Item 1 of this annual report. This regulatory oversight can affect certain aspects of our business and the market for our products and could materially adversely affect our cash flows.
We are subject to strict regulations at many of our facilities regarding employee safety, and failure to comply with these regulations could adversely affect our ability to make distributions to you.
The workplaces associated with our facilities are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local governmental authorities and local residents. The failure to comply with OSHA requirements or general industry standards, keep adequate records or monitor occupational exposure to regulated substances could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to you.
Terrorist attacks aimed at our facilities could adversely affect our business, results of operations, cash flows and financial condition.
Since the September 11, 2001 terrorist attacks on the United States, the United States government has issued warnings that energy assets, including our nation’s pipeline infrastructure, may be the future target of terrorist organizations. Any terrorist attack on our facilities or pipelines or those of our customers could have a material adverse effect on our business.
We depend on the leadership and involvement of Dan L. Duncan and other key personnel for the success of our businesses.
We depend on the leadership, involvement and services of Dan L. Duncan, the founder of EPCO and the chairman of our general partner and other key personnel. Mr. Duncan has been integral to our success and the success of EPCO due in part to his ability to identify and develop business opportunities, make strategic decisions and attract and retain key personnel. The loss of his leadership and involvement or the services of certain key members of our senior management team could have a material adverse effect on our business, results of operations, cash flows, market price of our securities and financial condition.
EPCO’s employees may be subjected to conflicts in managing our business and the allocation of time and compensation costs between our business and the business of EPCO and its other affiliates.
We have no officers or employees and rely solely on officers of our general partner and employees of EPCO. Certain of our officers are also officers of EPCO and other affiliates of EPCO. These relationships may create conflicts of interest regarding corporate opportunities and other matters, and the resolution of any such conflicts may not always be in our or our unitholders’ best interests. In addition, these overlapping officers allocate their time among us, EPCO and other affiliates of EPCO. These officers face potential conflicts regarding the allocation of their time, which may adversely affect our business, results of operations and financial condition.
We have entered into an administrative services agreement that governs business opportunities among entities controlled by EPCO, which includes us and our general partner, Enterprise GP Holdings and its general partner, Duncan Energy Partners and its general partner and TEPPCO and its general partner.
For information regarding how business opportunities are handled within the EPCO group of companies, please read Item 13 of this annual report.
We do not have an independent compensation committee, and aspects of the compensation of our executive officers and other key employees, including base salary, are not reviewed or approved by our independent directors. The determination of executive officer and key employee compensation could involve conflicts of interest resulting in economically unfavorable arrangements for us.
Risks Relating to Our Partnership Structure
We may issue additional securities without the approval of our common unitholders.
At any time, we may issue an unlimited number of limited partner interests of any type (to parties other than our affiliates) without the approval of our unitholders. Our partnership agreement does not give our common unitholders the right to approve the issuance of equity securities including equity securities ranking senior to our common units. The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:
§
the ownership interest of a unitholder immediately prior to the issuance will decrease;
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the amount of cash available for distributions on each common unit may decrease;
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the ratio of taxable income to distributions may increase;
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the relative voting strength of each previously outstanding common unit may be diminished; and
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the market price of our common units may decline.
We may not have sufficient cash from operations to pay distributions at the current level following establishment of cash reserves and payments of fees and expenses, including payments to EPGP.
Because distributions on our common units are dependent on the amount of cash we generate, distributions may fluctuate based on our performance. We cannot guarantee that we will continue to pay distributions at the current level each quarter. The actual amount of cash that is available to be distributed each quarter will depend upon numerous factors, some of which are beyond our control and the control of EPGP. These factors include but are not limited to the following:
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the level of our operating costs;
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the level of competition in our business segments;
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prevailing economic conditions;
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the level of capital expenditures we make;
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the restrictions contained in our debt agreements and our debt service requirements;
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fluctuations in our working capital needs;
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the cost of acquisitions, if any; and
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the amount, if any, of cash reserves established by EPGP in its sole discretion.
In addition, you should be aware that the amount of cash we have available for distribution depends primarily on our cash flow, including cash flow from financial reserves and working capital borrowings, not solely on profitability, which is affected by non-cash items. As a result, we may make
cash distributions during periods when we record losses and we may not make distributions during periods when we record net income.
We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.
Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash reduced by any amounts of reserves for commitments and contingencies, including capital and operating costs and debt service requirements. The value of our units and other limited partner interests may decrease in correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue more equity to recapitalize.
Cost reimbursements and fees due to EPCO and its affiliates, including our general partner may be substantial and will reduce our cash available for distribution to holders of our units.
Prior to making any distribution on our units, we will reimburse EPCO and its affiliates, including officers and directors of EPGP, for all expenses they incur on our behalf, including allocated overhead. These amounts will include all costs incurred in managing and operating us, including costs for rendering administrative staff and support services to us, and overhead allocated to us by EPCO. The payment of these amounts could adversely affect our ability to pay cash distributions to holders of our units. EPCO has sole discretion to determine the amount of these expenses. In addition, EPCO and its affiliates may provide other services to us for which we will be charged fees as determined by EPCO.
EPGP and its affiliates have limited fiduciary responsibilities to, and conflicts of interest with respect to, our partnership, which may permit it to favor its own interests to your detriment.
The directors and officers of EPGP and its affiliates have duties to manage EPGP in a manner that is beneficial to its members. At the same time, EPGP has duties to manage our partnership in a manner that is beneficial to us. Therefore, EPGP’s duties to us may conflict with the duties of its officers and directors to its members. Such conflicts may include, among others, the following:
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neither our partnership agreement nor any other agreement requires EPGP or EPCO to pursue a business strategy that favors us;
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decisions of EPGP regarding the amount and timing of asset purchases and sales, cash expenditures, borrowings, issuances of additional units and reserves in any quarter may affect the level of cash available to pay quarterly distributions to unitholders and EPGP;
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under our partnership agreement, EPGP determines which costs incurred by it and its affiliates are reimbursable by us;
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EPGP is allowed to resolve any conflicts of interest involving us and EPGP and its affiliates;
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EPGP is allowed to take into account the interests of parties other than us, such as EPCO, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to unitholders;
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any resolution of a conflict of interest by EPGP not made in bad faith and that is fair and reasonable to us shall be binding on the partners and shall not be a breach of our partnership agreement;
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affiliates of EPGP, including TEPPCO, may compete with us in certain circumstances;
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EPGP has limited its liability and reduced its fiduciary duties and has also restricted the remedies available to our unitholders for actions that might, without the limitations, constitute breaches of fiduciary duty. As a result of purchasing our units, you are deemed to consent to some actions and
conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;
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we do not have any employees and we rely solely on employees of EPCO and its affiliates;
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in some instances, EPGP may cause us to borrow funds in order to permit the payment of distributions, even if the purpose or effect of the borrowing is to make incentive distributions;
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our partnership agreement does not restrict EPGP from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
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EPGP intends to limit its liability regarding our contractual and other obligations and, in some circumstances, may be entitled to be indemnified by us;
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EPGP controls the enforcement of obligations owed to us by our general partner and its affiliates; and
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EPGP decides whether to retain separate counsel, accountants or others to perform services for us.
We have significant business relationships with entities controlled by Dan L. Duncan, including EPCO and TEPPCO. For detailed information on these relationships and related transactions with these entities, see Item 13 included within this annual report.
Unitholders have limited voting rights and are not entitled to elect our general partner or its directors, which could lower the trading price of our common units. In addition, even if unitholders are dissatisfied, they cannot easily remove our general partner.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect EPGP or its directors and will have no right to elect our general partner or its directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, is chosen by the owners of the general partner and not by the unitholders.
Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have no practical ability to remove EPGP or its officers or directors. EPGP may not be removed except upon the vote of the holders of at least 60% of our outstanding units voting together as a single class. Because affiliates of EPGP currently own approximately 34.0% of our outstanding common units, the removal of EPGP as our general partner is highly unlikely without the consent of both EPGP and its affiliates. As a result of this provision, the trading price of our common units may be lower than other forms of equity ownership because of the absence or reduction of a takeover premium in the trading price.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Unitholders’ voting rights are further restricted by a provision in our partnership agreement stating that any units held by a person that owns 20% or more of any class of our common units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence the manner or direction of our management. As a result of this provision, the trading price of our common units may be lower than other forms of equity ownership because of the absence or reduction of a takeover premium in the trading price.
EPGP has a limited call right that may require common unitholders to sell their units at an undesirable time or price.
If at any time EPGP and its affiliates own 85% or more of the common units then outstanding, EPGP will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price not less than the then current market price. As a result, common unitholders may be required to sell their common units at an undesirable time or price and may therefore not receive any return on their investment. They may also incur a tax liability upon a sale of their units.
Our common unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.
Under Delaware law, common unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right of limited partners to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business.
Under Delaware law, our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those of our contractual obligations that are expressly made without recourse to our general partner.
The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business. You could have unlimited liability for our obligations if a court or government agency determined that:
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we were conducting business in a state, but had not complied with that particular state’s partnership statute; or
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your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constituted “control” of our business.
Unitholders may have liability to repay distributions.
Under certain circumstances, our unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.
Sales of a large number of our outstanding common units in the market may depress the market price of our common units.
Sales of a substantial number of our common units in the public market could cause the market price of our common units to decline. As of February 1, 2008, we had 435,241,826 common units outstanding. Sales of a substantial number of these common units in the trading markets, whether in a single transaction or series of transactions, or the possibility that these sales may occur, could reduce the
market price of our outstanding common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future.
Our general partner’s interest in us and the control of our general partner may be transferred to a third party without unitholder consent.
After June 30, 2008, our general partner, in accordance with our partnership agreement, may transfer its general partner interest without the consent of unitholders. In addition, our general partner may transfer its general partner interest to a third party in a merger or consolidation or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of Enterprise GP Holdings or its affiliates to transfer their equity interests in our general partner to a third party. The new equity owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and to influence the decisions taken by the board of directors and officers of our general partner.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to our common unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (“IRS”) on this matter.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distributions to our common unitholders would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in the after-tax return to our common unitholders, likely causing a substantial reduction in the value of our common units.
Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to a material amount of entity level taxation. In addition, because of widespread state budget deficits and other reasons, several states (including Texas) are evaluating ways to enhance state-tax collections. For example, with respect to tax reports due on or after January 1, 2008, our operating subsidiaries are subject to the Revised Texas Franchise Tax on that portion of their revenue generated in Texas. Specifically, the Revised Texas Franchise Tax is imposed at a maximum effective rate of 0.7% of the operating subsidiaries’ gross revenue that is apportioned to Texas. If any additional state were to impose an entity-level tax upon us or our operating subsidiaries, the cash available for distribution to our common unitholders would be reduced.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation, or Qualifying Income Exception, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. For
example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Section 7704(d) of the Internal Revenue Code. It is possible that these legislative efforts could result in changes to the existing U.S. tax laws that affect publicly traded partnerships, including us. Modifications to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any changes will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to successfully challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units, and the costs of any contests will be borne by our unitholders and our general partner.
The IRS may adopt positions that differ from the positions we take, even positions taken with advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which our common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will be borne indirectly by our unitholders and our general partner.
Even if our common unitholders do not receive any cash distributions from us, they will be required to pay taxes on their share of our taxable income.
Common unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive any cash distributions from us. Our common unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability which results from their share of our taxable income.
Tax gain or loss on the disposition of our common units could be different than expected.
If a common unitholder sells its common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those common units. Prior distributions to a unitholder in excess of the total net taxable income a unitholder is allocated for a common unit, which decreased the unitholder’s tax basis in that common unit, will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price the unitholder receives is less than the unitholder’s original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to a unitholder.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investments in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable
income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.
We will treat each purchaser of our common units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
Because we cannot match transferors and transferees of common units, we adopt depreciation and amortization positions that may not conform with all aspects of applicable Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a common unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the common unitholder’s tax returns.
Our common unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of an investment in our common units.
In addition to federal income taxes, our common unitholders will likely be subject to other taxes, including state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Our common unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, they may be subject to penalties for failure to comply with those requirements. We may own property or conduct business in other states or foreign countries in the future. It is the responsibility of the common unitholder to file all federal, state and local tax returns.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.
We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between EPGP and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.
When we issue additional common units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and EPGP. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and EPGP, which may be unfavorable to such unitholders. Moreover, subsequent purchasers of common units may have a greater portion of their Internal Revenue code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between EPGP and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to the unitholder’s tax returns.
Item 1B. Unresolved Staff Comments.
None.
Item 3. Legal Proceedings.
On occasion, we or our unconsolidated affiliates are named as defendants 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 threatened, that could have a significant adverse effect on our financial position, cash flows or results of operations. For detailed information regarding our legal proceedings, see Note 20 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
Item 4. Submission of Matters to a Vote of Security Holders.
There were no matters voted on by our unitholders during the fourth quarter of 2007. On January 29, 2008, we held a special meeting where our unitholders where asked to approve the terms of the Enterprise Products 2008 Long-Term Incentive Plan (the “Enterprise Products 2008 LTIP”), which provides for awards of (i) options to purchase our common units, (ii) restricted units, (iii) phantom units, (iv) distribution equivalent rights and (v) common unit appreciation rights. These awards would be available for grant to employees and consultants of EPCO, including those who provide services on our behalf, and non-employee directors of our general partner. The Enterprise Products 2008 LTIP provides for the issuance of up to 10,000,000 of our common units as awards to such individuals. The following is a summary of the votes cast by our unitholders, which approved the terms of the Enterprise Products 2008 LTIP.
PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.
Market Information and Cash Distributions
Our common units are listed on the NYSE under the ticker symbol “EPD.” As of February 1, 2008, there were approximately 904 unitholders of record of our common units. The following table presents the high and low sales prices for our common units during the periods indicated (as reported by the NYSE Composite Transaction Tape) and the amount, record date and payment date of the quarterly cash distributions we paid on each of our common units.
The quarterly cash distributions shown in the table above correspond to cash flows for the quarters indicated. The actual cash distributions (i.e., the payments made to our partners) occur within 45 days after the end of such quarter. We expect to fund our quarterly cash distributions to partners primarily with cash provided by operating activities. For additional information regarding our cash flows from operating activities, see “Liquidity and Capital Resources” included under Item 7 of this annual report. Although the payment of cash distributions is not guaranteed, we expect to continue to pay comparable cash distributions in the future.
Recent Sales of Unregistered Securities
There were no sales of unregistered equity securities during 2007.
Common Units Authorized for Issuance Under Equity Compensation Plan
See “Securities Authorized for Issuance Under Equity Compensation Plans” under Item 12 of this annual report, which is incorporated by reference into this Item 5.
Issuer Purchases of Equity Securities
We have not repurchased any of our common units since 2002. In December 1998, we announced a common unit repurchase program whereby we, together with certain affiliates, intended to repurchase up to 2,000,000 of our common units for the purpose of granting options to management and key employees (amount adjusted for the 2-for-1 unit split in May 2002). As of February 1, 2008, we and our affiliates could repurchase up to 618,400 additional common units under this repurchase program.
Item 6. Selected Financial Data.
The following table presents selected historical consolidated financial data of our partnership. This information has been derived from our audited financial statements and should be read in conjunction with the audited financial statements included under Item 8 of this annual report. In addition, information regarding our results of operations and liquidity and capital resources can be found under Item 7 of this annual report. As presented in the table, amounts are in thousands (except per unit data).
(1)
In general, our historical operating results and financial position have been affected by numerous acquisitions since 2002. Our most significant transaction to date was the GulfTerra Merger, which was completed on September 30, 2004. The aggregate value of the total consideration we paid or issued to complete the GulfTerra Merger was approximately $4 billion. We accounted for the GulfTerra Merger and our other acquisitions using purchase accounting; therefore, the operating results of these acquired entities are included in our financial results prospectively from their respective acquisition dates.
