,467

Petrochemical Services

498

497

996

996

 

Total

$    22,256

$    20,782

$    45,235

$    41,934

 

For the remainder of 2007, amortization expense associated with our intangible assets is currently estimated at $44.5 million.

 

Goodwill

 

The following table summarizes our goodwill amounts by segment at the dates indicated:

 

 

June 30,

December 31,

 

2007

2006

NGL Pipelines & Services

$    152,701

$    152,595

Onshore Natural Gas Pipelines & Services

282,121

282,121

Offshore Pipelines & Services

82,135

82,135

Petrochemical Services

73,690

73,690

Totals

$    590,647

$    590,541

 

 

19

 


 

Note 9. Debt Obligations

 

Our consolidated debt obligations consisted of the following at the dates indicated:

 

 

 

 

June 30,

December 31,

 

 

 

2007

2006

EPO senior debt obligations:

 

 

 

Multi-Year Revolving Credit Facility, variable rate, due October 2011

$       495,000

$       410,000

 

Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010

54,000

54,000

 

Senior Notes B, 7.50% fixed-rate, due February 2011

450,000

450,000

 

Senior Notes C, 6.375% fixed-rate, due February 2013

350,000

350,000

 

Senior Notes D, 6.875% fixed-rate, due March 2033

500,000

500,000

 

Senior Notes E, 4.00% fixed-rate, due October 2007 (1)

500,000

500,000

 

Senior Notes F, 4.625% fixed-rate, due October 2009

500,000

500,000

 

Senior Notes G, 5.60% fixed-rate, due October 2014

650,000

650,000

 

Senior Notes H, 6.65% fixed-rate, due October 2034

350,000

350,000

 

Senior Notes I, 5.00% fixed-rate, due March 2015

250,000

250,000

 

Senior Notes J, 5.75% fixed-rate, due March 2035

250,000

250,000

 

Senior Notes K, 4.950% fixed-rate, due June 2010

500,000

500,000

Duncan Energy Partners’ debt obligation:

 

 

 

$300 Million Revolving Credit Facility, variable rate, due February 2011

190,000

--

Dixie Revolving Credit Facility, variable rate, due June 2010

10,000

10,000

Canadian Enterprise Revolving Credit Facility, variable rate, due October 2011

9,881

--

Other, 8.75% fixed-rate, due June 2010(2)

5,068

5,068

 

 

Total principal amount of senior debt obligations

5,063,949

4,779,068

EPO Junior Subordinated Notes A, due August 2066

550,000

550,000

EPO Junior Subordinated Notes B, due January 2068

700,000

--

Total principal amount of senior and junior debt obligations

6,313,949

5,329,068

Other, including unamortized discounts and premiums and changes in fair value (3)

(54,234)

(33,478)

 

 

Long-term debt

$    6,259,715

$    5,295,590

 

 

 

 

 

Standby letters of credit outstanding

$           4,000

$         49,858

 

 

 

 

 

(1)    In accordance with SFAS 6, “Classification of Short-Term Obligations Expected to be Refinanced,” long-term and current maturities of debt reflects the classification of such obligations at June 30, 2007 and December 31, 2006. With respect to Senior Notes E due in October 2007, EPO has the ability to use cash and available credit capacity under its $1.25 billion Multi-Year Revolving Credit Facility to fund the repayment of this debt.

(2)    Represents remaining debt obligations assumed in connection with the GulfTerra Merger.

(3)    The June 30, 2007 amount includes $49.7 million related to fair value hedges and a net $4.5 million in unamortized discounts and premiums. The December 31, 2006 amount includes $29.1 million related to fair value hedges and a net $4.4 million in unamortized discounts and premiums.

 

Parent-Subsidiary guarantor relationships

 

We act as guarantor of the debt obligations of EPO with the exception of the Dixie revolving credit facility and the senior subordinated notes we assumed in connection with the GulfTerra Merger. If EPO were to default on any debt we guarantee, we would be responsible for full repayment of that obligation. We do not act as guarantor of the debt obligations of Duncan Energy Partners.

 

EPO’s debt obligations

 

Apart from that discussed below, there have been no significant changes in the terms of EPO’s debt obligations since those reported in our annual report on Form 10-K for the year ended December 31, 2006.

 

Junior Notes B. EPO sold $700 million in principal amount of fixed/floating, unsecured, long-term subordinated notes due January 2068 (“Junior Notes B”) during the second quarter of 2007. EPO used the proceeds from this subordinated debt to temporarily reduce borrowings outstanding under its Multi-Year Revolving Credit Facility and for general partnership purposes. EPO’s payment obligations under Junior Notes B are subordinated to all of its current and future senior indebtedness (as defined in the

 

20

 


Indenture Agreement). We have guaranteed repayment of amounts due under Junior Notes B through an unsecured and subordinated guarantee.

 

The indenture agreement governing Junior Notes B allows EPO to defer interest payments on one or more occasions for up to ten consecutive years subject to certain conditions. During any period in which interest payments are deferred and subject to certain exceptions, neither we nor EPO can declare or make any distributions to any of our respective equity securities or make any payments on indebtedness or other obligations that rank pari passu with or are subordinate to Junior Notes B. Junior Notes B rank pari passu with the Junior Subordinated Notes A, due August 2066 (“Junior Notes A”), which were issued during the third quarter of 2006.

 

The Junior Notes B will bear interest at a fixed annual rate of 7.034% through January 15, 2018, payable semi-annually in arrears in January and July of each year, commencing in January 2008. After January 2018, the Junior Notes B will bear variable rate interest at the greater of (1) the sum of the 3-month London Interbank Offered Rate (“LIBOR”) for the related interest period plus a spread of 268 basis points or (2) 7.034% per annum, payable quarterly in arrears in January, April, July and October of each year commencing in April 2018. Interest payments may be deferred on a cumulative basis for up to ten consecutive years, subject to the certain provisions. The Junior Notes B mature in January 2068 and are not redeemable by EPO prior to January 2018 without payment of a make-whole premium.

 

In connection with the issuance of Junior Notes B, we and EPO entered into a Replacement Capital Covenant in favor of the covered debt holders (as named therein) pursuant to which we and EPO agreed for the benefit of such debt holders that we nor EPO would not redeem or repurchase such junior notes on or before January 15, 2038, unless such redemption or repurchase is made from the proceeds of issuance of certain securities.

 

Duncan Energy Partners’ debt obligation

 

We consolidate the debt of Duncan Energy Partners with that of our own; however, we do not have the obligation to make interest payments or debt payments with respect to the debt of Duncan Energy Partners.

 

Duncan Energy Partners entered into a $300.0 million revolving credit facility, all of which may be used for letters of credit, with a $30.0 million sublimit for Swingline loans. Letters of credit outstanding under this facility reduce the amount available for borrowings. At the closing of its initial public offering, Duncan Energy Partners made its initial borrowing of $200.0 million under the facility to fund the $198.9 million cash distribution to EPO and the remainder to pay debt issuance costs. At June 30, 2007, the balance outstanding under this facility was $190.0 million.

 

This credit facility matures in February 2011 and will be used by Duncan Energy Partners in the future to fund working capital and other capital requirements and for general partnership purposes. Duncan Energy Partners may make up to two requests for one-year extensions of the maturity date (subject to certain restrictions). The revolving credit facility is available to pay distributions upon the initial contribution of assets to Duncan Energy Partners, fund working capital, make acquisitions and provide payment for general purposes. Duncan Energy Partners can increase the revolving credit facility, without consent of the lenders, by an amount not to exceed $150.0 million by adding to the facility one or more new lenders and/or increasing the commitments of existing lenders. No existing lender is required to increase its commitment, unless it agrees to do so in its sole discretion.

 

This revolving credit facility offers the following unsecured loans, each having different interest requirements: (i) LIBOR loans bear interest at a rate per annum equal to LIBOR plus the applicable LIBOR margin (as defined in the credit agreement), (ii) Base Rate loans bear interest at a rate per annum equal to the higher of (a) the rate of interest publicly announced by the administrative agent, Wachovia Bank, National Association, as its Base Rate and (b) 0.5% per annum above the Federal Funds Rate in effect on such date and (iii) Swingline loans bear interest at a rate per annum equal to LIBOR plus an applicable LIBOR margin.