(2)
Amounts presented for the years ended December 31, 2006, 2005 and 2004 are before the cumulative effect of accounting changes.
(3)
Distributions per common unit represent declared cash distributions with respect to the four fiscal quarters of each period presented.
(4)
In general, the balances of our long-term and current maturities of debt have increased over time as a result of financing all or a portion of acquisitions and other capital spending.
(5)
We regularly issue common units through underwritten public offerings and, less frequently, in connection with acquisitions or other transactions. The increase in partners’ equity since 2003 has been the result of such transactions, with the September 2004 issuance of 104.5 million common units in connection with the GulfTerra Merger being our largest. For additional information regarding our partners’ equity and unit history, see Note 15 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
For the years ended December 31, 2007, 2006 and 2005.
The following information should be read in conjunction with our consolidated financial statements and our accompanying notes included under Item 8 of this annual report. Our discussion and analysis includes the following:
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Cautionary Note Regarding Forward-Looking Statements.
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Significant Relationships Referenced in this Discussion and Analysis.
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Overview of Business.
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Recent Developments - Discusses significant developments during the year ended December 31, 2007.
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Results of Operations - Discusses material year-to-year variances in our Statements of Consolidated Operations.
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Liquidity and Capital Resources - Addresses available sources of liquidity and capital resources and includes a discussion of our capital spending program.
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Critical Accounting Policies and Estimates.
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Other Items - Includes information related to contractual obligations, off-balance sheet arrangements, related party transactions, recent accounting pronouncements and similar disclosures.
As generally used in the energy industry and in this discussion, the identified terms have the following meanings:
/d
= per day
BBtus
= billion British thermal units
Bcf
= billion cubic feet
MBPD
= thousand barrels per day
MMBbls
= million barrels
MMBtus
= million British thermal units
MMcf
= million cubic feet
Our financial statements have been prepared in accordance with U.S generally accepted accounting principles (“GAAP”).
Cautionary Note Regarding Forward-Looking Statements
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,” “seek,” “goal,” “forecast,” “intend,” “could,” “should,” “will,” “believe,” “may,” “potential” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions as described in more detail in Item 1A
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
We are exposed to financial market risks, including changes in commodity prices, interest rates and foreign exchange 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) the 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.
We recognize financial instruments as assets and liabilities on our Consolidated Balance Sheets based on fair value. Fair value is generally defined as the amount at which a financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. The estimated fair values of our financial instruments have been determined using available market information and appropriate valuation techniques. We must use considerable judgment, however, in interpreting market data and developing these estimates. Accordingly, our fair value estimates are not necessarily indicative of the amounts that we could realize upon disposition of these instruments. The use of different market assumptions and/or estimation techniques could have a material effect on our estimates of fair value.
Changes in the fair value of financial instrument contracts are recognized currently in earnings unless specific hedge accounting criteria are met. If the financial instruments meet those criteria, the instrument’s gains and losses offset the related results of the hedged item in earnings for a fair value hedge and are deferred in other comprehensive income for a cash flow hedge. Gains and losses related to a cash flow hedge are reclassified into earnings when the forecasted transaction affects earnings. For additional information regarding our accounting for financial instruments, see Note 7 of the Notes to Consolidated Financial Statements included under Item 8
Item 8 of this annual report.
To qualify as a hedge, the item to be hedged must be exposed to commodity, interest rate or exchange rate risk and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” (as amended and interpreted). We must formally designate the financial instrument as a hedge and document and assess the effectiveness of the hedge at inception and on a quarterly basis. Any ineffectiveness of the hedge is recorded in current earnings.
We routinely review our outstanding financial instruments in light of current market conditions. If market conditions warrant, some financial instruments may be closed out in advance of their contractual settlement dates thus realizing income or loss depending on the specific hedging criteria. When this occurs, we may enter into a new financial instrument to reestablish the hedge to which the closed instrument relates.
Interest Rate Risk Hedging Program
Our interest rate exposure results from variable and fixed rate borrowings under various debt agreements. We manage a portion of our interest rate exposures 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. The following information summarizes significant components of our interest rate risk hedging portfolio:
Fair value hedges - Interest rate swaps
As summarized in the following table, we had eleven interest rate swap agreements outstanding at December 31, 2007 that were accounted for as fair value hedges.
(1)
The variable rate indicated is the all-in variable rate for the current settlement period.
We have designated these interest rate swaps as fair value hedges under SFAS 133 since they mitigate changes in the fair value of the underlying fixed rate debt. As effective fair value hedges, an increase in the fair value of these interest rate swaps is equally offset by an increase in the fair value of the underlying hedged debt. The offsetting changes in fair value have no effect on current period interest expense.
These eleven agreements have a combined notional amount of $1.1 billion and match the maturity dates of the underlying debt being hedged. Under each swap agreement, we pay the counterparty a variable interest rate based on six-month London interbank offered rate (“LIBOR”) (plus an applicable margin as defined in each swap agreement), and receive back from the counterparty a fixed interest rate payment based on the stated interest rate of the debt being hedged, with both payments calculated using the notional amounts stated in each swap agreement. We settle amounts receivable from or payable to the counterparties every six months (the “settlement period”). The settlement amount is amortized ratably to earnings as either an increase or a decrease in interest expense over the settlement period.
The total fair value of these eleven interest rate swaps at December 31, 2007, was an asset of $14.8 million, with an offsetting decrease in the fair value of the underlying debt. Interest expense for the years ended December 31, 2007, 2006 and 2005 reflects a $8.9 million loss, $5.2 million loss and $10.8 million benefit from these swap agreements, respectively.
The following table shows the effect of hypothetical price movements on the estimated fair value of our interest rate swap portfolio and the related change in fair value (“FV”) of the underlying debt at the dates indicated (dollars in thousands). Income is not affected by changes in the fair value of these swaps; however, these swaps effectively convert the hedged portion of fixed-rate debt to variable-rate debt. As a result, interest expense (and related cash outlays for debt service) will increase or decrease with the change in the periodic “reset” rate associated with the respective swap. Typically, the reset rate is an agreed upon index rate published for the first day of the six-month interest calculation period.
The fair value of the interest rate swaps excludes related hedged amounts we have recorded in earnings. The change in fair value between December 31, 2007 and February 12, 2008 is primarily due to a decrease in market interest rates relative to the interest rates used to determine the fair value of our financial instruments at December 31, 2007. The underlying floating LIBOR forward interest rate curve used to determine the February 12, 2008 fair values ranged from approximately 2.25% to 5.53% using 6-month reset periods ranging from February 2008 to March 2014.
Cash flow hedges - Interest Rate Swaps
Duncan Energy Partners had three interest rate swap agreements outstanding at December 31, 2007 that were accounted for as cash flow hedges.
(1)
Amounts receivable from or payable to the swap counterparties are settled every three months (the “settlement period”).
In September 2007, Duncan Energy Partners executed three floating-to-fixed interest rate swaps having a combined notional value of $175.0 million. The purpose of these financial instruments is to reduce the sensitivity of Duncan Energy Partners’ earnings to variable interest rates charged under its revolving credit facility. It recognized a $0.2 million benefit from these swaps in interest expense during 2007, which includes ineffectiveness of $0.2 million (an expense) and income of $0.4 million. In 2008, Duncan Energy Partners expects to reclassify $0.7 million of accumulated other comprehensive loss that was generated by these interest rate swaps as an increase to interest expense.
At December 31, 2007, the aggregate fair value of these interest rate swaps was a liability of $3.8 million. As cash flow hedges, any increase or decrease in fair value (to the extent effective) would be recorded into other comprehensive income and amortized into income based on the settlement period hedged. Any ineffectiveness is recorded directly into earnings as an increase in interest expense. The following table shows the effect of hypothetical price movements on the estimated fair value of Duncan Energy Partners’ interest rate swap portfolio (dollars in thousands).
Cash flow hedges - Treasury locks
At times, we may use treasury lock financial instruments to hedge the underlying U.S. treasury rates related to our anticipated issuances of debt. A treasury lock is a specialized agreement that fixes the price (or yield) on a specific treasury security for an established period of time. A treasury lock purchaser is protected from a rise in the yield of the underlying treasury security during the lock period. Each of the treasury lock transactions was designated as a cash flow hedge under SFAS 133.
To the extent effective, gains and losses on the value of the treasury locks will be deferred until the forecasted debt is issued and will be amortized to earnings over the life of the debt. No ineffectiveness was recognized as of December 31, 2007. Gains or losses on the termination of such instruments are amortized to earnings using the effective interest method over the estimated term of the underlying fixed-rate debt.
The following table summarizes changes in our treasury lock portfolio since December 31, 2005 (dollars in millions):
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.
The fair value of our commodity financial instrument portfolio, which primarily consisted of cash flow hedges, at December 31, 2007 was a liability of $19.3 million. During the years ended December 31, 2007, 2006 and 2005, we recorded a $28.6 million loss, $10.3 million income and $1.1 million income, respectively, related to our commodity financial instruments, which is included in operating costs and expenses on our Statements of Consolidated Operations. Included in the $28.6 million loss recorded during 2007, was ineffectiveness of $0.9 million (an expense) related to our commodity hedges. These contracts will terminate during 2008, and any amounts remaining in accumulated other comprehensive income will be recorded in earnings.
We assess the risk of our commodity financial instrument portfolio using a sensitivity analysis model. The sensitivity analysis applied to this portfolio measures the potential income or loss (i.e., the change in fair value of the portfolio) based upon a hypothetical 10% movement in the underlying quoted market prices of the commodity financial instruments outstanding at the date indicated within the following table.
The following table shows the effect of hypothetical price movements on the estimated fair value of this portfolio at the dates presented (dollars in thousands):
The increase in portfolio fair value between December 31, 2007 and February 12, 2008 is primarily due to an increase in the price of natural gas.
Foreign Currency Hedging Program
We are exposed to foreign currency exchange rate risk through our Canadian NGL marketing subsidiary and certain construction agreements with respect to our Pioneer processing plant 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.
Mark-to-market accounting is utilized for those foreign exchange contracts associated with our Canadian NGL marketing business. The duration of these contracts is typically one month. As of December 31, 2007, $4.7 million of these exchange contracts were outstanding, all of which settled in January 2008. In January 2008, we entered into $3.7 million of such instruments.
The foreign exchange contracts associated with our construction activities are accounted for using hedge accounting. At December 31, 2007, the fair value of these contracts was $1.3 million. These contracts settle through May 2008.
Product Purchase Commitments
We have long and short-term purchase commitments for NGLs, petrochemicals and natural gas with several suppliers. The purchase prices that we are obligated to pay under these contracts are based on market prices at the time we take delivery of the volumes. For additional information regarding these commitments, see “Contractual Obligations” included under Item 7 of this annual report.
Item 8. Financial Statements and Supplementary Data.
ENTERPRISE PRODUCTS PARTNERS L.P.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Enterprise Products GP, LLC and
Unitholders of Enterprise Products Partners L.P.
Houston, Texas
We have audited the accompanying consolidated balance sheets of Enterprise Products Partners L.P. and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related statements of consolidated operations, consolidated comprehensive income, consolidated cash flows and consolidated partners’ equity for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Enterprise Products Partners L.P. and subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2008 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 28, 2008
ENTERPRISE PRODUCTS PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
See Notes to Consolidated Financial Statements.
ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED OPERATIONS
(Dollars in thousands, except per unit amounts)
See Notes to Consolidated Financial Statements.
ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
(Dollars in thousands)
See Notes to Consolidated Financial Statements.
ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in thousands)
See Notes to Consolidated Financial Statements.
ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED PARTNERS’ EQUITY
(See Note 15 for Unit History and Detail of Changes in Limited Partners’ Equity)
(Dollars in thousands)
See Notes to Consolidated Financial Statements.
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
Note 1. 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 “EPGP”). EPGP 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, EPGP, Enterprise GP Holdings, EPE Holdings and Dan Duncan LLC are affiliates and under common control of Dan L. Duncan, the Group Co-Chairman and controlling shareholder of EPCO.
References to “TEPPCO” mean TEPPCO Partners, L.P., a publicly traded affiliate, the common 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 “LE 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 LE 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, Inc. See Note 25 for information regarding the formation of Enterprise Unit L.P. in February 2008.
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 17). Duncan Energy Partners owns equity interests in certain of our midstream energy businesses. References to “DEP GP” mean DEP Holdings, LLC, which is the general partner of Duncan Energy Partners and is wholly owned by EPO.
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.
Note 2. Summary of Significant Accounting Policies
Allowance for Doubtful Accounts
Our allowance for doubtful accounts is determined based on specific identification and estimates of future uncollectible accounts. Our procedure for determining the allowance for doubtful accounts is based on (i) historical experience with customers, (ii) the perceived financial stability of customers based on our research, and (iii) the levels of credit we grant to customers. In addition, we may increase the allowance account in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties. On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses. Our allowance also includes estimates for uncollectible natural gas imbalances based on specific identification of accounts.
The following table presents the activity of our allowance for doubtful accounts for the years ended December 31, 2007, 2006 and 2005:
Cash and Cash Equivalents
Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase.
Our 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.
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 all material 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.
If the entity 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 entity’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 entity’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 are material
and remain on our balance sheet (or those of our equity method investments) in inventory or similar accounts.
If our ownership interest in an entity does not provide us with either control or significant influence, we account for the investment using the cost method.
Contingencies
Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. Our management and its legal counsel assess such contingent liabilities, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.
If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of liability can be estimated, then the estimated liability would be accrued in our financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss (if determinable and material), is disclosed.
Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed.
Current Assets and Current Liabilities
We present, as individual captions in our consolidated balance sheets, all components of current assets and current liabilities that exceed five percent of total current assets and liabilities, respectively.
Deferred Revenues
We recognize revenues when earned (see Note 4). Amounts billed in advance of the period in which the service is rendered or product delivered are recorded as deferred revenue.
Earnings Per Unit
Earnings per unit is based on the amount of income allocated to limited partners and the weighted-average number of units outstanding during the period. See Note 19 for additional information regarding our earnings per unit.
Employee Benefit Plans
In 2005, we acquired a controlling ownership interest in Dixie Pipeline Company (“Dixie”), which resulted in Dixie becoming a consolidated subsidiary of ours. Dixie 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.
Statement of Financial Accounting Standards (“SFAS”) 158, "Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R),” requires businesses to record the over-funded or under-funded status of defined benefit pension and other postretirement plans as an asset or liability at a measurement date and to recognize annual changes in the funded status of each plan through other comprehensive income. At December 31, 2006, Dixie adopted the provisions of SFAS 158. See Note 6 for additional information regarding Dixie’s employee benefit plans.
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.
Environmental costs and related accruals were not significant prior to the GulfTerra Merger. As a result of the merger, we assumed an environmental liability for remediation costs associated with mercury gas meters. The balance of this environmental liability was $17.2 million and $20.3 million at December 31, 2007 and 2006, respectively. At December 31, 2007 and 2006, total reserves for environmental liabilities, including those related to the mercury gas meters, were $26.5 million and $24.2 million, respectively. At December 31, 2007 and 2006, $6.3 million and $7.1 million, respectively, of these amounts are classified as current liabilities.
In February 2007, we reserved $6.5 million in cash we received from a third party to fund anticipated future environmental remediation costs. These expected costs are associated with assets acquired in connection with the GulfTerra Merger. Previously, the third party had been obligated to indemnify us for such costs. As a result of the settlement, this indemnification arrangement was terminated.
The following table presents the activity of our environmental reserves for the years ended December 31, 2007, 2006 and 2005:
Estimates
Preparing our consolidated financial statements in conformity with generally accepted accounting principles in the United States of America (“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.
Exchange Contracts
Exchanges are contractual agreements for the movements of natural gas liquids (“NGLs”) and certain petrochemical products between parties to satisfy timing and logistical needs of the parties. Net exchange volumes borrowed from us under such agreements are valued and included in accounts receivable, and net exchange volumes loaned to us under such agreements are valued and accrued as a liability in accrued product payables.
Receivables and payables arising from exchange transactions are settled with movements of products rather than with cash. When payment or receipt of monetary consideration is required for product differentials and service costs, such items are recognized in our consolidated financial statements on a net basis.
Exit and Disposal Costs
Exit and disposal costs are charges associated with an exit activity not associated with a business combination or with a disposal activity covered by SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Examples of these costs include (i) termination benefits provided to current employees that are involuntarily terminated under the terms of a benefit arrangement that, in substance, is not an ongoing benefit arrangement or an individual deferred compensation contract, (ii) costs to terminate a contract that is not a capital lease, and (iii) costs to consolidate facilities or relocate employees. In accordance with SFAS 146, “Accounting for Costs Associated with Exit and Disposal Activities,” we recognize such costs when they are incurred rather than at the date of our commitment to an exit or disposal plan.
Financial Instruments
We use financial instruments such as swaps, forward and other contracts to manage price risks associated with inventories, firm commitments, interest rates, foreign currency and certain anticipated transactions. We recognize these transactions on our balance sheet as assets and liabilities based on the instrument’s fair value. Fair value is generally defined as the amount at which the financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale.
Changes in fair value of financial instrument contracts are recognized currently in earnings unless specific hedge accounting criteria are met. If the financial instrument meets the criteria of a fair value hedge, gains and losses incurred on the instrument will be recorded in earnings to offset corresponding losses and gains on the hedged item. If the financial instrument meets the criteria of a cash flow hedge, gains and losses incurred on the instrument are recorded in accumulated other comprehensive income (“AOCI”). Gains and losses on cash flow hedges are reclassified from accumulated other comprehensive income to earnings when the forecasted transaction occurs or, as appropriate, over the economic life of the underlying asset. A contract designated as a hedge of an anticipated transaction that is no longer likely to occur is immediately recognized in earnings.
To qualify as a hedge, the item to be hedged must expose us to risk and the related hedging instrument must reduce the exposure and meet the hedging requirements of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” (as amended and interpreted). We formally designate the financial instrument as a hedge and document and assess the effectiveness of the hedge at its inception and thereafter on a quarterly basis. Any hedge ineffectiveness is immediately recognized in earnings. See Note 7 for additional information regarding our financial instruments.
Foreign Currency Translation
We own a NGL marketing business located in Canada. The financial statements of this foreign subsidiary are translated into U.S. dollars from the Canadian dollar, which is the subsidiary’s functional currency, using the current rate method. Its assets and liabilities are translated at the rate of exchange in effect at the balance sheet date, while revenue and expense items are translated at average rates of exchange during the reporting period. Exchange gains and losses arising from foreign currency translation adjustments are reflected as separate components of accumulated other comprehensive income in the accompanying Consolidated Balance Sheets. Our net cash flows from this Canadian subsidiary may be adversely affected by changes in foreign currency exchange rates. We attempt to hedge this currency risk (see Note 7).
Impairment Testing for Goodwill
Our goodwill amounts are assessed for impairment (i) on a routine annual basis or (ii) when impairment indicators are present. If such indicators occur (e.g., the loss of a significant customer, economic obsolescence of plant assets, etc.), the estimated fair value of the reporting unit to which the goodwill is assigned is determined and compared to its book value. If the fair value of the reporting unit exceeds its book value including associated goodwill amounts, the goodwill is considered to be unimpaired and no impairment charge is required. If the fair value of the reporting unit is less than its book value including associated goodwill amounts, a charge to earnings is recorded to reduce the carrying value of the goodwill to its implied fair value. We have not recognized any impairment losses related to goodwill for any of the periods presented. See Note 13 for additional information regarding our goodwill.
Impairment Testing for Long-Lived Assets
Long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable.
Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written-down to their estimated fair values in accordance with SFAS 144. The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset’s carrying value over its estimated fair value is recorded. Fair value is defined as the amount at which an asset or liability could be bought or settled in an arm’s-length transaction. We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques.
We recorded a non-cash asset impairment charge of $0.1 million in 2006, which is reflected as a component of operating costs and expenses in our 2006 Statement of Consolidated Operations. No asset impairment charges were recorded in 2007 and 2005.
Impairment Testing for Unconsolidated Affiliates
We evaluate our equity method investments for impairment when events or changes in circumstances indicate that there is a loss in value of the investment attributable to an other than temporary decline. Examples of such events or changes in circumstances include continuing operating losses of the entity and/or long-term negative changes in the entity’s industry. In the event we determine that the loss in value of an investment is other than a temporary decline, we record a charge to earnings to adjust the carrying value of the investment to its estimated fair value.
During 2007, we evaluated our equity method investment in Nemo Gathering Company, LLC for impairment. As a result of this evaluation, we recorded a $7.0 million non-cash impairment charge that is a component of equity income from unconsolidated affiliates for the year ended December 31, 2007. Similarly, during 2006, we evaluated our investment in Neptune Pipeline Company, L.L.C. (“Neptune”) for impairment. As a result of this evaluation, we recorded a $7.4 million non-cash impairment charge that is a component of equity income from unconsolidated affiliates for the year ended December 31, 2006. We had no such impairment charges during the year ended December 31, 2005. See Note 11 for additional information regarding our equity method investments.
Income Taxes
Provision for income taxes is primarily applicable to our state tax obligations under the Revised Texas Franchise Tax (“the Revised Texas Franchise Tax”) and certain federal and state tax obligations of Seminole Pipeline Company (“Seminole”) and Dixie, both of which are consolidated subsidiaries of ours. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of our tax paying entities for financial reporting and tax purposes.
In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax. In May 2006, the State of Texas expanded its pre-existing franchise tax to include limited partnerships, limited liability companies, corporations and limited liability partnerships. As a result of the change in tax law, our tax status in the State of Texas has changed from non-taxable to taxable.
Since we are structured as a pass-through entity, we are not subject to federal income taxes. As a result, our partners are individually responsible for paying federal income taxes on their share of our taxable income. Since we do not have access to information regarding each partner’s tax basis, we cannot readily determine the total difference in the basis of our net assets for financial and tax reporting purposes.
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. See Note 18 for additional information regarding our income taxes.
Inventories
Inventories primarily consist of NGLs, certain petrochemical products and natural gas volumes that are valued at the lower of average cost or market. We capitalize, as a cost of inventory, shipping and handling charges directly related to volumes we purchase from third parties or take title to in connection with processing or other agreements. As these volumes are sold and delivered out of inventory, the average cost of these products (including freight-in charges that have been capitalized) are charged to operating costs and expenses. Shipping and handling fees associated with products we sell and deliver to customers are charged to operating costs and expenses as incurred. See Note 9 for additional information regarding our inventories.
Minority Interest
As presented in our 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 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 December 31, 2007 balance sheet, consists of $288.6 million attributable to third party owners of Duncan Energy Partners and the remainder to our other consolidated affiliates.
Minority interest expense for the year ended December 31, 2007 includes $13.9 million attributable to third party owners of Duncan Energy Partners. The remaining minority interest expense amounts for 2007 and likewise those for 2006 are attributable to our other consolidated affiliates.
Contributions from minority interests for the year ended December 31, 2007 includes $290.5 million received from third parties in connection with the initial public offering of Duncan Energy Partners in February 2007.
Natural Gas Imbalances
In the natural gas pipeline transportation business, imbalances frequently result from differences in natural gas volumes received from and delivered to our customers. Such differences occur when a customer delivers more or less gas into our pipelines than is physically redelivered back to them during a particular time period. We have various fee-based agreements with customers to transport their natural gas through
our pipelines. Our customers retain ownership of their natural gas shipped through our pipelines. As such, our pipeline transportation activities are not intended to create physical volume differences that would result in significant accounting or economic events for either our customers or us during the course of the arrangement.
We settle pipeline gas imbalances through either (i) physical delivery of in-kind gas or (ii) in cash. These settlements follow contractual guidelines or common industry practices. As imbalances occur, they may be settled (i) on a monthly basis, (ii) at the end of the agreement or (iii) in accordance with industry practice, including negotiated settlements. Certain of our natural gas pipelines have a regulated tariff rate mechanism requiring customer imbalance settlements each month at current market prices.
However, the vast majority of our settlements are through in-kind arrangements whereby incremental volumes are delivered to a customer (in the case of an imbalance payable) or received from a customer (in the case of an imbalance receivable). Such in-kind deliveries are on-going and take place over several periods. In some cases, settlements of imbalances built up over a period of time are ultimately cashed out and are generally negotiated at values which approximate average market prices over a period of time. For those gas imbalances that are ultimately settled over future periods, we estimate the value of such current assets and liabilities using average market prices, which is representative of the estimated value of the imbalances upon final settlement. Changes in natural gas prices may impact our estimates.
At December 31, 2007 and 2006, our natural gas imbalance receivables, net of allowance for doubtful accounts, were $60.9 million and $97.8 million, respectively, and are reflected as a component of “Accounts and notes receivable - trade” on our Consolidated Balance Sheets. At December 31, 2007 and 2006, our imbalance payables were $38.3 million and $51.2 million, respectively, and are reflected as a component of “Accrued product payables” on our Consolidated Balance Sheets.
Property, Plant and Equipment
Property, plant and equipment is recorded at cost. Expenditures for additions, improvements and other enhancements to property, plant and equipment are capitalized and minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred. When property, plant and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in the results of operations for the respective period. For financial statement purposes, depreciation is recorded based on the estimated useful lives of the related assets primarily using the straight-line method. Where appropriate, we use other depreciation methods (generally accelerated) for tax purposes. See Note 10 for additional information regarding our property, plant and equipment.
Certain of our plant operations entail periodic planned outages for major maintenance activities. These planned shutdowns typically result in significant expenditures, which are principally comprised of amounts paid to third parties for materials, contract services and related items. We use the expense-as-incurred method for our planned major maintenance activities that benefit periods in excess of one year or for periods that are not determinable. We use the deferral method for our annual planned major maintenance activities.
Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. Over time, the liability is accreted to its present value (accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. To the extent we do not settle an ARO liability at our recorded amounts, we will incur a gain or loss.
Reclassifications
A reclassification was made to the Statements of Operations for the year ended December 31, 2005 to consistently reflect our 2005 revenues due to a reclassification of $12.7 million from “Third-parties” to “Related-parties” attributable to our Onshore Natural Gas Pipelines & Services business segment. Such reclassification related to the presentation of our 49.5% equity method investment in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp. (collectively “Evangeline”) which revised its disclosures. A reclassification was made to the Statements of Consolidated Comprehensive Income for the year ended December 31, 2006 to include $2.2 million in reclassification adjustments for losses included in net income related to financial instruments and $8.7 million in net interest rate financial instrument gains to conform to the current year presentation of such activities.
Restricted Cash
Restricted cash represents amounts held by (i) a brokerage firm in connection with our commodity financial instruments portfolio and physical natural gas purchases made on the New York Mercantile Exchange (“NYMEX”) exchange, and (ii) us for the future settlement of current liabilities we assumed in connection with our acquisition of a Canadian affiliate in October 2006.
Revenue Recognition
See Note 4 for information regarding our revenue recognition policies.
Start-Up and Organization Costs
Start-up costs and organization costs are expensed as incurred. Start-up costs are defined as one-time activities related to opening a new facility, introducing a new product or service, conducting activities in a new territory, pursuing a new class of customer, initiating a new process in an existing facility, or some new operation. Routine ongoing efforts to improve existing facilities, products or services are not considered start-up costs. Organization costs include legal fees, promotional costs and similar charges incurred in connection with the formation of a business.
Unit-Based Awards
We account for unit-based awards in accordance with SFAS 123(R), “Share-Based Payment.” Prior to January 1, 2006, our unit-based awards were accounted for using the intrinsic value method described in Accounting Principles Board Opinion (“APB”) 25, “Accounting for Stock Issued to Employees.” The following table discloses the pro forma effect of unit-based compensation amounts on our net income and earnings per unit for the year ended December 31, 2005 as if we had applied the provisions of SFAS 123(R) instead of APB 25. The effects of applying SFAS 123(R) in the following pro forma disclosures may not be indicative of future amounts as additional awards in future years are anticipated. No pro forma adjustments are required for restricted unit awards in 2005 since compensation expense related to these awards was based on their estimated fair values. See Note 5 for additional information regarding our unit-based awards.
Note 3. Recent Accounting Developments
The following information summarizes recently issued accounting guidance that will or may affect our future financial statements:
SFAS 157
SFAS 157, “Fair Value Measurements,” defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS 157 applies only to fair-value measurements that are already required (or permitted) by other accounting standards and is expected to increase the consistency of those measurements. SFAS 157 emphasizes that fair value is a market-based measurement that should be determined based on the assumptions that market participants would use in pricing an asset or liability. Companies will be required to disclose the extent to which fair value is used to measure assets and liabilities, the inputs used to develop such measurements, and the effect of certain of the measurements on earnings (or changes in net assets) during a period.
Certain requirements of SFAS 157 are effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The effective date for other requirements of SFAS 157 has been deferred for one year. We adopted the provisions of SFAS 157 which are effective for fiscal years beginning after November 15, 2007 and there was no impact on our financial statements. Management is currently evaluating the impact that the deferred provisions of SFAS 157 will have on the disclosures in our financial statements in 2009.
SFAS 141(R)
SFAS 141(R), “Business Combinations,” replaces SFAS 141, “Business Combinations.” SFAS 141(R) retains the fundamental requirements of SFAS 141 that the acquisition method of accounting (previously termed the “purchase method”) be used for all business combinations and for an acquirer to be identified for each business combination. SFAS 141(R) defines the acquirer as the entity that obtains control of one or more businesses in a business combination and establishes the acquisition date as the date that the acquirer achieves control. This new guidance also retains guidance in SFAS 141 for identifying and recognizing intangible assets separately from goodwill.
The objective of SFAS 141(R) is to improve the relevance, representational faithfulness, and comparability of the information a reporting entity provides in its financial reports about business combinations and their effects. To accomplish this, SFAS 141(R) establishes principles and requirements for how the acquirer:
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Recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interests in the acquiree.
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Recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase. SFAS 141(R) defines a bargain purchase as a business combination in which the total acquisition-date fair value of the identifiable net assets acquired exceeds the fair value of the consideration transferred plus any noncontrolling interest in the acquiree, and requires the acquirer to recognize that excess in earnings as a gain attributable to the acquirer.
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Determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination.
SFAS 141(R) also requires that direct costs of an acquisition (e.g. finder’s fees, outside consultants, etc.) be expensed as incurred and not capitalized as part of the purchase price.
As a calendar year-end entity, we will adopt SFAS 141(R) on January 1, 2009. Although we are still evaluating this new guidance, we expect that it will have an impact on the way in which we evaluate acquisitions. For example, we have made several acquisitions in the past where the fair value of assets
acquired and liabilities assumed was in excess of the purchase price. In those cases, a bargain purchase would have been recognized under SFAS 141(R). Conversely, we will no longer capitalize transaction fees and other direct costs.
SFAS 160
SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51,” establishes accounting and reporting standards for non-controlling interests, which have been referred to as minority interests in prior accounting literature. A noncontrolling interest is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent company. This new standard requires, among other things, that (i) ownership interests of noncontrolling interests be presented as a component of equity on the balance sheet (i.e. elimination of the mezzanine “minority interest” category); (ii) elimination of minority interest expense as a line item on the statement of income and, as a result, that net income be allocated between the parent and noncontrolling interests on the face of the statement of income; and (iii) enhanced disclosures regarding noncontrolling interests. As a calendar year-end entity, we will adopt SFAS 160 on January 1, 2009 and apply its presentation and disclosure requirements retrospectively.