 

21

 


 

The revolving credit facility requires Duncan Energy Partners to maintain a leverage ratio for the prior four fiscal quarters of not more than 4.75 to 1.00 at the last day of each fiscal quarter commencing June 30, 2007; provided that, upon the closing of a permitted acquisition, such ratio shall not exceed (a) 5.25 to 1.00 at the last day of the fiscal quarter in which such specified acquisition occurred and at the last day of each of the two fiscal quarters following the fiscal quarter in which such specified acquisition occurred, and (b) 4.75 to 1.00 at the last day of each fiscal quarter thereafter. In addition, prior to obtaining an investment-grade rating by Standard & Poor’s Ratings Services, Moody’s Investors Service or Fitch Ratings, Duncan Energy Partners’ interest coverage ratio, for the prior four fiscal quarters shall not be less than 2.75 to 1.00 at the last day of each fiscal quarter commencing June 30, 2007.

 

The Duncan Energy Partners’ credit facility contains other customary covenants. Also, if an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity date of amounts borrowed under the credit agreement and exercise other rights and remedies.

 

Canadian Debt Obligations

 

In May 2007, Canadian Enterprise Gas Products, Ltd. (“Canadian Enterprise”), a wholly-owned subsidiary of EPO, entered into a $30.0 million Canadian revolving credit facility with The Bank of Nova Scotia. The credit facility, which includes the issuance of letters of credit, matures in October 2011. Letters of credit outstanding under this facility reduce the amount available for borrowings.

 

Borrowings may be made in Canadian or U.S. dollars. Canadian denominated borrowings may be comprised of Canadian Prime Rate (“CPR”) loans or Bankers’ Acceptances and U.S denominated borrowings may be comprised of Alternative Base Rate (“ABR”) or Eurodollar loans, each having different interest rate requirements. CPR loans bear interest at a rate determined by reference to the Canadian Prime Rate. ABR loans bear interest at a rate determined by reference to an alternative base rate as defined in the credit agreement. Eurodollar loans bear interest at a rate determined by the LIBOR plus an applicable rate as defined in the credit agreement. Bankers’ Acceptances carry interest at the rate for Canadian bankers’ acceptances plus an applicable rate as defined in the credit agreement.

 

The credit facility contains customary covenants and events of default. The restrictive covenants limit Canadian Enterprise from materially changing the nature of its business or operations, dissolving, or completing mergers. A continuing event of default would accelerate the maturity of amounts borrowed under the credit facility. The obligations under the credit facility are guaranteed by EPO.

 

Covenants

 

We are in compliance with the covenants of our consolidated debt agreements at June 30, 2007 and December 31, 2006.

 

Information regarding variable interest rates paid

 

The following table presents the range of interest rates paid and weighted-average interest rate paid on our consolidated variable-rate debt obligations during the six months ended June 30, 2007.

 

 

Range of

Weighted-average

 

interest rates

interest rate

 

paid

paid

EPO’s Multi-Year Revolving Credit Facility

5.82% to 8.25%

5.86%

Duncan Energy Partners’ Revolving Credit Facility

6.17%

6.17%

Dixie Revolving Credit Facility

5.66% to 5.67%

5.66%

Canadian Enterprise Revolving Credit Facility

4.95% to 5.82%

5.77%

 

 

22

 


 

Consolidated debt maturity table

 

The following table presents the scheduled maturities of principal amounts of our debt obligations for the next five years and in total thereafter.

 

2007

$                 --

2008

--

2009

500,000

2010

569,068

2011

1,644,881

Thereafter

3,600,000

Total scheduled principal payments

$    6,313,949

 

In accordance with SFAS 6, long-term and current maturities of debt reflect the classification of such obligations at June 30, 2007 and December 31, 2006. With respect to the $500.0 million in principal due under Senior Notes E in October 2007, EPO has the ability to use cash and available credit capacity under its Multi-Year Revolving Credit Facility to fund the repayment of this debt. The preceding table and our Unaudited Condensed Consolidated Balance Sheets at June 30, 2007 and December 31, 2006 reflect this ability to refinance.

 

Debt Obligations of Unconsolidated Affiliates

 

We have two unconsolidated affiliates with long-term debt obligations. The following table shows (i) our ownership interest in each entity at June 30, 2007, (ii) total debt of each unconsolidated affiliate at June 30, 2007 (on a 100% basis to the affiliate) and (iii) the corresponding scheduled maturities of such debt.

 

 

Our

 

Scheduled Maturities of Debt

 

Ownership

 

 

 

 

 

 

After

 

Interest

Total

2007

2008

2009

2010

2011

2011

Poseidon

36.0%

$    91,000

$        --

$        --

$        --

$          --

$  91,000

$      --

Evangeline

49.5%

25,650

5,000

5,000

5,000

10,650

--

--

Total

 

$  116,650

$  5,000

$  5,000

$  5,000

$  10,650

$  91,000

$      --

 

Previously, Cameron Highway’s debt consisted of $365.0 million of Series A notes and $50.0 million of Series B notes. Cameron Highway repaid its Series A notes on May 23, 2007 using proceeds from capital contributions from its partners. The total amount of the repayment was $379.1 million, which included an $11.0 million make-whole premium and $3.1 million of accrued interest. Our share of the capital contribution was funded by borrowings under EPO’s Multi-Year Revolving Credit Facility. With another capital contribution from its partners, Cameron Highway also repaid its Series B notes on June 7, 2007. The amount of the repayment was $50.9 million, which included a $0.3 million make-whole premium and $0.6 million of accrued interest. As of June 30, 2007, Cameron Highway no longer has any outstanding debt.

 

The credit agreements of our unconsolidated affiliates contain various affirmative and negative covenants, including financial covenants. These businesses were in compliance with such covenants at June 30, 2007. The credit agreements of our unconsolidated affiliates restrict their ability to pay cash dividends if a default or an event of default (as defined in each credit agreement) has occurred and is continuing at the time such dividend is scheduled to be paid.

 

Apart from the repayment of Cameron Highway’s Series A and Series B notes, there have been no significant changes in the terms of the debt obligations of our unconsolidated affiliates since those reported in our annual report on Form 10-K for the year ended December 31, 2006.

 

23

 


 

Note 10. Partners’ Equity and Distributions

 

Our common units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under our Fifth Amended and Restated Agreement of Limited Partnership (together with all amendments thereto, the “Partnership Agreement”). We are managed by our general partner, Enterprise Products GP.

 

In accordance with the Partnership Agreement, capital accounts are maintained for our general partner and limited partners. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in our consolidated financial statements.

 

Our Partnership Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that our limited partners and general partner will receive. The Partnership Agreement also contains provisions for the allocation of net earnings and losses to our limited partners and general partner. For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interests. Normal income and loss allocations according to percentage interests are done only after giving effect to priority earnings allocations in an amount equal to incentive cash distributions allocated to our general partner.

 

Equity Offerings and Registration Statements

 

In general, the Partnership Agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities for such consideration and on such terms and conditions as may be established by Enterprise Products GP in its sole discretion (subject, under certain circumstances, to the approval of our unitholders).

 

We have a universal shelf registration statement on file with the SEC registering the issuance of up to $4 billion of equity and debt securities. After taking into account past issuance of securities under this registration statement, we have the ability to issue approximately $1.4 billion of additional securities under this registration statement as of June 30, 2007.

 

In April 2007, we filed a registration statement with the SEC authorizing the issuance of up to 25,000,000 common units in connection with our distribution reinvestment plan (“DRIP”). The DRIP provides unitholders of record and beneficial owners of our common units a voluntary means by which they can increase the number of common units they own by reinvesting the quarterly cash distributions they would otherwise receive into the purchase of additional common units. A total of 932,800 of our common units were issued in February 2007 and May 2007 in connection with the DRIP and the employee unit purchase plan (“EUPP”). The issuance of these units generated $28.6 million in net proceeds.

 

In May 2007, EPO sold $700 million in principal amount of Junior Notes B under our universal shelf registration statement. For additional information regarding this debt offering, see Note 9.