Note 4. Revenue Recognition
In general, we recognize revenue from our customers when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the buyer’s price is fixed or determinable and (iv) collectability is reasonably assured. The following information provides a general description our underlying revenue recognition policies by business segment:
NGL Pipelines & Services
This aspect of our business generates revenues primarily from the provision of natural gas processing, NGL pipeline transportation, product storage and NGL fractionation services and the sale of NGLs. In our natural gas processing activities, we enter into margin-band contracts, percent-of-liquids contracts, percent-of-proceeds contracts, fee-based contracts, hybrid-contracts (i.e. mixed percent-of-liquids and fee-based) and keepwhole contracts. Under margin-band and keepwhole contracts, we take ownership of mixed NGLs extracted from the producer’s natural gas stream and recognize revenue when the extracted NGLs are delivered and sold to customers under NGL marketing sales contracts. In the same way, revenue is recognized under our percent-of-liquids contracts except that the volume of NGLs we extract and sell is less than the total amount of NGLs extracted from the producers’ natural gas. Under a percent-of-liquids contract, the producer retains title to the remaining percentage of mixed NGLs we extract. Under a percent-of-proceeds contract, we share in the proceeds generated from the sale of the mixed NGLs we extract on the producer’s behalf. If a cash fee for natural gas processing services is stipulated by the contract, we record revenue when the natural gas has been processed and delivered to the producer.
Our NGL marketing activities generate revenues from the sale of NGLs obtained from either our natural gas processing activities or purchased from third parties on the open market. Revenues from these sales contracts are recognized when the NGLs are delivered to customers. In general, the sales prices referenced in these contracts are market-related and can include pricing differentials for such factors as delivery location.
Under our NGL pipeline transportation contracts and tariffs, revenue is recognized when volumes have been delivered to customers. Revenue from these contracts and tariffs is generally based upon a fixed fee per gallon of liquids transported multiplied by the volume delivered. Transportation fees charged under these arrangements are either contractual or regulated by governmental agencies such as the Federal Energy Regulatory Commission (“FERC”).
We collect storage revenues under our NGL and related product storage contracts based on the number of days a customer has volumes in storage multiplied by a storage rate (as defined in each contract). Under these contracts, revenue is recognized ratably over the length of the storage period. With respect to capacity reservation agreements, we collect a fee for reserving storage capacity for customers in our underground storage wells. Under these agreements, revenue is recognized ratably over the specified reservation period. Excess storage fees are collected when customers exceed their reservation amounts and are recognized in the period of occurrence.
Revenues from product terminalling activities (applicable to our import and export operations) are recorded in the period such services are provided. Customers are typically billed a fee per unit of volume loaded or unloaded. With respect to export operations, revenues may also include demand payments charged to customers who reserve the use of our export facilities and later fail to use them. Demand fee revenues are recognized when the customer fails to utilize the specified export facility as required by contract.
We enter into fee-based arrangements and percent-of-liquids contracts for the NGL fractionation services we provide to customers. Under such fee-based arrangements, revenue is recognized in the period services are provided. Such fee-based arrangements typically include a base-processing fee (typically in cents per gallon) that is subject to adjustment for changes in certain fractionation expenses (e.g. natural gas fuel costs). Certain of our NGL fractionation facilities generate revenues using percent-of-liquids contracts. Such contracts allow us to retain a contractually determined percentage of the customer’s fractionated NGL products as payment for services rendered. Revenue is recognized from such arrangements when we sell and deliver the retained NGLs to customers.
Onshore Natural Gas Pipelines & Services
This aspect of our business generates revenues primarily from the provision of natural gas pipeline transportation and gathering services; natural gas storage services; and from the sale of natural gas. Certain of our onshore natural gas pipelines generate revenues from transportation and gathering agreements as customers are billed a fee per unit of volume multiplied by the volume delivered or gathered. Fees charged under these arrangements are either contractual or regulated by governmental agencies such as the FERC. Revenues associated with these fee-based contracts are recognized when volumes have been delivered.
Revenues from natural gas storage contracts typically have two components: (i) a monthly demand payment, which is associated with storage capacity reservations, and (ii) a storage fee per unit of volume held at each location. Revenues from demand payments are recognized during the period the customer reserves capacity. Revenues from storage fees are recognized in the period the services are provided.
Our natural gas marketing activities generate revenues from the sale of natural gas purchased from third parties on the open market. Revenues from these sales contracts are recognized when the natural gas is delivered to customers. In general, the sales prices referenced in these contracts are market-related and can include pricing differentials for such factors as delivery location.
Offshore Pipelines & Services
This aspect of our business generates revenues from the provision of offshore natural gas and crude oil pipeline transportation services and related offshore platform operations. Our offshore natural gas pipelines generate revenues through fee-based contracts or tariffs where revenues are equal to the product of a fee per unit of volume (typically in MMBtus) multiplied by the volume of natural gas transported. Revenues associated with these fee-based contracts and tariffs are recognized when natural gas volumes have been delivered.
The majority of our revenues from offshore crude oil pipelines are derived from purchase and sale arrangements whereby crude oil is purchased from shippers at various receipt points along the pipeline for an index-based price (less a price differential) and sold back to the shippers at various redelivery points at the same index-based price. Net revenue recognized from such arrangements is based on the price
differential per unit of volume (typically in barrels) multiplied by the volume delivered. In addition, certain offshore crude oil pipelines generate revenues based upon a gathering fee per unit of volume (typically in barrels) multiplied by the volume delivered to the customer. Revenues from both arrangements are recognized when the crude oil is delivered.
Revenues from offshore platform services generally consist of demand payments and commodity charges. Revenues from platform services are recognized in the period the services are provided. Demand fees represent charges to customers served by our offshore platforms regardless of the volume the customer delivers to the platform. Revenues from commodity charges are based on a fixed-fee per unit of volume delivered to the platform (typically per MMcf of natural gas or per barrel of crude oil) multiplied by the total volume of each product delivered. Contracts for platform services often include both demand payments and commodity charges, but demand payments generally expire after a contractually fixed period of time and in some instances may be subject to cancellation by customers. Our Independence Hub and Marco Polo offshore platforms earn a significant amount of demand revenues. The Independence Hub platform will earn $55.2 million of demand revenues annually through March 2012. The Marco Polo platform will earn $25.2 million of demand revenues annually through April 2009.
Petrochemical Services
This aspect of our business generates revenues from the provision of isomerization and propylene fractionation services and the sale of certain petrochemical products. Our isomerization and propylene fractionation operations generate revenues through fee-based arrangements, which typically include a base-processing fee per gallon (or other unit of measurement) subject to adjustment for changes in natural gas, electricity and labor costs, which are the primary costs of propylene fractionation and isomerization operations. Revenues resulting from such agreements are recognized in the period the services are provided.
Our petrochemical marketing activities generate revenues from the sale of propylene and other petrochemicals obtained from either its processing activities or purchased from third parties on the open market. Revenues from these sales contracts are recognized when the petrochemicals are delivered to customers. In general, the sales prices referenced in these contracts are market-related and can include pricing differentials for such factors as delivery location.
Note 5. Accounting for Unit-Based Awards
Since January 1, 2006, we account for unit-based awards in accordance with SFAS 123(R) (see Note 2). The following table summarizes our unit-based compensation amounts by plan during each of the periods indicated:
See Note 25 for information regarding the formation of the Enterprise Products 2008 Long-Term Incentive Plan in January 2008 and Enterprise Unit L.P. in February 2008.
SFAS 123(R) requires us to recognize compensation expense related to unit-based awards based on the fair value of the award at grant date. The fair value of restricted unit awards (i.e. time-vested units under SFAS 123(R)) 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 (such as a restricted unit award) is amortized to earnings on a straight-line basis over the requisite service or vesting period. Compensation expense for liability-classified awards (such as unit appreciation rights (“UARs”)) 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. Liability-type awards are cash settled upon vesting.
As used in the context of the EPCO plans, the term “restricted unit” represents a time-vested unit under SFAS 123(R). Such awards are non-vested until the required service period expires.
Upon our adoption of SFAS 123(R), we recognized, as a benefit, a cumulative effect of a change in accounting principle of $1.5 million based on the SFAS 123(R) requirement to recognize compensation expense based upon the grant date fair value of an equity award and the application of an estimated forfeiture rate to unvested awards. In addition, previously recognized deferred compensation expense of $14.6 million related to our restricted common units was reversed on January 1, 2006.
Prior to our adoption of SFAS 123(R), we did not recognize any compensation expense related to unit options; however, compensation expense was recognized in connection with awards granted by EPE Unit L.P. (“EPE Unit I”) and the issuance of restricted units. The effects of applying SFAS 123(R) during the year ended December 31, 2006 did not have a material effect on our net income or basic and diluted earnings per unit. Since we adopted SFAS 123(R) using the modified prospective method, we have not restated the financial statements of prior periods to reflect this new standard.
1998 Plan
Unit option awards. Under 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. When issued, the exercise price of each option grant is equivalent to the market price of the underlying equity on the date of grant. In general, options granted under the 1998 Plan have a cliff vesting period of four years and remain exercisable for ten years from the date of grant.
In order to fund its obligations under the 1998 Plan, EPCO may purchase common units at fair value either in the open market or directly from us. When employees exercise unit options, we reimburse EPCO for the cash difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the units issued to the employee.
The fair value of each unit option is estimated on the date of grant using the Black-Scholes option pricing model, which incorporates various assumptions including expected life of the options, risk-free interest rates, expected distribution yield on our common units, and expected unit price volatility of our common units. In general, our assumption of expected life of the options represents the period of time that the options are expected to be outstanding based on an analysis of historical option activity. Our selection of the risk-free interest rate is based on published yields for U.S. government securities with comparable terms. The expected distribution yield and unit price volatility is estimated based on several factors, which include an analysis of our historical unit price volatility and distribution yield over a period equal to the expected life of the option.
The 1998 Plan provides for the issuance of up to 7,000,000 of our common units. After giving effect to outstanding option awards at December 31, 2007 and the issuance and forfeiture of restricted unit awards through December 31, 2007, a total of 1,282,256 additional common units could be issued under the 1998 Plan.
The following table presents option activity under the 1998 Plan for the periods indicated:
The total intrinsic value of option awards exercised during the years ended December 31, 2007, 2006 and 2005 were $3.0 million, $2.2 million and $9.2 million, respectively. At December 31, 2007, there was an estimated $2.8 million of total unrecognized compensation cost related to nonvested option awards granted under the 1998 Plan. We expect to recognize this amount over a weighted-average period of 3.0 years. We will recognize our share of these costs in accordance with the EPCO administrative services agreement (see Note 17).
During the years ended December 31, 2007 and 2006, we received cash of $7.5 million and $5.6 million, respectively from the exercise of option awards granted under the 1998 Plan. Conversely, our option-related reimbursements to EPCO were $3.0 million and $1.8 million, respectively.
Restricted unit awards. Under the 1998 Plan, we may also issue restricted common units to key employees of EPCO and directors of our general partner. In general, the restricted unit awards allow recipients to acquire the underlying common units at no cost to the recipient once a defined cliff vesting period expires, subject to certain forfeiture provisions. The restrictions on such units generally lapse four years from the date of grant. Compensation expense is recognized on a straight-line basis over the vesting period. Fair value of such restricted units is based on the market price of the underlying common units on the date of grant and an allowance for estimated forfeitures.
Each recipient is also entitled to cash distributions equal to the product of the number of restricted units outstanding for the participant and the cash distribution per unit paid by us to our unitholders. Since restricted units are issued securities, such distributions are reflected as a component of cash distributions to partners as shown on our statements of consolidated cash flows. We paid $2.6 million, $1.6 million and $0.9 million in cash distributions with respect to restricted units during the years ended December 31, 2007, 2006 and 2005, respectively.
The following table summarizes information regarding our restricted unit awards for the periods indicated:
The total fair value of restricted units that vested during the year ended December 31, 2007 was $0.1 million. At December 31, 2007, there was an estimated $25.5 million of total unrecognized compensation cost related to restricted unit awards granted under the 1998 Plan, which we expect to recognize over a weighted-average period of 2.4 years. We will recognize our share of such costs in accordance with the EPCO administrative services agreement.
Phantom unit awards. The 1998 Plan also provides for the issuance of phantom unit awards. These liability awards are automatically redeemed for cash based on the vested portion of the fair market value of the phantom units at redemption dates in each award. The fair market value of each phantom unit award is equal to the market closing price of our common units on the redemption date. Each participant is required to redeem their phantom units as they vest, which typically is four years from the date the award is granted. No phantom unit awards have been issued to date under the 1998 Plan.
The 1998 Plan also provides for the award of distribution equivalent rights (“DERs”) in tandem with its phantom unit awards. A DER entitles the participant to cash distributions equal to the product of the number of phantom units outstanding for the participant and the cash distribution rate paid by us to our unitholders.
Employee Partnerships
EPCO formed the Employee Partnerships to serve as an incentive arrangement for key employees of EPCO by providing them a “profits interest” in the Employee Partnerships. Certain EPCO employees who work on behalf of us and EPCO were issued Class B limited partner interests and admitted as Class B limited partners without any capital contribution. The profits interest awards (i.e., the Class B limited partner interests) in the Employee Partnerships entitles each holder to participate in the appreciation in value of Enterprise GP Holdings’ Units. The Class B limited partner interests are subject to forfeiture if the participating employee’s employment with EPCO is terminated prior to vesting, with customary exceptions for death, disability and certain retirements. The risk of forfeiture will also lapse upon certain change in control events.
Prior to our adoption of SFAS 123(R), the estimated value of these awards was accounted for in a manner similar to a stock appreciation right. Starting January 1, 2006, compensation expense attributable to these awards was based on the estimated grant date fair value of each award. A portion of the fair value of these equity-based awards is allocated to us under the EPCO administrative services agreement as a non-cash expense. We are not responsible for reimbursing EPCO for any expenses of the Employee
Partnerships, including the value of any contributions of cash or units of Enterprise GP Holdings made by private company affiliates of EPCO at the formation of each Employee Partnership.
Currently, there are four Employee Partnerships. EPE Unit I was formed in August 2005 in connection with Enterprise GP Holdings’ initial public offering. EPE Unit II was formed in December 2006. EPE Unit III was formed in May 2007.
At December 31, 2007, there was an estimated $26.9 million of combined unrecognized compensation cost related to the Employee Partnerships. We will recognize our share of these costs in accordance with the EPCO administrative services agreement over a weighted-average period of 3.9 years.
The following is a discussion of significant terms of EPE Unit I, EPE Unit II, and EPE Unit III.
EPE Unit I. In connection with the initial public offering of Enterprise GP Holdings in August 2005, EPE Unit I was formed to serve as an incentive arrangement for certain employees of EPCO through a “profits interest” in EPE Unit I. In August 2005, EPE Unit I used $51.0 million in contributions it received from its Class A limited partner (an affiliate of EPCO) to purchase 1,821,428 units of Enterprise GP Holdings. Certain EPCO employees, including all of EPGP’s executive officers other than Dan L. Duncan and Dr. Ralph S. Cunningham, were admitted as Class B limited partners of EPE Unit I without any capital contributions.
Unless otherwise agreed to by EPCO, the Class A limited partner and a majority of the Class B limited partners, EPE Unit I will be liquidated upon the earlier of (i) August 2010 or (ii) a change in control of Enterprise GP Holdings or its general partner, EPE Holdings. Upon liquidation of EPE Unit I, units having a fair market value equal to the Class A limited partner’s capital base, plus any Class A preferred return for the quarter in which liquidation occurs, will be distributed to the Class A limited partner. Any remaining units will be distributed to the Class B limited partners as a residual profits interest award in EPE Unit I.
As adjusted for forfeitures and regrants, the grant date fair value of the Class B limited partnership interests in EPE Unit I was $12.2 million at December 31, 2007. This fair value was estimated using the Black-Scholes option pricing model, which incorporates various assumptions including (i) an expected life of the awards ranging from three to five years, (ii) risk-free interest rates ranging from 4.1% to 5.0%, (iii) an expected distribution yield on units of Enterprise GP Holdings ranging from 3.0% to 4.2%, and (iv) an expected unit price volatility for Enterprise GP Holdings’ units ranging from 17.4% to 30.0%.
EPE Unit II. In December 2006, EPE Unit II, L.P. was formed to serve as an incentive arrangement for Dr. Ralph S. Cunningham, an executive officer of our general partner. The officer, who is not a participant in EPE Unit I, was granted a “profits interest” award in EPE Unit II. EPCO serves as the general partner of EPE Unit II.
At inception, EPE Unit II used $1.5 million in contributions it received from an affiliate of EPCO (which was admitted as the Class A limited partner of EPE Unit II as a result of such contribution) to purchase 40,725 units of Enterprise GP Holdings at an average price of $36.91 per unit in December 2006. The officer was issued a Class B limited partner interest in EPE Unit II without any capital contribution.
Unless otherwise agreed upon by EPCO, the Class A limited partner and the Class B limited partner, EPE Unit II will be liquidated upon the earlier of (i) December 2011 or (ii) a change in control of Enterprise GP Holdings or its general partner, EPE Holdings. Upon liquidation of the EPE Unit II, units having a fair market value equal to the Class A limited partner’s capital base will be distributed to the Class A limited partner, plus any Class A preferred return for the quarter in which liquidation occurs. Any remaining units will be distributed to the Class B limited partner as a residual profits interest award in EPE Unit II.
The grant date fair value of the Class B limited partnership interests in EPE Unit II was $0.2 million at December 31, 2007. This fair value was estimated on the date of grant using the Black-Scholes option pricing model, which incorporated various assumptions including (i) an expected life of the award of five years, (ii) risk-free interest rate of 4.4%, (iii) an expected distribution yield on units of Enterprise GP Holdings of 3.8%, and (iv) an expected Enterprise GP Holdings unit price volatility of 18.7%.
EPE Unit III. EPE Unit III 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. The units of Enterprise GP Holdings contributed by the Class A limited partner had a fair value of $170.0 million on the date of contribution (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 Enterprise GP Holdings’ units owned by EPE Unit III.
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:
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Distributions of Cash flow - 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 pro rata 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% per annum, 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, Enterprise GP Holdings’ 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 of Enterprise GP Holdings will be distributed to the Class B limited partners.
§
Sale Proceeds - If EPE Unit III sells any of the 4,421,326 units of Enterprise GP Holdings 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 adjusted for forfeitures and regrants, the grant date fair value of the Class B limited partnership interests in EPE Unit III was $23.0 million at December 31, 2007. This fair value was estimated using the Black-Scholes option pricing model, which incorporates various assumptions including (i) an expected life of the awards ranging from four to five years, (ii) risk-free interest rates ranging from 3.5% to 4.9%, (iii) an expected distribution yield on units of Enterprise GP Holdings ranging from 4.0% to 4.3%, and (iv) an expected unit price volatility for Enterprise GP Holdings’ units ranging from 16.9% to 17.6%.
DEP Holdings, LLC Unit Appreciation Rights
The non-employee directors of DEP Holdings, LLC, the general partner of Duncan Energy Partners (“DEP GP”), have been granted UARs in the form of letter agreements. These liability awards are not part of any established long-term incentive plan of EPCO, Enterprise GP Holdings or us. The compensation expense associated with these awards is recognized by DEP GP, which is our consolidated subsidiary. The UARs entitle each non-employee director to receive a cash payment on the vesting date equal to the excess, if any, of the fair market value of Enterprise GP Holdings’ units (determined as of a future vesting date) over the grant date fair value. If a director resigns prior to vesting, his UAR awards are forfeited. These UARs are accounted for similar to liability awards under SFAS 123(R) since they will be settled with cash.
As of December 31, 2007, a total of 90,000 UARs had been granted to non-employee directors of DEP GP that cliff vest in 2012. If a director resigns prior to vesting, his UAR awards are forfeited. The grant date fair value with respect to these UARs is based on an Enterprise GP Holdings’ unit price of $36.68.
Note 6. Employee Benefit Plans
Dixie 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 $0.3 million to its company-sponsored defined contribution plan for each of the years ended December 31, 2007 and 2006.
Pension and Postretirement Benefit Plans
Dixie’s pension plan is a noncontributory defined benefit plan that provides for the payment of benefits to retirees based on their age at retirement, years of service and average compensation. Dixie’s postretirement benefit plan also provides medical and life insurance to retired employees. The medical plan is contributory and the life insurance plan is noncontributory. Dixie employees hired after July 1, 2004 are not eligible for pension and other benefit plans after retirement.
The following table presents Dixie’s benefit obligations, fair value of plan assets and funded status at December 31, 2007.
Projected benefit obligations and net periodic benefit costs are based on actuarial estimates and assumptions. The weighted-average actuarial assumptions used in determining the projected benefit obligation at December 31, 2007 were as follows: discount rate of 5.75%; rate of compensation increase of 4.00% and 5.00% for the pension and postretirement plans, respectively; and a medical trend rate of 8.00% for 2008 grading to an ultimate trend of 5.00% for 2010 and later years. Dixie’s net pension and postretirement benefit costs for 2007 were $1.1 million (including settlement loss of $0.6 million) and $0.4 million, respectively. Dixie’s net pension and postretirement benefit costs for 2006 were $0.7 million and $0.3 million, respectively.
Future benefits expected to be paid from Dixie’s pension and postretirement plans are as follows for the periods indicated:
On December 31, 2006, Dixie adopted the recognition and disclosure provisions of SFAS 158. Dixie uses a December 31 measurement date of these plans. SFAS 158 requires Dixie to recognize the funded status of its defined benefit pension and other postretirement plans as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income.
The incremental effects of Dixie’s implementation of SFAS 158 on our Consolidated Balance Sheets at December 31, 2006 are presented in the following table.
Included in Accumulated Other Comprehensive Income (“AOCI”) on the Consolidated Balance Sheet at December 31, 2007 and 2006 are the following amounts that have not been recognized in net periodic pension costs (in millions):
Note 7. Financial Instruments
We are exposed to financial market risks, including changes in commodity prices, interest rates and foreign exchange 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) the 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.
We recognize financial instruments as assets and liabilities on our Consolidated Balance Sheets based on fair value. Fair value is generally defined as the amount at which a financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. The estimated fair values of our financial instruments have been determined using available market information and appropriate valuation techniques. We must use considerable judgment, however, in interpreting market data and developing these estimates. Accordingly, our fair value estimates are not necessarily indicative of the amounts that we could realize upon disposition of these instruments. The use of different market assumptions and/or estimation techniques could have a material effect on our estimates of fair value.
Changes in the fair value of financial instrument contracts are recognized currently in earnings unless specific hedge accounting criteria are met. If the financial instruments meet those criteria, the instrument’s gains and losses offset the related results of the hedged item in earnings for a fair value hedge and are deferred in other comprehensive income for a cash flow hedge. Gains and losses related to a cash flow hedge are reclassified into earnings when the forecasted transaction affects earnings. For additional information regarding our accounting for financial instruments, see Note 2 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
To qualify as a hedge, the item to be hedged must be exposed to commodity, interest rate or exchange rate risk and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” (as amended and interpreted). We must formally designate the financial instrument as a hedge and document and assess the effectiveness of the hedge at inception and on a quarterly basis. Any ineffectiveness of the hedge is recorded in current earnings.
We routinely review our outstanding financial instruments in light of current market conditions. If market conditions warrant, some financial instruments may be closed out in advance of their contractual settlement dates thus realizing income or loss depending on the specific hedging criteria. When this occurs, we may enter into a new financial instrument to reestablish the hedge to which the closed instrument relates.
Interest Rate Risk Hedging Program
Our interest rate exposure results from variable and fixed rate borrowings under various debt agreements. We manage a portion of our interest rate exposures 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. The following information summarizes significant components of our interest rate risk hedging portfolio:
Fair value hedges - Interest rate swaps
As summarized in the following table, we had eleven interest rate swap agreements outstanding at December 31, 2007 that were accounted for as fair value hedges.
(1)
The variable rate indicated is the all-in variable rate for the current settlement period.
We have designated these eleven interest rate swaps as fair value hedges under SFAS 133 since they mitigate changes in the fair value of the underlying fixed rate debt. As effective fair value hedges, an increase in the fair value of these interest rate swaps is equally offset by an increase in the fair value of the underlying hedged debt. The offsetting changes in fair value have no effect on current period interest expense.
These eleven agreements have a combined notional amount of $1.1 billion and match the maturity dates of the underlying debt being hedged. Under each swap agreement, we pay the counterparty a variable interest rate based on six-month London interbank offered rate (“LIBOR”) (plus an applicable margin as defined in each swap agreement), and receive back from the counterparty a fixed interest rate payment based on the stated interest rate of the debt being hedged, with both payments calculated using the notional amounts stated in each swap agreement. We settle amounts receivable from or payable to the counterparties every six months (the “settlement period”). The settlement amount is amortized ratably to earnings as either an increase or a decrease in interest expense over the settlement period.
The total fair value of these eleven interest rate swaps at December 31, 2007, was an asset of $14.8 million, with an offsetting decrease in the fair value of the underlying debt. Interest expense for the years ended December 31, 2007, 2006 and 2005 reflects a $8.9 million loss, $5.2 million loss and $10.8 million benefit from these swap agreements, respectively.
Cash flow hedges - Interest Rate Swaps
Duncan Energy Partners had three interest rate swap agreements outstanding at December 31, 2007 that were accounted for as cash flow hedges.
(1)
Amounts receivable from or payable to the swap counterparties are settled every three months (the “settlement period”).
In September 2007, Duncan Energy Partners executed three floating-to-fixed interest rate swaps having a combined notional value of $175.0 million. The purpose of these financial instruments is to reduce the sensitivity of Duncan Energy Partners’ earnings to variable interest rates charged under its revolving credit facility. It recognized a $0.2 million benefit from these swaps in interest expense during 2007, which includes ineffectiveness of $0.2 million (an expense) and income of $0.4 million. In 2008, Duncan Energy Partners expects to reclassify $0.7 million of accumulated other comprehensive loss that was generated by these interest rate swaps as an increase to interest expense.
At December 31, 2007, the aggregate fair value of these interest rate swaps was a liability of $3.8 million. As cash flow hedges, any increase or decrease in fair value (to the extent effective) would be recorded into other comprehensive income and amortized into income based on the settlement period hedged. Any ineffectiveness is recorded directly into earnings as an increase in interest expense.
Cash flow hedges - Treasury locks
At times, we may use treasury lock financial instruments to hedge the underlying U.S. treasury rates related to our anticipated issuances of debt. A treasury lock is a specialized agreement that fixes the price (or yield) on a specific treasury security for an established period of time. A treasury lock purchaser is protected from a rise in the yield of the underlying treasury security during the lock period. Each of the treasury lock transactions was designated as a cash flow hedge under SFAS 133.
To the extent effective, gains and losses on the value of the treasury locks will be deferred until the forecasted debt is issued and will be amortized to earnings over the life of the debt. No ineffectiveness was recognized as of December 31, 2007. Gains or losses on the termination of such instruments are amortized to earnings using the effective interest method over the estimated term of the underlying fixed-rate debt. The following table summarizes changes in our treasury lock portfolio since December 31, 2005 (dollars in millions):
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.
The fair value of our commodity financial instrument portfolio, which primarily consisted of cash flow hedges, at December 31, 2007 was a liability of $19.3 million. During the years ended December 31, 2007, 2006 and 2005, we recorded a $28.6 million loss, $10.3 million income and $1.1 million income, respectively, related to our commodity financial instruments, which is included in operating costs and expenses on our Statements of Consolidated Operations. Included in the $28.6 million loss recorded during 2007, was ineffectiveness of $0.9 million (an expense) related to our commodity hedges. These contracts will terminate during 2008, and any amounts remaining in accumulated other comprehensive income will be recorded in earnings.
Foreign Currency Hedging Program
We are exposed to foreign currency exchange rate risk through our Canadian NGL marketing subsidiary and certain construction agreements with respect to our Pioneer processing plant 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.
Mark-to-market accounting is utilized for those foreign exchange contracts associated with our Canadian NGL marketing business. The duration of these contracts is typically one month. As of December 31, 2007, $4.7 million of these exchange contracts were outstanding, all of which settled in January 2008. In January 2008, we entered into $3.7 million of such instruments.
The foreign exchange contracts associated with our construction activities are accounted for using hedge accounting. At December 31, 2007, the fair value of these contracts was $1.3 million. These contracts settle through May 2008.
Fair Value Information
Cash and cash equivalents, accounts receivable, accounts payable and accrued expenses are carried at amounts which reasonably approximate their fair values due to their short-term nature. The estimated fair values of our fixed rate debt are based on quoted market prices for such debt or debt of similar terms and maturities. The carrying amounts of our variable rate debt obligations reasonably approximate their fair values due to their variable interest rates. The fair values associated with our interest rate and commodity hedging portfolios were developed using available market information and appropriate valuation techniques. The following table presents the estimated fair values of our financial instruments at the dates indicated:
(1)
Represent commodity financial instrument transactions that either have not settled or have settled and not been invoiced. Settled and invoiced transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction.
(2)
Relates to the hedging of our exposure to fluctuations in the Canadian dollar.
(3)
Represent interest rate hedging financial instrument transactions that have not settled. Settled transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction.
Note 8. Cumulative Effect of Changes in Accounting Principles
During the years ended December 31, 2006 and 2005, we recorded various amounts related to the cumulative effect of changes in accounting principles, including a benefit of $1.5 million in January 2006 related to the implementation of SFAS 123(R) and a charge of $4.2 million in December 2005 related to our implementation of FIN 47.
See Note 6 regarding the balance sheet impact of adopting SFAS 158 at December 31, 2006, which had no effect on net income.
Effect of Implementation of Staff Accounting Bulletin (“SAB”) 108
SAB 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” addresses how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. This SAB requires us to quantify errors using both a balance sheet and an income statement approach and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. The provisions of SAB 108 did not have a material impact on our consolidated financial statements.
Effect of Implementation of SFAS 123(R)
SFAS 123(R) requires us to recognize compensation expense related to unit-based 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 for equity-classified awards. Compensation 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. Liability awards will be cash settled upon vesting.
Upon adoption of SFAS 123(R), we recognized, as a benefit, the cumulative effect of a change in accounting principle of $1.5 million based on the SFAS 123(R) requirement to recognize compensation expense based upon the grant date fair value of unit-based awards and the application of an estimated forfeiture rate to unvested awards. See Notes 2 and 5 for additional information regarding our accounting for equity awards.
Effect of Implementation of FIN 47
In December 2005, we adopted FIN 47, “Accounting for Conditional Asset Retirement Obligations - An Interpretation for FAS 143,” which required us to record a liability for AROs in which the timing and/or amount of settlement of the obligation is uncertain. These conditional asset retirement obligations were not addressed in SFAS 143, which we adopted on January 1, 2003. We recorded a charge of $4.2 million in connection with our implementation of FIN 47, which represents the depreciation and accretion expense we would have recognized in prior periods had we recorded these conditional asset retirement obligations when incurred. See Note 10 for additional information regarding our AROs.
The following table shows unaudited pro forma net income for the years ended December 31, 2006 and 2005, assuming these accounting changes noted above were applied retroactively to January 1, 2005.
Note 9. Inventories
Our inventory amounts were as follows at the dates indicated:
(1)
Working inventory is comprised of inventories of natural gas, NGLs and certain petrochemical products that are either available-for-sale or used in the provision for services.
(2)
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 Statements of Consolidated Operations, include cost of sales amounts related to the sale of inventories. Our costs of sales were $14.5 billion, $11.8 billion and $10.3 billion for the years ended December 31, 2007, 2006 and 2005, respectively.