 

The following table reflects the number of common units issued and the net proceeds received from underwritten and other common unit offerings completed during the six months ended June 30, 2007:

 

 

Net Proceeds from Sale of Common Units

 

Number of

Contributed

Contributed by

Total

 

common units

by Limited

General

Net

 

issued

Partners

Partner

Proceeds

February DRIP and EUPP

438,631

$  12,495

$       255

$  12,750

May DRIP and EUPP

494,169

15,181

622

15,803

Total 2007

932,800

$  27,676

$       877

$  28,553

 

24

 


 

Summary of Changes in Outstanding Units

 

The following table summarizes changes in our outstanding units since December 31, 2006:

 

 

 

 

 

Restricted

 

 

 

Common

Common

 

 

 

Units

Units

Balance, December 31, 2006

431,303,193

1,105,237

 

Units issued in connection with DRIP and EUPP

932,800

--

 

Units issued in connection with equity-based awards

230,500

--

 

Restricted common units issued

--

620,140

 

Forfeiture or settlement of restricted units

--

(129,053)

Balance, June 30, 2007

432,466,493

1,596,324

 

Summary of Changes in Limited Partners’ Equity

 

The following table details the changes in limited partners’ equity since December 31, 2006:

 

 

 

 

Restricted

 

 

 

Common

Common

 

 

 

Units

Units

Total

Balance, December 31, 2006

$  6,320,577

$    9,340

$  6,329,917

 

Net income

198,010

566

198,576

 

Operating leases paid by EPCO

1,029

3

1,032

 

Cash distributions to partners

(406,778)

(1,048)

(407,826)

 

Net proceeds from sales of common units

27,676

--

27,676

 

Proceeds from exercise of unit options

7,139

--

7,139

 

Repurchase of restricted units and options

(512)

(1,056)

(1,568)

 

Unit option reimbursements to EPCO

(2,786)

--

(2,786)

 

Amortization of equity-based awards

1,590

3,584

5,174

Balance, June 30, 2007

$  6,145,945

$  11,389

$  6,157,334

  

Distributions to Partners

 

The percentage interest of Enterprise Products GP in our quarterly cash distributions is increased after certain specified target levels of quarterly distribution rates are met. At current distribution rates, we are in the highest tier of such incentive targets. Enterprise Products GP’s quarterly incentive distribution thresholds are as follows:

 

 

§

2% of quarterly cash distributions up to $0.253 per unit;

 

§

15% of quarterly cash distributions from $0.253 per unit up to $0.3085 per unit; and

 

§

25% of quarterly cash distributions that exceed $0.3085 per unit.

 

We paid incentive distributions of $26.3 million and $21.0 million to Enterprise Products GP during the three months ended June 30, 2007 and 2006, respectively. During the six months ended June 30, 2007 and 2006, we paid incentive distributions of $51.6 million and $40.1 million, respectively, to Enterprise Products GP.

 

Our quarterly cash distributions for 2007 are presented in the following table:

 

 

Cash Distribution History

 

Distribution

Record

Payment

 

per Unit

Date

Date

1st Quarter 2007

$ 0.4750

Apr. 30, 2007

May 10, 2007

2nd Quarter 2007

$ 0.4825

Jul. 31, 2007

Aug. 9, 2007


25

 


 

Note 11. Business Segments

 

We have four reportable business segments: NGL Pipelines & Services; Onshore Natural Gas Pipelines & Services; Offshore Pipelines & Services; and Petrochemical Services. Our business segments are generally organized and managed according to the type of services rendered (or technologies employed) and products produced and/or sold.

 

We evaluate segment performance based on the non-GAAP financial measure of gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. The GAAP financial measure most directly comparable to total segment gross operating margin is operating income. Our non-GAAP financial measure of total segment gross operating margin should not be considered an alternative to GAAP operating income.

 

We define total segment gross operating margin as consolidated operating income before: (i) depreciation, amortization and accretion expense; (ii) operating lease expenses for which we do not have the payment obligation; (iii) gains and losses on the sale of assets; and (iv) general and administrative costs. Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, minority interest, extraordinary charges and the cumulative effect of change in accounting principle. Gross operating margin by segment is calculated by subtracting segment operating costs and expenses (net of the adjustments noted above) from segment revenues, with both segment totals before the elimination of intersegment and intrasegment transactions.

 

Segment revenues include intersegment and intrasegment transactions, which are generally based on transactions made at market-related rates. Our consolidated revenues reflect the elimination of intercompany (both intersegment and intrasegment) transactions.

 

We include equity earnings from unconsolidated affiliates in our measurement of segment gross operating margin and operating income. Our equity investments with industry partners are a vital component of our business strategy. They are a means by which we conduct our operations to align our interests with those of our customers and/or suppliers. This method of operation enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what we could accomplish on a stand-alone basis. Many of these businesses perform supporting or complementary roles to our other business operations.

 

Our integrated midstream energy asset system (including the midstream energy assets of our equity method investees) provides services to producers and consumers of natural gas, NGLs, crude oil and certain petrochemicals. In general, hydrocarbons enter our asset system in a number of ways, such as an offshore natural gas or crude oil pipeline, an offshore platform, a natural gas processing plant, an onshore natural gas gathering pipeline, an NGL fractionator, an NGL storage facility, or an NGL transportation or distribution pipeline.

 

Many of our equity investees are included within our integrated midstream asset system. For example, we have ownership interests in several offshore natural gas and crude oil pipelines. Other examples include our use of the Promix NGL fractionator to process mixed NGLs extracted by our gas plants. The fractionated NGLs we receive from Promix can then be sold in our NGL marketing activities. Given the integral nature of our equity method investees to our operations, we believe the presentation of earnings from such investees as a component of gross operating margin and operating income is meaningful and appropriate.


Historically, substantially all of our consolidated revenues were earned in the United States and derived from a wide customer base. The majority of our plant-based operations are located in Texas, Louisiana, Mississippi, New Mexico and Wyoming. Our natural gas, NGL and crude oil pipelines are located in a number of regions of the United States including (i) the Gulf of Mexico offshore Texas and

 

26

 


 

Louisiana; (ii) the south and southeastern United States (primarily in Texas, Louisiana, Mississippi and Alabama); and (iii) certain regions of the central and western United States, including the Rocky Mountains. Our marketing activities are headquartered in Houston, Texas and serve customers in a number of regions of the United States including the Gulf Coast, West Coast and Mid-Continent areas.

 

Consolidated property, plant and equipment and investments in and advances to unconsolidated affiliates are assigned to each segment on the basis of each asset’s or investment’s principal operations. The principal reconciling difference between consolidated property, plant and equipment and the total value of segment assets is construction-in-progress. Segment assets represent the net book carrying value of facilities and other assets that contribute to gross operating margin of that particular segment. Since assets under construction generally do not contribute to segment gross operating margin, such assets are excluded from segment asset totals until they are placed in service. Consolidated intangible assets and goodwill are assigned to each segment based on the classification of the assets to which they relate.

 

We consolidate the financial statements of Duncan Energy Partners with those of our own. As a result, our consolidated gross operating margin amounts include the gross operating margin amounts of Duncan Energy Partners on a 100% basis.

 

The following table presents our measurement of total segment gross operating margin for the periods indicated:

 

 

 

For the Three Months

For the Six Months

 

 

Ended June 30,

Ended June 30,

 

 

2007

2006

2007

2006

Revenues (1)

$  4,212,806

$  3,517,853

$  7,535,660

$  6,767,927

Less:

Operating costs and expenses (1)

(3,960,672)

(3,323,585)

(7,085,151)

(6,370,448)

Add:

Equity in income (loss) of unconsolidated affiliates (1)

(6,211)

8,012

(32)

12,041

 

Depreciation, amortization and accretion in operating costs and expenses (2)

121,161

107,952

240,653

212,768

 

Operating lease expense paid by EPCO (2)

527

528

1,053

1,056

 

Loss (gain) on sale of assets in operating costs and expenses (2)

5,737

(136)

5,664

(197)

Total segment gross operating margin

$     373,348

$     310,624

$     697,847

$     623,147

 

 

 

 

 

 

(1)   These amounts are taken from our Unaudited Condensed Statements of Consolidated Operations.

(2)   These non-cash expenses are taken from the operating activities section of our Unaudited Condensed Statements of Consolidated Cash Flows.