In those instances where we take ownership of inventory volumes through percent-of-liquids contracts and similar arrangements (as opposed to actually purchasing volumes for cash from third parties, see Note 4), these volumes are valued at market-related prices during the month in which they are acquired. We capitalize as a component of inventory those ancillary costs (e.g. freight-in and other handling and processing charges) incurred in connection with volumes obtained through such contracts.
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 and generally affect our segment operating results in the following manner:
§
Write-downs of NGL inventories are recorded as a cost of our NGL marketing activities within our NGL Pipelines & Services business segment;
§
Write-downs of natural gas inventories are recorded as a cost of our natural gas pipeline operations within our Onshore Natural Gas Pipelines & Services business segment; and
§
Write-downs of petrochemical inventories are recorded as a cost of our petrochemical marketing activities or octane additive production business within our Petrochemical Services business segment, as applicable.
For the years ended December 31, 2007, 2006 and 2005, we recognized LCM adjustments of approximately $13.3 million, $18.6 million and $21.9 million, respectively. To the extent our commodity hedging strategies address inventory-related risks and are successful, these inventory valuation adjustments are mitigated or offset. See Note 7 for a description of our commodity hedging activities.
Note 10. Property, Plant and Equipment
Our property, plant and equipment values and accumulated depreciation balances were as follows at the dates indicated:
(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).
The following table summarizes our depreciation expense and capitalized interest amounts for the periods indicated:
(1)
Depreciation expense is a component of operating costs and expenses as presented in our Statements of Consolidated Operations.
(2)
Capitalized interest increases the carrying value of the associated asset and reduces interest expense during the period it is recorded.
Asset retirement obligations
We have recorded asset retirement obligations related to legal requirements to perform retirement activities as specified in contractual arrangements and/or governmental regulations. In general, our asset retirement obligations primarily result from (i) right-of-way agreements associated with our pipeline operations, (ii) leases of plant sites and (iii) regulatory requirements triggered by the abandonment or retirement of certain underground storage assets and offshore facilities. In addition, our asset retirement obligations may result from the renovation or demolition of certain assets containing hazardous substances such as asbestos.
Previously, we recorded asset retirement obligations associated with the future retirement and removal activities of certain offshore assets located in the Gulf of Mexico. In December 2005, we adopted FIN 47 and recorded an additional $10.1 million in connection with conditional asset retirement obligations. The cumulative effect of this change in accounting principle for years prior to 2005 was a non-cash charge of $4.2 million. None of our assets are legally restricted for purposes of settling asset retirement obligations.
The following table presents information regarding our asset retirement obligations since December 31, 2005.
Property, plant and equipment at December 31, 2007 and 2006 includes $10.6 million and $3.0 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset. Also, based on information currently available, we estimate that accretion expense will approximate $2.0 million for each of the years 2008 and 2009, $2.1 million for 2010, $2.3 million for 2011 and $2.5 million for 2012.
Certain of our unconsolidated affiliates have AROs recorded at December 31, 2007 and 2006 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our financial statements.
Note 11. 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 16 for a general discussion of our business segments. The following table shows our investments in and advances to unconsolidated affiliates at the dates indicated.
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 December 31, 2007 and 2006, our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway, Nemo and Jonah included excess cost amounts totaling $43.8 million and $38.7 million, respectively, all of which were attributable to the fair value of the underlying tangible assets of these entities exceeding their book carrying values at the time of our acquisition of interests in these entities. To the extent that we attribute all or a portion of an excess cost amount to higher fair values, we amortize such excess cost as a reduction in equity earnings in a manner similar to depreciation. To the extent we attribute an excess cost amount to goodwill, we do not amortize this amount but it is subject to evaluation for impairment. Amortization of such excess cost amounts was $2.6 million, $2.1 million and $2.3 million for the years ended December 31, 2007, 2006 and 2005, respectively.
The following table presents our equity in income (loss) of unconsolidated affiliates for the periods indicated:
NGL Pipelines & Services
At December 31, 2007, our NGL Pipelines & Services segment included the following unconsolidated affiliates accounted for using the equity method:
VESCO. We own a 13.1% interest in VESCO, which owns a natural gas processing facility and related assets located in south Louisiana.
Promix. We own a 50.0% interest in Promix, which owns an NGL fractionation facility and related storage and pipeline assets located in south Louisiana.
BRF. We own an approximate 32.3% interest in BRF, which owns an NGL fractionation facility located in south Louisiana.
The combined balance sheet information for the last two years and results of operations data for the last three years of this segment’s current unconsolidated affiliates are summarized below.
Onshore Natural Gas Pipelines & Services
At December 31, 2007, our Onshore Natural Gas Pipelines & Services segment included the following unconsolidated affiliates accounted for using the equity method:
Evangeline. We own an approximate 49.5% aggregate interest in Evangeline, which owns a natural gas pipeline located in south Louisiana. A subsidiary of Acadian Gas, LLC owns the Evangeline interests, which were contributed to Duncan Energy Partners in February 2007 in connection with its initial public offering (see Note 17).
Coyote. We owned a 50.0% interest in Coyote during 2005, which owns a natural gas treating facility located in the San Juan Basin of southwestern Colorado. During 2006, we sold our interest in Coyote and recorded a gain on the sale of $3.3 million.
Jonah. Our equity interest in Jonah at December 31, 2007 is based on capital contributions we made to Jonah in connection with its Phase V expansion project through this date. We completed Phase I of this expansion in July 2007 entitling us to approximately 19.4% in earnings and ownership with the remaining 80.6% entitlement to TEPPCO. See Note 17 for additional information regarding our Jonah affiliate. Jonah owns the Jonah Gas Gathering System located in the Greater Green River Basin of southwestern Wyoming.
The combined balance sheet information for the last two years and results of operations data for the last three years of this segment’s current unconsolidated affiliates are summarized below.
Offshore Pipelines & Services
At December 31, 2007, our Offshore Pipelines & Services segment included the following unconsolidated affiliates accounted for using the equity method:
Poseidon. We own a 36.0% interest in Poseidon, which owns a crude oil pipeline that gathers production from the outer continental shelf and deepwater areas of the Gulf of Mexico for delivery to onshore locations in south Louisiana.
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. The Cameron Highway Oil Pipeline commenced operations during the first quarter of 2005.
Cameron Highway repaid its $365.0 million Series A notes and $50.0 million Series B notes in 2007 using cash contributions from its partners. We funded our 50% share of the capital contributions using borrowings under EPO’s Multi-Year Revolving Credit Facility. Cameron Highway incurred a $14.1 million make-whole premium in connection with the repayment of its Series A notes.
Deepwater Gateway. We own a 50.0% interest in Deepwater Gateway, which owns the Marco Polo platform located in the Gulf of Mexico. The Marco Polo platform processes crude oil and natural gas production from the Marco Polo, K2, K2 North and Ghengis Khan fields located in the South Green Canyon area of the Gulf of Mexico.
Neptune. We own a 25.7% interest in Neptune, which owns the Manta Ray Offshore Gathering and Nautilus Systems, which are natural gas pipelines located in the Gulf of Mexico.
Nemo. We own a 33.9% interest in Nemo, which owns the Nemo Gathering System, which is a natural gas pipeline located in the Gulf of Mexico.
In connection with obtaining regulatory approval for the GulfTerra Merger, we were required by the U.S. Federal Trade Commission to sell our ownership interest in Starfish by March 31, 2005. In March 2005, we sold this asset to a third-party for $42.1 million in cash and realized a gain on the sale of $5.5 million.
The combined balance sheet information for the last two years and results of operations data for the last three years of this segment’s current unconsolidated affiliates are summarized below.
Neptune owns the Manta Ray Offshore Gathering System (“Manta Ray”) and Nautilus Pipeline System (“Nautilus”). Manta Ray gathers natural gas originating from producing fields located in the Green Canyon, Southern Green Canyon, Ship Shoal, South Timbalier and Ewing Bank areas of the Gulf of Mexico to numerous downstream pipelines, including the Nautilus pipeline. Nautilus connects our Manta Ray pipeline to our Neptune natural gas processing plant located in south Louisiana. Due to a recent decrease in throughput volumes on the Manta Ray and Nautilus pipelines, we evaluated our 25.7% investment in Neptune for impairment during the third quarter of 2006. The decrease in throughput volumes is primarily due to underperformance of certain fields, natural depletion and hurricane-related delays in starting new production. These factors contributed to significant delays in throughput volumes Neptune expects to receive. As a result, Neptune has experienced operating losses in recent periods.
At December 31, 2005, the carrying value of our investment in Neptune was $68.1 million, which included $10.9 million of excess cost related to its original acquisition in 2001. Our review of Neptune’s estimated cash flows during the third quarter of 2006 indicated that the carrying value of our investment exceeded its fair value, which resulted in a non-cash impairment charge of $7.4 million. This loss is recorded as a component of “Equity in income of unconsolidated affiliates” in our Statement of Consolidated Operations for the year ended December 31, 2006. After recording this impairment charge, the carrying value of our investment in Neptune at December 31, 2006 was $58.8 million.
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 impairment charge of $7.0 million. This loss is recorded as a component of “Equity in income of unconsolidated affiliates” in our Statement of Consolidated Operations for the year ended December 31, 2007. After recording this impairment charge, the carrying value of our investment in Nemo at December 31, 2007 was $2.9 million.
Our investments in Neptune and Nemo were written down to fair value, which management estimated using recognized business valuation techniques. The fair value analysis is based upon management’s expectation of future cash flows, which incorporates certain industry information and assumptions made by management. For example, the individual reviews of Neptune and Nemo included management estimates regarding natural gas reserves of producers served by both Neptune and Nemo, respectively. If the assumptions underlying our fair value analysis change and expected cash flows are reduced, additional impairment charges may result.
Petrochemical Services
At December 31, 2007, our Petrochemical Services segment included the following unconsolidated affiliates accounted for using the equity method:
BRPC. We own a 30.0% interest in BRPC, which owns a propylene fractionation facility located in south Louisiana.
La Porte. We own an aggregate 50.0% interest in La Porte, which owns a propylene pipeline extending from Mont Belvieu, Texas to La Porte, Texas.
The combined balance sheet information for the last two years and results of operations data for the last three years of this segment’s current unconsolidated affiliates are summarized below.
Note 12. Business Combinations
2007 Transactions
Our expenditures for business combination during the year ended December 31, 2007 were $35.8 million, which primarily reflect the $35.0 million we spent to acquire the South Monco natural gas pipeline business (“South Monco”) in December 2007. This business includes approximately 128 miles of natural gas pipelines located in southeast Texas. The remaining business combination-related amounts for 2007 consist of purchase price adjustments to prior period transactions.
On a pro forma consolidated basis, our revenues, costs and expenses, operating income, net income and earnings per unit amounts would not have differed materially from those we actually reported for 2007 and 2006 due to immaterial nature of our 2007 business combination transactions.
We accounted for our 2007 business combinations using the purchase method of accounting and, accordingly, such costs have been allocated to assets acquired and liabilities assumed based on estimated preliminary fair values. Such preliminary values have been developed using recognized business valuation techniques and are subject to change pending a final valuation analysis. We expect to finalize the purchase price allocations for these transactions during 2008.
2006 Transactions
Our expenditures for business combinations during the year ended December 31, 2006 were $276.5 million and primarily reflect the Encinal and Piceance Creek acquisitions described below.
Encinal Acquisition. In July 2006, we acquired the Encinal and Canales natural gas gathering systems and related gathering and processing contracts that comprised the South Texas natural gas transportation and processing business of an affiliate of Lewis Energy Group, L.P. (“Lewis”). The aggregate value of total consideration we paid or issued to complete this business combination (referred to as the “Encinal acquisition”) was $326.3 million, which consisted of $145.2 million in cash and 7,115,844 of our common units.
The Encinal and Canales gathering systems are located in South Texas and are connected to over 1,450 natural gas wells producing from the Olmos and Wilcox formations. The Encinal system consists of 449 miles of pipeline, which is comprised of 277 miles of pipeline we acquired from Lewis in this transaction and 172 miles of pipeline that we own and had previously leased to Lewis. The Canales gathering system is comprised of 32 miles of pipeline. Currently, natural gas volumes gathered by the Encinal and Canales systems are transported by our existing Texas Intrastate System and are processed by our South Texas natural gas processing plants.
The Encinal and Canales gathering systems will be supported by a life of reserves gathering and processing dedication by Lewis related to its natural gas production from the Olmos formation. In addition, we entered into a 10-year agreement with Lewis for the transportation of natural gas treated at its proposed Big Reef facility. This facility will treat natural gas from the southern portion of the Edwards Trend in South Texas. We also entered into a 10-year agreement with Lewis for the gathering and processing of rich gas it produces from below the Olmos formation.
The total consideration we paid or granted to Lewis in connection with the Encinal acquisition is as follows:
In accordance with purchase accounting, the value of our common units issued to Lewis was based on the average closing price of such units immediately prior to and after the transaction was announced on July 12, 2006. For purposes of this calculation, the average closing price was $25.45 per unit.
Since the closing date of the Encinal acquisition was July 1, 2006, our Statements of Consolidated Operations do not include any earnings from these assets prior to this date. Given the relative size of the Encinal acquisition to our other business combination transactions during 2006, the following table presents selected pro forma earnings information for the years ended December 31, 2006 and 2005 as if the Encinal acquisition had been completed on January 1, 2006 and 2005, respectively, instead of July 1, 2006. This information was prepared based on financial data available to us and reflects certain estimates and assumptions made by our management. Our pro forma financial information is not necessarily indicative of what our consolidated financial results would have been had the Encinal acquisition actually occurred on January 1, 2005. The amounts shown in the following table are in millions, except per unit amounts.
Piceance Creek Acquisition. In December 2006, one of our affiliates, Enterprise Gas Processing, LLC, purchased a 100% interest in Piceance Creek Pipeline, LLC (“Piceance Creek”), for cash consideration of $100.0 million. Piceance Creek was wholly owned by EnCana Oil & Gas (“EnCana”).
The assets of Piceance Creek consist of a recently constructed 48-mile natural gas gathering pipeline, the Piceance Creek Gathering System, located in the Piceance Basin of northwestern Colorado. The Piceance Creek Gathering System has a transportation capacity of 1.6 billion cubic feet per day (“Bcf/d”) of natural gas and extends from a connection with EnCana’s Great Divide Gathering System located near Parachute, Colorado, northward through the heart of the Piceance Basin to our 1.5 Bcf/d Meeker natural gas treating and processing complex. Connectivity to EnCana’s Great Divide Gathering System will provide the Piceance Creek Gathering System with access to production from the southern portion of the Piceance basin, including production from EnCana’s Mamm Creek field. The Piceance Creek Gathering System was placed in service in January 2007 and began transporting initial volumes of approximately 300 million cubic feet per day (“MMcf/d”) of natural gas. Currently, we transport approximately 520 MMcf/d of natural gas volumes, with a significant portion of these volumes being produced by EnCana, one of the largest natural gas producers in the region. In conjunction with our acquisition of Piceance Creek, EnCana signed a long-term, fixed fee gathering agreement with us and dedicated significant production to the Piceance Creek Gathering System for the life of the associated lease holdings.
Other Transactions. In addition to the Encinal and Piceance Creek acquisitions, our business combinations during 2006 included the purchase of (i) an additional 8.2% ownership interest in Dixie for $12.9 million, (ii) all of the capital stock of an affiliated NGL marketing company located in Canada from related parties for $17.7 million (see Note 17) and (iii) a storage business in Flagstaff, Arizona for $0.7 million.
2005 Transactions
Our expenditures for business combinations during the year ended December 31, 2005 were $326.6 million. In January 2005, we acquired indirect ownership interests in the Indian Springs Gathering System and Indian Springs natural gas processing plant for $74.9 million. In January and February 2005, we acquired an additional 46% of the ownership interests in Dixie for $68.6 million. In June 2005, we acquired additional indirect ownership interests in our Mid-America Pipeline System and Seminole Pipeline for $25.0 million. Also in June 2005, we acquired an additional 41.7% ownership interest in Belle Rose, which owns a NGL pipeline located in Louisiana, for $4.4 million. In July 2005, we purchased three underground NGL storage facilities and four propane terminals from Ferrellgas L.P. (“Ferrellgas”) for $145.5 million in cash. Dixie and Belle Rose became consolidated subsidiaries of ours in 2005 as a result of our acquisition of additional ownership interests in these two entities.
Note 13. Intangible Assets and Goodwill
Identifiable Intangible Assets
The following table summarizes our intangible assets at the dates indicated:
We paid $11.2 million for certain air emission credits related to our Mont Belvieu complex in 2007. These items were recorded as intangible assets within our Petrochemical Services business segment.
The following table presents the amortization expense of our intangible assets by segment for the periods indicated:
Based on information currently available, we estimate that amortization expense associated with existing intangible assets will approximate $86.3 million in 2008, $80.4 million in 2009, $75.8 million in 2010, $70.1 million in 2011 and $60.7 million in 2012.
In general, our intangible assets fall within two categories - contract-based intangible assets and customer relationships. Contract-based intangible assets represent commercial rights we acquired in connection with business combinations or asset purchases. Customer relationship intangible assets represent customer bases that we acquired in connection with business combinations and asset purchases. The values assigned to intangible assets are amortized to earnings using either (i) a straight-line approach or (ii) other methods that closely resemble the pattern in which the economic benefits of associated resource bases are estimated to be consumed or otherwise used, as appropriate.
We acquired $141.3 million of intangible assets during the year ended December 31, 2006, primarily attributable to customer relationships we acquired in connection with the Encinal acquisition. The $132.9 million of intangible assets we acquired in connection with the Encinal acquisition (see Note 12) represents the value we assigned to customer relationships, particularly the long-term relationship we now have with Lewis through natural gas processing and gathering arrangements. We recorded $127.1 million in our NGL Pipelines & Services segment associated with processing arrangements and $5.8 million in our Onshore Natural Gas Pipelines & Services segment associated with gathering arrangements. These intangible assets will be amortized to earnings over a 20-year life using methods that closely resemble the pattern in which we estimate the depletion of the underlying natural gas resources to occur.
We acquired numerous customer relationship and contract-based intangible assets in connection with the GulfTerra Merger. The customer relationship intangible assets represent the exploration and production, natural gas processing and NGL fractionation customer bases served by GulfTerra and the South Texas midstream assets at the time the merger was completed. The contract-based intangible assets represent the rights we acquired in connection with discrete contracts to provide storage services for natural gas and NGLs that GulfTerra had entered into prior to the merger.
The value we assigned to these customer relationships is being amortized to earnings using methods that closely resemble the pattern in which the economic benefits of the underlying oil and natural gas resource bases from which the customers produce are estimated to be consumed or otherwise used. Our estimate of the useful life of each resource base is based on a number of factors, including reserve estimates, the economic viability of production and exploration activities and other industry factors. This group of intangible assets primarily consists of the (i) Offshore Pipelines & Platforms customer relationships; (ii) San Juan Gathering System customer relationships; (iii) Texas Intrastate pipeline customer relationships; and (iv) STMA and GulfTerra NGL Business customer relationships.
The contract-based intangible assets we acquired in connection with the GulfTerra Merger are being amortized over the estimated useful life (or term) of each agreement, which we estimate to range from two to eighteen years. This group of intangible assets consists of the (i) Petal and Hattiesburg natural gas storage contracts and (ii) Markham NGL storage contracts.
The Shell Processing Agreement grants us the right to process Shell’s (or its assignee’s) current and future production within the state and federal waters of the Gulf of Mexico. We acquired this
intangible asset in connection with our 1999 purchase of certain of Shell’s midstream energy assets located along the Gulf Coast. The value of the Shell Processing Agreement is being amortized on a straight-line basis over the remainder of its initial 20-year contract term through 2019.
Goodwill
Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction. Goodwill is not amortized; however, it is subject to annual impairment testing. The following table summarizes our goodwill amounts by segment at the dates indicated:
Goodwill recorded in connection with the GulfTerra Merger can be attributed to our belief (at the time the merger was consummated) that the combined partnerships would benefit from the strategic location of each partnership’s assets and the industry relationships that each possessed. In addition, we expected that various operating synergies could develop (such as reduced general and administrative costs and interest savings) that would result in improved financial results for the merged entity. Based on miles of pipelines, GulfTerra was one of the largest natural gas gathering and transportation companies in the United States, serving producers in the central and western Gulf of Mexico and onshore in Texas and New Mexico. These regions offer us significant growth potential through the acquisition and construction of additional pipelines, platforms, processing and storage facilities and other midstream energy infrastructure.
In 2006, the only significant change in goodwill was the recording of $95.2 million in connection with our preliminary purchase price allocation for the Encinal acquisition. Management attributes this goodwill to potential future benefits we may realize from our other south Texas processing and NGL businesses as a result of acquiring the Encinal business. Specifically, our acquisition of the long-term dedication rights associated with the Encinal business is expected to add value to our south Texas processing facilities and related NGL businesses due to increased volumes. The Encinal goodwill is recorded as part of the NGL Pipelines & Services business segment due to management’s belief that such future benefits will accrue to businesses classified within this segment.
The remainder of our goodwill amounts is associated with prior acquisitions, principally that of our purchase of a propylene fractionation business in February 2002 and our acquisition of indirect ownership interests in the Indian Springs natural gas gathering and processing business in January 2005.
Note 14. Debt Obligations
Our consolidated debt obligations consisted of the following at the dates indicated:
Letters of credit
At December 31, 2007, we had $1.1 million of standby letters outstanding under Duncan Energy Partners’ Revolving Credit Facility. At December 31, 2006, we had $49.9 million in standby letters of credit outstanding, all of which were issued under EPO’s Multi-Year Revolving Credit Facility. As of February 1, 2008, our standby letters of credit outstanding were $1.1 million under Duncan Energy Partners’ Revolving Credit Facility.
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 senior indebtedness is structurally subordinated to and ranks junior in right of payment to the indebtedness of GulfTerra and Dixie. This subordination feature exists only to the extent that the repayment of debt incurred by GulfTerra and Dixie is dependent upon the assets and operations of these two entities. The Dixie revolving credit facility is an unsecured obligation of Dixie (of which we own 74.2% of its capital stock). The senior subordinated notes of GulfTerra are unsecured obligations of GulfTerra (of which we own 100% of its limited and general partnership interests).
EPO’s debt obligations
Multi-Year Revolving Credit Facility. In November 2007, EPO executed an amended and restated Multi-Year Revolving Credit Facility totaling $1.75 billion, which replaced an existing $1.25 billion multi-year revolving credit agreement. Amounts borrowed under the amended and restated credit agreement mature in November 2012, although EPO is permitted, 30 to 60 days before the maturity date in effect, to convert the principal balance of the revolving loans then outstanding into a non-revolving, one-year term loan (the “term-out option”). There is no sublimit on the amount of standby letters of credit that can be outstanding under the amended facility. EPO’s borrowings under this agreement are unsecured general obligations that are non-recourse to EPGP. We have guaranteed repayment of amounts due under this revolving credit agreement through an unsecured guarantee.
As defined by the credit agreement, variable interest rates charged under this facility bear interest at a Eurodollar rate plus an applicable margin. In addition, EPO is required to pay a quarterly facility fee on each lender’s commitment irrespective of commitment usage.
The applicable margins will be increased by 0.100% per annum for each day that the total outstanding loans and letter of credit obligations under the facility exceeds fifty percent of the total lender commitments. Also, upon the conversion of the revolving loans to term loans pursuant to the term-out option described above, the applicable margin will increase by 0.125% per annum and, if immediately prior to such conversion, the total amount of outstanding loans and letter of credit obligations under the facility exceeds fifty percent of the total lender commitments, the applicable margin with respect to the term loans will increase by an additional 0.10% per annum.
EPO may increase the amount that may be borrowed under the facility, without the consent of the lenders, by an amount not exceeding $500.0 million by adding to the facility one or more new lenders and/or requesting that the commitments of existing lenders be increased, although none of the existing lenders has agreed to or is obligated to increase its existing commitment. EPO may request unlimited one-year extensions of the maturity date by delivering a written request to the administrative agent, but any such extension shall be effective only if consented to by the required lenders in their sole discretion.
The Multi-Year Revolving Credit Facility contains various covenants related to EPO’s ability to incur certain indebtedness; grant certain liens; enter into certain merger or consolidation transactions; and make certain investments. The loan agreement also requires EPO to satisfy certain financial covenants at the end of each fiscal quarter. The credit agreement also restricts EPO’s ability to pay cash distributions to us if a default or an event of default (as defined in the credit agreement) has occurred and is continuing at the time such distribution is scheduled to be paid.
Pascagoula MBFC Loan. In connection with the construction of our Pascagoula, Mississippi natural gas processing plant in 2000, EPO entered into a ten-year fixed-rate loan with the Mississippi Business Finance Corporation (“MBFC”). This loan is subject to a make-whole redemption right and is guaranteed by us through an unsecured and unsubordinated guarantee. The Pascagoula MBFC Loan contains certain covenants including the maintenance of appropriate levels of insurance on the Pascagoula facility.
The indenture agreement for this loan contains an acceleration clause whereby if EPO’s credit rating by Moody’s declines below Baa3 in combination with our credit rating at Standard & Poor’s declining below BBB-, the $54 million principal balance of this loan, together with all accrued and unpaid interest, would become immediately due and payable 120 days following such event. If such an event
occurred, we would have to either redeem the Pascagoula MBFC Loan or provide an alternative credit agreement to support our obligation under this loan.
Senior Notes B through L. These fixed-rate notes are unsecured obligations of EPO and rank equally with its existing and future unsecured and unsubordinated indebtedness. They are senior to any future subordinated indebtedness. EPO’s borrowings under these notes are non-recourse to EPGP. We have guaranteed repayment of amounts due under these notes through an unsecured and unsubordinated guarantee. Our guarantee of such notes is non-recourse to EPGP. The Senior Notes are subject to make-whole redemption rights and were issued under indentures containing certain covenants, which generally restrict EPO’s ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions.
EPO used net proceeds from its issuance of Senior Notes L to temporarily reduce indebtedness outstanding under its Multi-Year Revolving Credit Facility and for general partnership purposes. In October 2007, EPO used borrowing capacity under its Multi-Year Revolving Credit Facility to repay its $500.0 million Senior Notes E.
Petal GO Zone Bonds. In August 2007, Petal borrowed $57.5 million from the MBFC pursuant to a loan agreement and promissory note between Petal and the MBFC to pay a portion of the costs of certain natural gas storage facilities located in Petal, Mississippi. The promissory note between Petal and MBFC is guaranteed by EPO and supported by a letter of credit issued by Petal. On the same date, the MBFC issued $57.5 million in Gulf Opportunity Zone Tax-Exempt (“GO Zone”) bonds to various third parties. A portion of the GO Zone bond proceeds are being held by a third party trustee and reflected as a component of other assets on our balance sheet. The remaining proceeds held by the trustee will be released to us as we spend capital to complete the construction of the natural gas storage facilities. At December 31, 2007, $17.9 million of the GO Zone bond proceeds remained held by the third party trustee. The promissory note and the GO Zone bonds have identical terms including floating interest rates and maturities of twenty-seven years. The bonds and the associated tax incentives are authorized under the Mississippi Business Finance Act and the Gulf Opportunity Zone Act of 2005.
Petal MBFC Loan. In August 2007, Petal Gas Storage L.L.C. (“Petal”), a wholly owned subsidiary of EPO, entered into a loan agreement and a promissory note with the MBFC under which Petal may borrow up to $29.5 million. On the same date, the MBFC issued taxable bonds to EPO in the maximum amount of $29.5 million. As of December 31, 2007, there was $8.9 million outstanding under the loan and the bonds. EPO will make advances on the bonds to the MBFC and the MBFC will in turn make identical advances to Petal under the promissory note. The promissory note and the taxable bonds have identical terms including fixed interest rates of 5.90% and maturities of fifteen years. The bonds and the associated tax incentives are authorized under the Mississippi Business Finance Act. Petal may prepay on the promissory note without penalty, and thus cause the bonds to be redeemed, any time after one year from their date of issue. The loan and bonds are netted in preparing our consolidated balance sheet, as well the related interest expense and income amounts are netted in preparing our consolidated income statement.
Junior Notes A. In the third quarter of 2006, EPO sold $550.0 million in principal amount of fixed/floating, unsecured, long-term subordinated notes due 2066 (“Junior Notes A”). 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 A are subordinated to all of its current and future senior indebtedness (as defined in the related indenture agreement). We guaranteed EPO’s repayment of amounts due under Junior Notes A through an unsecured and subordinated guarantee.
The indenture agreement governing Junior Notes A allows EPO to defer interest payments on one or more occasions for up to ten consecutive years, subject to certain conditions. The indenture agreement also provides that, unless (i) all deferred interest on Junior Notes A has been paid in full as of the most recent interest payment date, (ii) no event of default under the indenture agreement has occurred and is continuing and (iii) we are not in default of our obligations under related guarantee agreements, neither we nor EPO cannot 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 subordinated to the Junior Notes A.
The Junior Notes A bear interest at a fixed annual rate of 8.375% from July 2006 to August 2016, payable semi-annually in arrears in February and August of each year, which commenced in February 2007. After August 2016, the Junior Notes A will bear variable rate interest at an annual rate equal to the 3-month LIBOR rate for the related interest period plus 3.708%, payable quarterly in arrears in February, May, August and November of each year commencing in November 2016. Interest payments may be deferred on a cumulative basis for up to ten consecutive years, subject to the certain provisions. The Junior Notes A mature in August 2066 and are not redeemable by EPO prior to August 2016 without payment of a make-whole premium.
In connection with the issuance of Junior Notes A, EPO entered into a Replacement Capital Covenant in favor of the covered debt holders (as defined in the underlying documents) pursuant to which EPO agreed for the benefit of such debt holders that it would not redeem or repurchase such junior notes unless such redemption or repurchase is made using proceeds from the of issuance of certain securities.
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 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 Junior Notes A.
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 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 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 neither we nor EPO would 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 a $198.9 million cash distribution to EPO and the remainder to pay debt issuance costs. At December 31, 2007, the principal balance outstanding under this facility was $200.0 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.
The Duncan Energy Partners’ credit facility contains certain financial and 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.
Dixie Revolving Credit Facility
As a result of acquiring a controlling interest in Dixie in February 2005, we began consolidating the financial statements of Dixie with those of our own. In accordance with GAAP, we consolidate the debt of Dixie with that of our own; however we do not have the obligation to make interest or debt payments with respect to Dixie’s debt. Dixie’s debt obligations consist of a senior, unsecured revolving credit facility having a borrowing capacity of $28.0 million. The maturity date of this facility was extended from June 2007 to June 2010 in August 2006.
As defined in the Dixie credit agreement, variable interest rates charged under this facility generally bear interest, at our election at the time of each borrowing, at either (i) a Eurodollar rate plus an applicable margin or (ii) the greater of (a) the Prime Rate or (b) the Federal Funds Rate plus 1/2%.
The credit agreement contains various covenants related to Dixie’s ability to incur certain indebtedness; grant certain liens; enter into merger transactions; and make certain investments. The loan agreement also requires Dixie to satisfy a minimum net worth financial covenant. The revolving credit agreement restricts Dixie’s ability to pay cash dividends to us and its other stockholders if a default or an event of default (as defined in the credit agreement) has occurred and its continuing at the time such dividend is scheduled to be paid.
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. As of December 31, 2007, there were no debt obligations outstanding under this credit facility.