 

A reconciliation of our total segment gross operating margin to operating income and income before provision for income taxes, minority interest and the cumulative effect of change in accounting principle follows:

 

 

 

For the Three Months

For the Six Months

 

 

Ended June 30,

Ended June 30,

 

 

2007

2006

2007

2006

Total segment gross operating margin

$   373,348

$   310,624

$   697,847

$   623,147

Adjustments to reconcile total segment gross operating margin

 

 

 

 

 

to operating income:

 

 

 

 

 

Depreciation, amortization and accretion in operating costs and expenses

(121,161)

(107,952)

(240,653)

(212,768)

 

Operating lease expense paid by EPCO

(527)

(528)

(1,053)

(1,056)

 

Gain (loss) on sale of assets in operating costs and expenses

(5,737)

136

(5,664)

197

 

General and administrative costs

(31,361)

(16,235)

(47,991)

(29,975)

Consolidated operating income

214,562

186,045

402,486

379,545

 

Other expense, net

(68,528)

(52,940)

(129,958)

(109,048)

Income before provision for income taxes, minority interest

 

 

 

 

 

and cumulative effect of change in accounting principle

$   146,034

$   133,105

$   272,528

$   270,497

 

27

 


 

Information by segment, together with reconciliations to our consolidated totals, is presented in the following table:

 

 

 

 

Reportable Segments

 

 

 

 

 

 

Onshore

 

 

 

 

 

 

 

NGL

Natural Gas

Offshore

 

Adjustments

 

 

 

 

Pipelines

Pipelines

Pipelines

Petrochemical

and

Consolidated

 

 

 

& Services

& Services

& Services

Services

Eliminations

Totals

Revenues from third parties:

 

 

 

 

 

 

 

 

Three months ended June 30, 2007

$ 3,022,604

$ 459,202

$ 55,130

$ 539,637

$               --

$ 4,076,573

 

 

Three months ended June 30, 2006

2,553,212

308,410

29,506

513,291

--

3,404,419

 

 

Six months ended June 30, 2007

5,387,722

875,432

88,113

983,918

--

7,335,185

 

 

Six months ended June 30, 2006

4,891,908

721,411

51,858

899,241

--

6,564,418

 

 

 

 

 

 

 

 

 

Revenues from related parties:

 

 

 

 

 

 

 

 

Three months ended June 30, 2007

66,155

69,101

977

--

--

136,233

 

 

Three months ended June 30, 2006

37,101

75,914

419

--

--

113,434

 

 

Six months ended June 30, 2007

76,058

123,103

1,305

9

--

200,475

 

 

Six months ended June 30, 2006

44,049

158,869

591

--

--

203,509

 

 

 

 

 

 

 

 

 

Intersegment and intrasegment revenues:

 

 

 

 

 

 

 

 

Three months ended June 30, 2007

1,151,803

42,917

499

123,044

(1,318,263)

--

 

 

Three months ended June 30, 2006

1,077,547

31,588

390

103,449

(1,212,974)

--

 

 

Six months ended June 30, 2007

2,274,650

61,486

1,047

228,041

(2,565,224)

--

 

 

Six months ended June 30, 2006

1,973,792

59,729

703

186,266

(2,220,490)

--

 

 

 

 

 

 

 

 

 

Total revenues:

 

 

 

 

 

 

 

 

Three months ended June 30, 2007

4,240,562

571,220

56,606

662,681

(1,318,263)

4,212,806

 

 

Three months ended June 30, 2006

3,667,860

415,912

30,315

616,740

(1,212,974)

3,517,853

 

 

Six months ended June 30, 2007

7,738,430

1,060,021

90,465

1,211,968

(2,565,224)

7,535,660

 

 

Six months ended June 30, 2006

6,909,749

940,009

53,152

1,085,507

(2,220,490)

6,767,927

 

 

 

 

 

 

 

 

 

Equity in income (loss) of unconsolidated affiliates:

 

 

 

 

 

 

 

 

Three months ended June 30, 2007

1,089

1,212

(8,846)

334

--

(6,211)

 

 

Three months ended June 30, 2006

1,924

904

4,769

415

--

8,012

 

 

Six months ended June 30, 2007

1,680

2,241

(4,771)

818

--

(32)

 

 

Six months ended June 30, 2006

3,442

1,506

6,703

390

--

12,041

 

 

 

 

 

 

 

 

 

Gross operating margin by individual

 

 

 

 

 

 

 

business segment and in total:

 

 

 

 

 

 

 

 

Three months ended June 30, 2007

208,805

83,163

31,046

50,334

--

373,348

 

 

Three months ended June 30, 2006

146,414

86,651

20,515

57,044

--

310,624

 

 

Six months ended June 30, 2007

399,499

159,678

50,753

87,917

--

697,847

 

 

Six months ended June 30, 2006

317,364

183,454

37,767

84,562

--

623,147

 

 

 

 

 

 

 

 

 

Segment assets:

 

 

 

 

 

 

 

 

At June 30, 2007

3,690,731

3,684,425

1,169,248

557,478

1,632,248

10,734,130

 

 

At December 31, 2006

3,249,486

3,611,974

734,659

502,345

1,734,083

9,832,547

 

 

 

 

 

 

 

 

 

Investments in and advances

 

 

 

 

 

 

 

to unconsolidated affiliates (see Note 7):

 

 

 

 

 

 

 

 

At June 30, 2007

122,488

204,290

491,188

18,125

--

836,091

 

 

At December 31, 2006

111,229

124,591

310,136

18,603

--

564,559

 

 

 

 

 

 

 

 

 

Intangible Assets (see Note 8):

 

 

 

 

 

 

 

 

At June 30, 2007

391,448

369,940

142,388

46,484

--

950,260

 

 

At December 31, 2006

417,950

386,149

152,376

47,480

--

1,003,955

 

 

 

 

 

 

 

 

 

Goodwill (see Note 8):

 

 

 

 

 

 

 

 

At June 30, 2007

152,701

282,121

82,135

73,690

--

590,647

 

 

At December 31, 2006

152,595

282,121

82,135

73,690

--

590,541

 

28

 


 

The following table summarizes the contribution to consolidated revenues from the sale of NGL, natural gas and petrochemical products for the periods indicated:

 

 

 

 

For the Three Months

For the Six Months

 

 

 

Ended June 30,

Ended June 30,

 

 

 

2007

2006

2007

2006

NGL Pipelines & Services:

 

 

 

 

Sale of NGL products

 

$ 2,923,058

$ 2,423,219

$ 5,114,682

$ 4,615,235

Percent of consolidated revenues

69%

69%

68%

68%

Onshore Natural Gas Pipelines & Services:

 

 

 

 

Sale of natural gas

 

422,722

268,601

783,753

636,145

Percent of consolidated revenues

10%

8%

10%

9%

Petrochemical Services:

 

 

 

 

Sale of petrochemical products

436,309

396,439

824,061

739,789

Percent of consolidated revenues

10%

11%

11%

11%

 

 

Note 12. Related Party Transactions

 

The following table summarizes our related party transactions for the periods indicated:

 

 

 

For the Three Months

For the Six Months

 

 

Ended June 30,

Ended June 30,

 

 

2007

2006

2007

2006

Revenues from consolidated operations:

 

 

 

 

 

EPCO and affiliates

$     64,127

$     33,448

$     72,669

$     39,080

 

Unconsolidated affiliates

72,106

79,986

127,806

164,429

 

Total

$   136,233

$   113,434

$   200,475

$   203,509

Operating costs and expenses:

 

 

 

 

 

EPCO and affiliates

$     74,681

$     71,105

$   153,354

$   166,062

 

Unconsolidated affiliates

10,941

7,904

16,214

14,590

 

Total

$     85,622

$     79,009

$   169,568

$   180,652

General and administrative costs:

 

 

 

 

 

EPCO and affiliates

$     20,733

$     10,830

$     33,788

$     21,838

 

Relationship with EPCO and affiliates

 

We have an extensive and ongoing relationship with EPCO and its affiliates, which include the following significant entities that are not part of our consolidated group of companies:

 

 

§

EPCO and its private company subsidiaries;

 

§

Enterprise Products GP, our sole general partner;

 

§

Enterprise GP Holdings, which owns and controls our general partner;

 

§

TEPPCO and TEPPCO GP, which are controlled by Enterprise GP Holdings ; and

 

§

the Employee Partnerships.


We also have an ongoing relationship with Duncan Energy Partners, the financial statements of which are consolidated with those of our own. Our transactions with Duncan Energy Partners are eliminated in consolidation; therefore, they are not part of the totals presented in the preceding table. A description of our relationship with Duncan Energy Partners is presented within this Note 12.

 

Unless noted otherwise, our agreements with EPCO are not the result of arm’s length transactions. As a result, we cannot provide assurance that the terms and provisions of such agreements are at least as favorable to us as we could have obtained from unaffiliated third parties.

 

EPCO is a private company controlled by Dan L. Duncan, who is also a director and Chairman of Enterprise Products GP, our general partner. At June 30, 2007, EPCO and its affiliates beneficially owned 146,317,198 (or 33.7%) of our outstanding common units, which include 13,454,498 of our common units

 

29

 


 

owned by Enterprise GP Holdings. In addition, at June 30, 2007, EPCO and its affiliates beneficially owned 90.1% of the limited partner interests of Enterprise GP Holdings and 100% of its general partner, EPE Holdings. Enterprise GP Holdings owns all of the membership interests of Enterprise Products GP. The principal business activity of Enterprise Products GP is to act as our managing partner. The executive officers and certain of the directors of Enterprise Products GP and EPE Holdings are employees of EPCO.

 

In connection with its general partner interest in us, Enterprise Products GP received cash distributions of $59.9 million and $47.3 million from us during the six months ended June 30, 2007 and 2006, respectively. These amounts include incentive distributions of $51.6 million and $40.1 million for the six months ended June 30, 2007 and 2006, respectively.

 

We and Enterprise Products GP are both separate legal entities apart from each other and apart from EPCO, Enterprise GP Holdings and their respective other affiliates, with assets and liabilities that are separate from those of EPCO, Enterprise GP Holdings and their respective other affiliates. EPCO and its private company subsidiaries depend on the cash distributions they receive from us, Enterprise GP Holdings and other investments to fund their other operations and to meet their debt obligations. Enterprise GP Holdings, EPCO and its private company affiliates received $185.8 million and $163.4 million in cash distributions from us during the six months ended June 30, 2007 and 2006, respectively.

 

The ownership interests in us that are owned or controlled by Enterprise GP Holdings are pledged as security under its credit facility. In addition, substantially all of the ownership interests in us that are owned or controlled by EPCO and its affiliates, other than those interests owned by Enterprise GP Holdings, Dan Duncan LLC and certain trusts affiliated with Dan L. Duncan, are pledged as security under the credit facility of a private company affiliate of EPCO. This credit facility contains customary and other events of default relating to EPCO and certain affiliates, including Enterprise GP Holdings, us and TEPPCO.

 

We have entered into an agreement with an affiliate of EPCO to provide trucking services to us for the transportation of NGLs and other products. We also lease office space in various buildings from affiliates of EPCO. The rental rates in these lease agreements approximate market rates.

 

Historically, we entered into transactions with a Canadian affiliate of EPCO for the purchase and sale of NGL products in the normal course of business. These transactions were at market-related prices. We acquired this affiliate in October 2006 and began consolidating its financial statements with those of our own from the date of acquisition.

 

Relationship with TEPPCO

 

We received $21.6 million and $11.5 million from TEPPCO during the three months ended June 30, 2007 and 2006, respectively, primarily from the sale of NGLs. We received $30.1 million and $17.0 million from TEPPCO during the six months ended June 30, 2007 and 2006, respectively, primarily from the sale of NGLs. We paid TEPPCO $2.8 million and $6.2 million for NGL pipeline transportation and storage services during the three months ended June 30, 2007 and 2006, respectively. We paid TEPPCO $9.3 million and $10.6 million for NGL pipeline transportation and storage services during the six months ended June 30, 2007 and 2006, respectively.

 

Purchase and lease of pipelines for DEP South Texas NGL Pipeline System from TEPPCO. In January 2007, we purchased a 10-mile segment of pipeline from TEPPCO located in the Houston area for $8.0 million that is part of the DEP South Texas NGL Pipeline System. In addition, we entered into a lease with TEPPCO for an 11-mile interconnecting pipeline located in the Houston area. The primary term of this lease expires in September 2007, and will continue on a month-to-month basis subject to termination by either party upon 60 days notice. This pipeline is being leased by a subsidiary of Duncan Energy Partners in connection with operations on its DEP South Texas NGL Pipeline System until construction of a parallel pipeline is completed in December 2007.

 

30

 


 

Jonah Joint Venture with TEPPCO. In August 2006, we formed a joint venture with TEPPCO to be partners in TEPPCO’s Jonah Gas Gathering Company, or Jonah. Jonah owns the Jonah Gas Gathering System (the “Jonah Gathering System”), located in the Greater Green River Basin of southwestern Wyoming. The Jonah Gathering System gathers and transports natural gas produced from the Jonah and Pinedale fields to regional natural gas processing plants and major interstate pipelines that deliver natural gas to end-user markets.

 

Prior to entering into the Jonah joint venture, we managed the construction of the Phase V expansion and funded the initial construction costs under a letter of intent we signed in February 2006. In connection with the joint venture arrangement, we and TEPPCO will continue the Phase V expansion, which is expected to increase the capacity of the Jonah Gathering System from 1.5 Bcf/d to 2.3 Bcf/d. The Phase V expansion is also expected to significantly reduce system operating pressures, which we anticipate will lead to increased production rates and ultimate reserve recoveries. The first portion of the expansion, which is expected to increase the system gathering capacity to 2.0 Bcf/d, was completed in July 2007. The second portion of the expansion is expected to be completed by the first quarter of 2008. We will operate the Jonah Gathering System.

 

We manage the Phase V construction project. TEPPCO is entitled to all distributions from the joint venture until specified milestones are achieved, at which point, we will be entitled to receive 50% of the incremental cash flow from portions of the system placed in service as part of the expansion. After subsequent milestones are achieved, we and TEPPCO will share distributions based on a formula that takes into account the respective capital contributions of the parties, including expenditures by TEPPCO prior to the expansion.

 

Since August 1, 2006, we and TEPPCO equally share in the construction costs of the Phase V expansion. TEPPCO has reimbursed us $176.0 million for its share of the Phase V costs. At June 30, 2007, we had a receivable from TEPPCO of $10.9 million for additional Phase V costs incurred through June 30, 2007.

 

Upon completion of the expansion project and based on the formula in the joint venture partnership agreement, we expect to own an interest in Jonah of approximately 20%, with TEPPCO owning the remaining 80%. At June 30, 2007, we and TEPPCO owned an approximate 19.6% interest and 80.4% interest, respectively, in Jonah. For the six months ended June 30, 2007, our earnings sharing ratio in Jonah was 4.7% compared to TEPPCO’s 95.3%.

 

The joint venture is governed by a management committee comprised of two representatives approved by us and two representatives appointed by TEPPCO, each with equal voting power. After an in-depth consideration of all relevant factors, this transaction was approved by the Audit, Conflicts and Governance Committee of our general partner and that of TEPPCO GP.

 

EPCO Administrative Services Agreement

 

We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”). We and our general partner, Enterprise GP Holdings and its general partner, Duncan Energy Partners and its general partner, and TEPPCO and its general partner, among other affiliates, are parties to the ASA.

 

Under the ASA, we reimburse EPCO for all costs and expenses it incurs in providing management, administrative and operating services to us. The ASA also addresses potential conflicts that may arise among us, Enterprise GP Holdings, Duncan Energy Partners and other affiliates of EPCO.

 

31

 


 

Relationship with Duncan Energy Partners

 

For financial reporting purposes, we consolidate the financial statements of Duncan Energy Partners with those of our own and reflect its operations in our business segments. All intercompany transactions between us and Duncan Energy Partners are eliminated in the preparation of our consolidated financial statements. Also, due to common control of the entities by Dan L. Duncan, the initial consolidated balance sheet of Duncan Energy Partners reflects our historical carrying basis in each of the subsidiaries contributed to Duncan Energy Partners. Public ownership of Duncan Energy Partners’ net assets and earnings are presented as a component of minority interest in our consolidated financial statements.

 

The borrowings of Duncan Energy Partners are presented as part of our consolidated debt; however, we do not have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.

 

On February 5, 2007, Duncan Energy Partners completed its initial public offering of 14,950,000 common units (including an overallotment amount of 1,950,000 common units) at $21.00 per unit, which generated net proceeds to Duncan Energy Partners of $291.9 million. As consideration for assets contributed and reimbursement for capital expenditures related to these assets, Duncan Energy Partners distributed $260.6 million of these net proceeds to us along with $198.9 million in borrowings under its credit facility and a final amount of 5,351,571 common units of Duncan Energy Partners. Duncan Energy Partners used $38.5 million of net proceeds from the overallotment to redeem 1,950,000 of the 7,301,571 common units it had originally issued to Enterprise Products Partners, resulting in the final amount of 5,351,571 common units beneficially owned by Enterprise Products Partners. We used the cash received from Duncan Energy Partners to temporarily reduce amounts outstanding under EPO’s Multi-Year Revolving Credit Facility.

 

We contributed 66% of our equity interests in the following subsidiaries to Duncan Energy Partners:

 

 

§

Mont Belvieu Caverns, LLC (“Mont Belvieu Caverns”), a recently formed subsidiary, which owns salt dome storage caverns located in Mont Belvieu, Texas that receive, store and deliver NGLs and certain petrochemical products for industrial customers located along the upper Texas Gulf Coast, which has the largest concentration of petrochemical plants and refineries in the United States;

 

 

§

Acadian Gas, LLC (“Acadian Gas”), which owns an onshore natural gas pipeline system that gathers, transports, stores and markets natural gas in Louisiana. The Acadian Gas system links natural gas supplies from onshore and offshore Gulf of Mexico developments (including offshore pipelines, continental shelf and deepwater production) with local gas distribution companies, electric generation plants and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River corridor. A subsidiary of Acadian Gas owns our 49.5% equity interest in Evangeline;

 

 

§

Sabine Propylene Pipeline L.P. (“Sabine Propylene”), which transports polymer-grade propylene between Port Arthur, Texas and a pipeline interconnect located in Cameron Parish, Louisiana;

 

 

§

Enterprise Lou-Tex Propylene Pipeline L.P. (“Lou-Tex Propylene”), which transports chemical-grade propylene from Sorrento, Louisiana to Mont Belvieu, Texas; and

 

 

§

South Texas NGL Pipelines, LLC (“South Texas NGL”), a recently formed subsidiary, which began transporting NGLs from Corpus Christi, Texas to Mont Belvieu, Texas in January 2007. South Texas NGL owns the DEP South Texas NGL Pipeline System.

 

In addition to the 34% direct ownership interest we retained in such entities, we also own the 2% general partner interest in Duncan Energy Partners and 26.4% of Duncan Energy Partners’ outstanding common units at June 30, 2007. Accordingly, we have in effect retained a net economic interest in Duncan Energy Partners’ of approximately 52.7% as of June 30, 2007. EPO directs the business operations of

 

32

 


 

Duncan Energy Partners indirectly through its ownership and control of the general partner of Duncan Energy Partners.

 

We have significant involvement with all of the subsidiaries of Duncan Energy Partners, including the following types of transactions:

 

 

§

We utilize storage services provided by Mont Belvieu Caverns to support our Mont Belvieu fractionation and other businesses;

 

 

§

We buy natural gas from and sell natural gas to Acadian Gas in connection with its normal business activities; and

 

 

§

We are currently the sole shipper on the DEP South Texas NGL Pipeline System.

 

We may contribute or sell other equity interests in our subsidiaries to Duncan Energy Partners and use the proceeds we receive from Duncan Energy Partners to fund our capital spending program. We have no obligation or commitment to make such contributions or sales to Duncan Energy Partners.

 

Relationship with Energy Transfer Equity

 

Enterprise GP Holdings acquired equity method investments in Energy Transfer Equity and its general partner in May 2007. As a result, Energy Transfer Equity and its consolidated subsidiaries became related parties to our consolidated businesses.

 

For the two months ended June 30, 2007, we recorded $42.6 million of revenues from Energy Transfer Partners, L.P. (“ETP”), primarily from NGL marketing activities, and incurred $5.8 million in operating costs and expenses. We have a long-term revenue generating contract with Titan Energy Partners, L.P. (“Titan”), a consolidated subsidiary of ETP. Titan purchases substantially all of its propane requirements from us. The contract continues until March 31, 2010 and contains renewal and extension options. We and Energy Transfer Company (“ETC OLP”) transport natural gas on each other’s systems and share operating expenses on certain pipelines. ETC OLP also sells natural gas to us.

 

Relationships with Unconsolidated Affiliates

 

Our significant related party revenue and expense transactions with unconsolidated affiliates consist of the sale of natural gas to Evangeline and the purchase of NGL storage, transportation and fractionation services from Promix. In addition, we sell natural gas to Promix and process natural gas at VESCO. For additional information regarding our unconsolidated affiliates, see Note 7.

 

See “Relationship with TEPPCO” within this Note 12 for a description of ongoing transactions involving our Jonah joint venture with TEPPCO.

 

 



 

33

 


 

Note 13. Earnings Per Unit

 

Basic earnings per unit is computed by dividing net income or loss allocated to limited partner interests by the weighted-average number of distribution-bearing units outstanding during a period. Diluted earnings per unit is computed by dividing net income or loss allocated to limited partner interests by the sum of (i) the weighted-average number of distribution-bearing units outstanding during a period (as used in determining basic earnings per unit); (ii) the weighted-average number of performance-based phantom units outstanding during a period; and (iii) the number of incremental common units resulting from the assumed exercise of dilutive unit options outstanding during a period (the “incremental option units”).

 

In a period of net operating losses, restricted units, phantom units and incremental option units are excluded from the calculation of diluted earnings per unit due to their antidilutive effect. The dilutive incremental option units are calculated using the treasury stock method, which assumes that proceeds from the exercise of all in-the-money options at the end of each period are used to repurchase common units at an average market value during the period. The amount of common units remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities.

 

The amount of net income or loss allocated to limited partner interests is net of our general partner’s share of such earnings. The following table presents the allocation of net income to Enterprise Products GP for the periods indicated:

 

 

 

For the Three Months

For the Six Months

 

 

Ended June 30,

Ended June 30,

 

 

2007

2006

2007

2006

 

 

 

 

 

 

Net income

$   142,154

$   126,295

$   254,199

$   260,072

Less incentive earnings allocations to Enterprise Products GP

(26,310)

(20,997)

(51,570)

(40,112)

Net income available after incentive earnings allocation

115,844

105,298

202,629

219,960

Multiplied by Enterprise Products GP ownership interest

2.0%

2.0%

2.0%

2.0%

Standard earnings allocation to Enterprise Products GP

$       2,317

$       2,106

$       4,053

$       4,399

 

 

 

 

 

 

Incentive earnings allocation to Enterprise Products GP

$     26,310

$     20,997

$     51,570

$     40,112

Standard earnings allocation to Enterprise Products GP

2,317

2,106

4,053

4,399

Enterprise Products GP interest in net income

$     28,627

$     23,103

$     55,623

$     44,511

 

 

 

 

 

 

 

34

 


 

The following table presents our calculation of basic and diluted earnings per unit for the periods indicated:

 

 

 

For the Three Months

For the Six Months

 

 

Ended June 30,

Ended June 30,

 

 

2007

2006

2007

2006

Income before change in accounting principle

 

 

 

 

and Enterprise Products GP interest

$    142,154

$    126,295

$    254,199

$    258,597

Cumulative effect of change in accounting principle

--

--

--

1,475

Net income

142,154

126,295

254,199

260,072

Enterprise Products GP interest in net income

(28,627)

(23,103)

(55,623)

(44,511)

Net income available to limited partners

$    113,527

$    103,192

$    198,576

$    215,561

BASIC EARNINGS PER UNIT

 

 

 

 

Numerator

 

 

 

 

 

Income before change in accounting principle

 

 

 

 

 

and Enterprise Products GP interest

$    142,154

$    126,295

$    254,199

$    258,597

 

Cumulative effect of change in accounting principle

--

--

--

1,475

 

Enterprise Products GP interest in net income

(28,627)

(23,103)

(55,623)

(44,511)

 

Limited partners’ interest in net income

$    113,527

$    103,192

$    198,576

$    215,561

Denominator

 

 

 

 

 

Common units

432,213

408,275

431,925

401,820

 

Time-vested restricted units

1,329

968

1,220

862

 

Total

433,542

409,243

433,145

402,682

Basic earnings per unit

 

 

 

 

 

Income before change in accounting principle

 

 

 

 

 

and Enterprise Products GP interest

$          0.33

$          0.31

$          0.59

$          0.64

 

Cumulative effect of change in accounting principle

--

--

--

0.01

 

Enterprise Products GP interest in net income

(0.07)

(0.06)

(0.13)

(0.11)

 

Limited partners’ interest in net income

$          0.26

$          0.25

$          0.46

$          0.54

DILUTED EARNINGS PER UNIT

 

 

 

 

Numerator

 

 

 

 

 

Income before change in accounting principle

 

 

 

 

 

and Enterprise Products GP interest

$    142,154

$    126,295

$    254,199

$    258,597

 

Cumulative effect of change in accounting principle

--

--

--

1,475

 

Enterprise Products GP interest in net income

(28,627)

(23,103)

(55,623)

(44,511)

 

Limited partners’ interest in net income

$    113,527

$    103,192

$    198,576

$    215,561

Denominator

 

 

 

 

 

Common units

432,213

408,275

431,925

401,820

 

Time-vested restricted units

1,329

968

1,220

862

 

Performance-based restricted units

9

27

9

27

 

Incremental option units

576

234

547

241

 

Total

434,127

409,504

433,701

402,950

Diluted earnings per unit

 

 

 

 

 

Income before change in accounting principle

 

 

 

 

 

and Enterprise Products GP interest

$          0.33

$          0.31

$          0.59

$          0.64

 

Cumulative effect of change in accounting principle

--

--

--

0.01

 

Enterprise Products GP interest in net income

(0.07)

(0.06)

(0.13)

(0.11)

 

Limited partners’ interest in net income

$          0.26

$          0.25

$          0.46

$          0.54

 


Note 14. Commitments and Contingencies

 

Litigation

 

On occasion, we are named as a defendant in litigation relating to our normal business activities, including regulatory and environmental matters. Although we are insured against various business risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings as a result of our ordinary business activities. We are unaware of any significant litigation, pending or

 

35

 


 

threatened, that could have a significant adverse effect on our financial position, cash flows or results of operations.

 

On September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed a complaint in the Court of Chancery of New Castle County in the State of Delaware, in his individual capacity, as a putative class action on behalf of other unitholders of TEPPCO, and derivatively on behalf of TEPPCO, concerning, among other things, certain transactions involving TEPPCO and us or our affiliates.  Mr. Brinkerhoff filed an amended complaint on July 12, 2007. The amended complaint names as defendants (i) TEPPCO, its current and certain former directors, and certain of its affiliates; (ii) us and certain of our affiliates; (iii) EPCO, Inc.; and (iv) Dan L. Duncan. 

 

The amended complaint alleges, among other things, that the defendants have caused TEPPCO to enter into certain transactions with us or our affiliates that were unfair to TEPPCO or otherwise unfairly favored us or our affiliates over TEPPCO.  These transactions are alleged to include the joint venture to further expand the Jonah Gathering System entered into by TEPPCO and one of our affiliates in August 2006 and the sale by TEPPCO to one of our affiliates of the Pioneer gas processing plant in March 2006. The amended complaint seeks (i) rescission of these transactions or an award of rescissory damages with respect thereto; (ii) damages for profits and special benefits allegedly obtained by defendants as a result of the alleged wrongdoings in the amended complaint; and (iii) awarding plaintiff costs of the action, including fees and expenses of his attorneys and experts. We believe this lawsuit is without merit and intend to vigorously defend against it. See Note 12 for additional information regarding our relationship with TEPPCO.

 

On February 13, 2007, EPO received notice from the U.S. Department of Justice (“DOJ”) that it was the subject of a criminal investigation related to an ammonia release in Kingman County, Kansas on October 27, 2004 from a pressurized anhydrous ammonia pipeline owned by a third party, Magellan Ammonia Pipeline, L.P. (“Magellan”). EPO is the operator of this pipeline. On February 14, 2007, EPO received a letter from the Environment and Natural Resources Division (“ENRD”) of the DOJ regarding this incident and a previous release of ammonia on September 27, 2004 from the same pipeline.  The ENRD has indicated that it may pursue civil damages against EPO and Magellan as a result of these incidents.  Based on this correspondence from the ENRD, the statutory maximum amount of civil fines that could be assessed against EPO and Magellan is up to $17.4 million in the aggregate. EPO is cooperating with the DOJ and is pursuing a resolution acceptable to all parties.  EPO is seeking defense and indemnity under the pipeline operating agreement between it and Magellan. At this time, we do not believe that a final resolution of either the criminal investigation by the DOJ or the civil claims by the ENRD will have a material impact on our consolidated financial position, results of operations or cash flows.

 

On October 25, 2006, a rupture in the Magellan Ammonia Pipeline resulted in the release of ammonia near Clay Center, Kansas. The pipeline has been repaired and environmental remediation tasks related to this incident have been completed. At this time, we do not believe that this incident will have a material impact on our consolidated financial position, results of operations or cash flows.

 

Several lawsuits have been filed by municipalities and other water suppliers against a number of manufacturers of reformulated gasoline containing methyl tertiary butyl ether. In general, such suits have not named manufacturers of this product as defendants, and there have been no such lawsuits filed against our subsidiary that owns an octane-additive production facility. It is possible, however, that former manufacturers such as our subsidiary could ultimately be added as defendants in such lawsuits or in new lawsuits.

 

Operating Leases

 

We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Our significant lease agreements involve (i) the lease of underground caverns for the storage of natural gas and NGLs, (ii) leased office space with an affiliate of EPCO, and (iii) land held pursuant to right-of-way agreements. In general, our material lease agreements have original terms that range from 14 to 20 years and include renewal options that could extend the agreements for up to an additional 20 years.

 

36

 


 

Lease expense is charged to operating costs and expenses on a straight line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred.

 

There have been no material changes in our operating lease commitments since December 31, 2006, except for the commitments associated with a new natural gas storage lease. In order to provide firm natural gas transportation and storage services under long-term agreements with CenterPoint Energy Resources Corp. (“CenterPoint Energy”) in Houston, Texas, we entered into a 2-year agreement during the second quarter of 2007 for firm natural gas storage capacity in Texas. Our rental payments under the lease are at a fixed rate. Contingent rental payments are based upon the actual volume of natural gas we inject or withdrawal from the storage cavern over the term of the lease agreement. The incremental future minimum lease payments associated with our new natural gas storage lease are $3.7 million in 2007, $4.9 million in 2008 and $1.2 million in 2009. CenterPoint Energy will reimburse us for the costs we incur associated with this natural gas storage lease.

 

Lease and rental expense included in operating costs and expenses was $11.8 million and $10.0 million during the three months ended June 30, 2007 and 2006, respectively. For the six months ended June 30, 2007 and 2006, lease and rental expense included in operating costs and expenses was $19.9 million and $19.7 million, respectively.

 

Contractual Obligations

 

With the exception of the debt incurred by Duncan Energy Partners in connection with its initial public offering and the issuance of Junior Notes B by EPO, there have been no significant changes in our consolidated scheduled maturities of long-term debt since those reported in our annual report on Form 10-K for the year ended December 31, 2006. See Note 9 for additional information regarding the debt obligations of Duncan Energy Partners and the issuance of Junior Notes B.

 

Performance Guaranty

 

In December 2004, a subsidiary of ours entered into the Independence Hub Agreement with six oil and natural gas producers. We guaranteed to the producers the construction-related performance of our subsidiary up to an amount of $340.8 million. The performance guaranty expired during the second quarter of 2007.

 

Other Claims

 

As part of our normal business activities with joint venture partners and certain customers and suppliers, we occasionally make claims against such parties or have claims made against us as a result of disputes related to contractual agreements or similar arrangements. As of June 30, 2007, our contingent claims against such parties were approximately $1.9 million and claims against us were approximately $33.8 million. These matters are in various stages of assessment and the ultimate outcome of such disputes cannot be reasonably estimated. However, in our opinion, the likelihood of a material adverse outcome related to disputes against us is remote. Accordingly, accruals for loss contingencies related to these matters, if any, that might result from the resolution of such disputes have not been reflected in our consolidated financial statements.

 


Note 15. Significant Risks and Uncertainties – Weather-Related Risks

 

The following is a discussion of the general status of our insurance claims related to recent significant storm events. To the extent we include any estimate or range of estimates regarding the dollar value of damages, please be aware that a change in our estimates may occur as additional information becomes available. To the extent we receive nonrefundable cash proceeds from business interruption insurance claims, they are recorded as revenue in our Unaudited Condensed Statements of Consolidated Operations in the period of receipt.

 

37

 


 

Hurricane Ivan insurance claims. We have submitted business interruption insurance claims for our estimated losses caused by Hurricane Ivan, which struck the eastern U.S. Gulf Coast region in September 2004. We are continuing our efforts to collect residual balances and expect to complete the process during 2007.

 

Hurricanes Katrina and Rita insurance claims. Hurricanes Katrina and Rita, both significant storms, affected certain of our Gulf Coast assets in August and September of 2005, respectively. We continue to pursue collection of our property damage and business interruption claims related to Hurricanes Katrina and Rita.

 

The following table summarizes the proceeds we received for the three and six months ended June 30, 2007 and 2006 from business interruption and property damage insurance claims with respect to certain named storms:

 

 

For the Three Months

For the Six Months

 

Ended June 30,

Ended June 30,

 

2007

2006

2007

2006

Business interruption proceeds:

 

 

 

 

 

Hurricane Ivan

$           --

$     2,021

$        377

$   12,226

 

Hurricane Katrina

13,199

--

13,199

--

 

Hurricane Rita

8,258

--

8,258

--

 

Other

--

--

996

--

 

Total proceeds

21,457

2,021

22,830

12,226

Property damage proceeds:

 

 

 

 

 

Hurricane Ivan

204

--

1,273

24,104

 

Hurricane Katrina

6,563

--

6,563

--

 

Other

--

--

184

--

 

Total proceeds

6,767

--

8,020

24,104

 

Total

$   28,224

$     2,021

$   30,850

$   36,330

 

 

Note 16. Supplemental Cash Flow Information

 

Our Unaudited Condensed Statements of Consolidated Cash Flows are prepared using the indirect method. The indirect method derives net cash flows from operating activities by adjusting net income to remove (i) the effects of all deferrals of past operating cash receipts and payments, such as changes during the period in inventory, deferred income and similar transactions, (ii) the effects of all accruals of expected future operating cash receipts and cash payments, such as changes during the period in receivables and payables, (iii) the effects of all items classified as investing or financing cash flows, such as gains or losses on sale of property, plant and equipment or extinguishment of debt, and (iv) other non-cash amounts such as depreciation, amortization and changes in the fair market value of financial instruments.

 

 



38

 


 

The net effect of changes in operating assets and liabilities is as follows for the periods indicated:

 

 

 

For the Six Months

 

 

Ended June 30,

 

 

2007

2006

Decrease (increase) in:

 

 

 

Accounts and notes receivable

$    (272,644)

$    117,826

 

Inventories

1,580

(111,631)

 

Prepaid and other current assets

(43,145)

(48,347)

 

Other assets

3,308

7,601

Increase (decrease) in:

 

 

 

Accounts payable

33,418

12,898

 

Accrued gas payable

187,642

19,402

 

Accrued expenses

98,219

35,911

 

Accrued interest

3,972

(1,248)

 

Other current liabilities

(16,937)

45,843

 

Other long-term liabilities

362

(3,563)

Net effect of changes in operating accounts

$        (4,225)

$      74,692

 

Third parties may be obligated to reimburse us for all or a portion of expenditures on certain of our capital projects. The majority of such arrangements are associated with projects related to pipeline construction and production well tie-ins. We received $48.6 million and $34.9 million as contributions in aid of our construction costs during the six months ended June 30, 2007 and 2006, respectively.

 


Note 17. Condensed Financial Information of EPO

 

EPO conducts substantially all of our business. Currently, we have no independent operations and no material assets outside those of EPO. EPO consolidates the financial statements of Duncan Energy Partners with those of its own.

 

We guarantee the consolidated debt obligations of EPO with the exception of the Dixie revolving credit facility, Duncan Energy Partners’ credit facility and the senior subordinated notes assumed in connection with the GulfTerra Merger. If EPO were to default on any debt we guarantee, we would be responsible for full repayment of that obligation. See Note 9 for additional information regarding our consolidated debt obligations.

 

 

 

 

 



39

 


 

The reconciling items between our consolidated financial statements and those of EPO are insignificant. The following table presents condensed consolidated balance sheet data for EPO at the dates indicated:

 

 

 

June 30,

December 31,

 

 

2007

2006

ASSETS

 

 

Current assets

$      2,172,755

$      1,915,937

Property, plant and equipment, net

10,734,128

9,832,547

Investments in and advances to unconsolidated affiliates, net

836,091

564,559

Intangible assets, net

950,260

1,003,955

Goodwill

590,647

590,541

Deferred tax asset

2,051

1,632

Other assets

77,630

74,103

 

Total

$    15,363,562

$    13,983,274

 

 

 

 

LIABILITIES AND PARTNERS’ EQUITY

 

 

Current liabilities

$      2,203,066

$      1,986,444

Long-term debt

6,259,715

5,295,590

Other long-term liabilities

126,026

99,845

Minority interest

439,812

136,249

Partners’ equity

6,334,943

6,465,146

 

Total

$    15,363,562

$    13,983,274

 

 

 

 

Total EPO debt obligations guaranteed by us

$      6,108,881

$      5,314,000

 

The following table presents condensed consolidated statements of operations data for EPO for the periods indicated:       

 

 

For the Three Months

For the Six Months

 

Ended June 30,

Ended June 30,

 

2007

2006

2007

2006

Revenues

$   4,212,806

$   3,517,853

$   7,535,660

$   6,767,927

Costs and expenses

3,989,249

3,339,326

7,128,979

6,397,972

Equity in income (loss) of unconsolidated affiliates

(6,211)

8,012

(32)

12,041

Operating income

217,346

186,539

406,649

381,996

Other expense

(69,123)

(53,413)

(131,087)

(109,925)

Income before provision for income taxes, minority

 

 

 

 

interest and change in accounting principle

148,223

133,126

275,562

272,071

Provision for income taxes

1,845

(6,272)

(6,934)

(9,164)

Income before minority interest and change in

 

 

 

 

accounting principle

150,068

126,854

268,628

262,907

Minority interest

(5,778)

(534)

(11,521)

(2,733)

Income before change in accounting principle

144,290

126,320

257,107

260,174

Cumulative effect of change in accounting principle

--

--

--

1,475

Net income

$      144,290

$      126,320

$      257,107

$      261,649

 

 



40

 


 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

For the three and six months ended June 30, 2007 and 2006.

 

The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and our accompanying notes included under Item 1 of this quarterly report on Form 10-Q and with the information contained within our annual report on Form 10-K for the year ended December 31, 2006. Our discussion and analysis includes the following:

 

 

§

Overview of Business.

 

 

§

Results of Operations – Discusses material period-to-period variances in our Unaudited Condensed Statements of Consolidated Operations.

 

 

§

Liquidity and Capital Resources – Addresses available sources of liquidity and analyzes cash flows.

 

 

§

Critical Accounting Policies – Presents accounting policies that are among the most significant to the portrayal of our financial condition and results of operations.

 

 

§

Other Items – Includes information related to contractual obligations, off-balance sheet arrangements, related party transactions, recent accounting pronouncements and similar disclosures.

 

This discussion contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may” and similar expressions and statements regarding our plans and objectives for future operations, are intende