Covenants
We are in compliance with the covenants of our consolidated debt agreements at December 31, 2007 and 2006.
Information regarding variable interest rates paid
The following table shows the range of interest rates paid and weighted-average interest rate paid on our consolidated variable-rate debt obligations during the year ended December 31, 2007.
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.
In accordance with SFAS 6, long-term and current maturities of debt reflect the classification of such obligations at December 31, 2006. With respect to the $500.0 million in principal that was due under Senior Notes E in October 2007, EPO repaid this note in October 2007 using cash and available credit capacity under its Multi-Year Revolving Credit Facility. The preceding table and our Consolidated Balance Sheet at 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 December 31, 2007, (ii) total debt of each unconsolidated affiliate at December 31, 2007 (on a 100% basis to the affiliate) and (iii) the corresponding scheduled maturities of such 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 December 31, 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. Cameron Highway repaid its debt obligations during the second quarter of 2007 using pro rata capital contributions from EPO and its joint venture partner in Cameron Highway.
The following information summarizes significant terms of the debt obligations of our unconsolidated affiliates at December 31, 2007:
Poseidon. Poseidon has $91.0 million outstanding under its $150.0 million revolving credit facility that matures in May 2011. Interest rates charged under this revolving credit facility are variable and depend on the ratio of Poseidon’s total debt to its earnings before interest, taxes, depreciation and amortization. This credit agreement is secured by substantially all of Poseidon’s assets. The variable interest rates charged on this debt at December 31, 2007 and 2006 were 6.62% and 6.68%, respectively.
Evangeline. At December 31, 2007, short and long-term debt for Evangeline consisted of (i) $13.2 million in principal amount of 9.90% fixed-rate Series B senior secured notes due December 2010 and (ii) a $7.5 million subordinated note payable. The Series B senior secured notes are collateralized by Evangeline’s property, plant and equipment; proceeds from a gas sales contract; and by a debt service reserve requirement. Scheduled principal repayments on the Series B notes are $5.0 million annually through 2009 with a final repayment in 2010 of approximately $3.2 million. The trust indenture governing the Series B notes contains covenants such as requirements to maintain certain financial ratios.
Evangeline incurred the subordinated note payable as a result of its acquisition of a contract-based intangible asset in the 1990s. This note is subject to a subordination agreement which prevents the repayment of principal and accrued interest on the note until such time as the Series B noteholders are either fully cash secured through debt service accounts or have been completely repaid. Variable rate interest accrues on the subordinated note at a Eurodollar rate plus 1/2%. The variable interest rates charged on this note at December 31, 2007 and 2006 were 5.88% and 6.08%, respectively. Accrued interest payable related to the subordinated note was $9.1 million and $7.9 million at December 31, 2007 and 2006, respectively.
Note 15. 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, EPGP.
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.
In August 2005, we revised our Partnership Agreement to allow EPGP, at its discretion, to elect not to make its proportionate capital contributions to us in connection with our issuance of limited partner interests, in which case its 2% general partner interest would be proportionately reduced. At the time of such offerings, EPGP has historically contributed cash to us to maintain its 2% general partner interest. EPGP made such cash contributions to us during the years ended December 31, 2007 and 2006. If EPGP exercises this option in the future, the amount of earnings we allocate to it and the cash distributions it receives from us will be reduced accordingly. If this occurs, EPGP can, under certain conditions, restore its full 2% general partner interest by making additional cash contributions to us.
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 EPGP in its sole discretion (subject, under certain circumstances, to the approval of our unitholders).
In August 2007, we filed a universal shelf registration statement with the SEC that allows us to issue an unlimited amount of debt and equity securities.
During 2003, we instituted a distribution reinvestment plan (“DRIP”). 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 the 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 16,102,737 common units have been issued under this registration statement through December 31, 2007.
We also have a registration statement on file related to our employee unit purchase plan, under which we can issue up to 1,200,000 common units. Under this plan, employees of EPCO can purchase our common units at a 10% discount through payroll deductions. A total of 495,661 common units have been issued to employees under this plan through December 31, 2007.
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 years ended December 31, 2007, 2006 and 2005:
Other offerings primarily represent the issuance of common units under our distribution reinvestment plan. Net proceeds received from our underwritten offerings completed during 2005 were generally used to repay an interim credit facility related to the GulfTerra Merger and to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility. Net proceeds from our other offerings were used for general partnership purposes.
Net proceeds received from our underwritten and other offerings completed during 2006 were used to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and for general partnership purposes.
Net proceeds received from our other offerings completed during 2007 were used to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and for general partnership purposes.
Summary of Changes in Outstanding Units
The following table summarizes changes in our outstanding units since December 31, 2004:
Treasury Units. In 2000, we and a consolidated trust (the “1999 Trust”) were authorized by EPGP to repurchase up to 2,000,000 publicly-held common units under an announced buy-back program. The repurchases would be made during periods of temporary market weakness at price levels that would be accretive to our remaining unitholders. After deducting for repurchases under the program in prior periods, we and the 1999 Trust could repurchase up to 618,400 common units at December 31, 2005. We cancelled our 427,200 treasury units in 2005.
Summary of Changes in Limited Partners’ Equity
The following table details the changes in limited partners’ equity since December 31, 2004:
In October 2006, we acquired all of the capital stock of an affiliated NGL marketing company located in Canada from EPCO and Dan L. Duncan for $17.7 million in cash. The amount we paid for this business exceeded the carrying values of the assets acquired and liabilities assumed from this related party (which is under common control with us) by $6.3 million, of which $6.2 million was allocated to limited partners and $0.1 million to our general partner. The excess of the acquisition price over the net book value of this business at the time of acquisition is treated as a deemed distribution to our owners and presented as an “Acquisition-related disbursement of cash” in our Statement of Partners’ Equity for the year ended December 31, 2006. The total purchase price is a component of “Cash used for business combinations” as presented in our Statement of Consolidated Cash Flows for the year ended December 31, 2006 (see Note 12).
Distributions to Partners
The percentage interest of EPGP 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. EPGP’s quarterly incentive distribution thresholds are as follows:
We paid incentive distributions of $107.4 million, $86.7 million and $63.9 million to EPGP during the years ended December 31, 2007, 2006 and 2005, respectively.
The following table presents our declared quarterly cash distribution rates per unit since the first quarter of 2006 and the related record and distribution payment dates. The quarterly cash distribution rates per unit correspond to the fiscal quarters indicated. Actual cash distributions are paid within 45 days after the end of such fiscal quarter.
Accumulated Other Comprehensive Income
The following table presents the components of accumulated other comprehensive income at the dates indicated:
(1)
See Note 2 for additional information regarding these components of accumulated other comprehensive income.
(2)
See Note 6 for additional information regarding pension and postretirement benefit plans.
Note 16. 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 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 shows our measurement of total segment gross operating margin for the periods indicated:
(1)
These amounts are taken from our Statements of Consolidated Operations.
(2)
These non-cash expenses are taken from the operating activities section of our 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 changes in accounting principles follows:
Information by segment, together with reconciliations to our consolidated totals, is presented in the following table:
In general, our historical operating results and/or financial position have been affected by business combinations and other acquisitions. The operating results of entities and assets we acquire are included in our financial results prospectively from their purchase dates.
Note 17. Related Party Transactions
The following table summarizes our related party transactions for the periods indicated.
We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties.
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 a part of our consolidated group of companies:
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EPCO and its private company subsidiaries;
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EPGP, our sole general partner;
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Enterprise GP Holdings, which owns and controls our general partner;
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TEPPCO, which is owned and controlled by Enterprise GP Holdings;
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the Employee Partnerships (see Note 5); and
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Energy Transfer Equity, an equity method investment of Enterprise GP Holdings.
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. A description of our relationship with Duncan Energy Partners is presented within this Note 17.
EPCO is a private company controlled by Dan L. Duncan, who is also a Director and Chairman of EPGP, our general partner. At December 31, 2007, EPCO and its affiliates beneficially owned 147,986,045 (or 34.0%) of our outstanding common units, which includes 13,454,498 of our common units owned by Enterprise GP Holdings. In addition, at December 31, 2007, EPCO and its affiliates beneficially owned 77.1% 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 EPGP. The principal business activity of EPGP is to act as our managing partner. The executive officers and certain of the directors of EPGP and EPE Holdings are employees of EPCO.
As our general partner, EPGP received cash distributions of $124.4 million, $101.8 million and $76.8 million from us during the years ended December 31, 2007, 2006 and 2005, respectively. These amounts include incentive distributions of $107.4 million, $86.7 million and $63.9 million for the years ended December 31, 2007, 2006 and 2005, respectively.
We and EPGP 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 and affiliates 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. EPCO and its private company affiliates received $355.5 million, $306.5 million and $243.9 million in cash distributions from us and Enterprise GP Holdings during the years ended December 31, 2007, 2006 and 2005, 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, TEPPCO and us.
We have entered into an agreement with EPCO to provide trucking services to us for the transportation of NGLs and other products. For the years ended December 31, 2007, 2006 and 2005, we paid this trucking affiliate $17.5 million, $20.7 million and $17.6 million, respectively, for such services.
We lease office space in various buildings from affiliates of EPCO. The rental rates in these lease agreements approximate market rates. For the years ended December 31, 2007, 2006 and 2005, we paid EPCO $5.6 million, $3.0 million and $2.7 million, respectively, for office space leases.
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. For the year ended December 31, 2005 our revenues from this former affiliate were $0.3 million and our purchases were $61.0 million. For the nine months ended September 30, 2006, our revenues from this former affiliate were $55.8 million and our purchases were $43.4 million.
EPCO Administrative Services Agreement
We have no employees. All of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to an administrative services agreement (the “ASA”). We, Duncan Energy Partners, Enterprise GP Holdings, TEPPCO and our respective general partners are parties to the ASA. The significant terms of the ASA are as follows:
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EPCO will provide selling, general and administrative services, and management and operating services, as may be necessary to manage and operate our businesses, properties and assets (all in accordance with prudent industry practices). EPCO will employ or otherwise retain the services of such personnel as may be necessary to provide such services.
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We are required to reimburse EPCO for its services in an amount equal to the sum of all costs and expenses incurred by EPCO which are directly or indirectly related to our business or activities (including expenses reasonably allocated to us by EPCO). In addition, we have agreed to pay all sales, use, excise, value added or similar taxes, if any, that may be applicable from time to time in respect of the services provided to us by EPCO.
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EPCO will allow us to participate as named insureds in its overall insurance program, with the associated premiums and other costs being allocated to us.
Under the ASA, EPCO subleases to us (for $1 per year) certain equipment which it holds pursuant to operating leases and has assigned to us its purchase option under such leases (the “retained leases”).
EPCO remains liable for the actual cash lease payments associated with these agreements. We record the full value of these payments made by EPCO on our behalf as a non-cash related party operating lease expense, with the offset to partners’ equity accounted for as a general contribution to our partnership. At December 31, 2007, the retained leases were for a cogeneration unit and approximately 100 railcars. Should we decide to exercise the purchase options associated with the retained leases, $2.3 million would be payable in 2008 and $3.1 million in 2016.
Our operating costs and expenses for the years ended December 31, 2007, 2006 and 2005 include reimbursement payments to EPCO for the costs it incurs to operate our facilities, including compensation of employees. We reimburse EPCO for actual direct and indirect expenses it incurs related to the operation of our assets. These reimbursements were $273.0 million, $285.4 million and $273.8 million during the years ended December 31, 2007, 2006 and 2005, respectively.
Likewise, our general and administrative costs for the years ended December 31, 2007, 2006 and 2005 include amounts we reimburse to EPCO for administrative services, including compensation of employees. In general, our reimbursement to EPCO for administrative services is either (i) on an actual basis for direct expenses it may incur on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to ASA based on the estimated use of such services by each party (e.g., the allocation of general legal or accounting salaries based on estimates of time spent on each entity’s business and affairs). These reimbursements were $56.5 million, $41.3 million and $41.0 million during the years ended December 31, 2007, 2006 and 2005, respectively.
The ASA also addresses potential conflicts that may arise among Enterprise Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), Duncan Energy Partners (including DEP GP), and the EPCO Group. The EPCO Group includes EPCO and its other affiliates, but excludes Enterprise Products Partners, Enterprise GP Holdings, Duncan Energy Partners and their respective general partners. With respect to potential conflicts, the ASA provides, among other things, that:
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If a business opportunity to acquire “equity securities” (as defined below) is presented to the EPCO Group, Enterprise Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), Duncan Energy Partners (including DEP GP), then Enterprise GP Holdings will have the first right to pursue such opportunity. The term “equity securities” is defined to include:
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general partner interests (or securities which have characteristics similar to general partner interests) or interests in “persons” that own or control such general partner or similar interests (collectively, “GP Interests”) and securities convertible, exercisable, exchangeable or otherwise representing ownership or control of such GP Interests; and
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incentive distribution rights and limited partner interests (or securities which have characteristics similar to incentive distribution rights or limited partner interests) in publicly traded partnerships or interests in “persons” that own or control such limited partner or similar interests (collectively, “non-GP Interests”); provided that such non-GP Interests are associated with GP Interests and are owned by the owners of GP Interests or their respective affiliates.
Enterprise GP Holdings will be presumed to want to acquire the equity securities until such time as EPE Holdings advises the EPCO Group, EPGP and DEP GP that it has abandoned the pursuit of such business opportunity. In the event that the purchase price of the equity securities is reasonably likely to equal or exceed $100 million, the decision to decline the acquisition will be made by the Chief Executive Officer of EPE Holdings after consultation with and subject to the approval of the ACG Committee of EPE Holdings. If the purchase price is reasonably likely to be less than $100 million, the Chief Executive Officer of EPE Holdings may make the determination to decline the acquisition without consulting the ACG Committee of EPE Holdings.
In the event that Enterprise GP Holdings abandons the acquisition and so notifies the EPCO Group, EPGP and DEP GP, Enterprise Products Partners will have the second right to pursue such
acquisition. Enterprise Products Partners will be presumed to want to acquire the equity securities until such time as EPGP advises the EPCO Group and DEP GP that Enterprise Products Partners has abandoned the pursuit of such acquisition. In determining whether or not to pursue the acquisition, Enterprise Products Partners will follow the same procedures applicable to Enterprise GP Holdings, as described above but utilizing EPGP’s Chief Executive Officer and ACG Committee.
In its sole discretion, Enterprise Products Partners may affirmatively direct such acquisition opportunity to Duncan Energy Partners. In the event this occurs, Duncan Energy Partners may pursue such acquisition.
In the event Enterprise Products Partners abandons the acquisition opportunity for the equity securities and so notifies the EPCO Group and DEP GP, the EPCO Group may pursue the acquisition or offer the opportunity to TEPPCO (including TEPPCO GP) and their controlled affiliates, in either case, without any further obligation to any other party or offer such opportunity to other affiliates.
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If any business opportunity not covered by the preceding bullet point (i.e. not involving “equity securities”) is presented to the EPCO Group, Enterprise Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), or Duncan Energy Partners (including DEP GP), Enterprise Products Partners will have the first right to pursue such opportunity either for itself or, if desired by Enterprise Products Partners in its sole discretion, for the benefit of Duncan Energy Partners. It will be presumed that Enterprise Products Partners will pursue the business opportunity until such time as its general partner advises the EPCO Group, EPE Holdings and DEP GP that it has abandoned the pursuit of such business opportunity.
In the event the purchase price or cost associated with the business opportunity is reasonably likely to equal or exceed $100 million, any decision to decline the business opportunity will be made by the Chief Executive Officer of EPGP after consultation with and subject to the approval of the ACG Committee of EPGP. If the purchase price or cost is reasonably likely to be less than $100 million, the Chief Executive Officer of EPGP may make the determination to decline the business opportunity without consulting EPGP’s ACG Committee.
In its sole discretion, Enterprise Products Partners may affirmatively direct such acquisition opportunity to Duncan Energy Partners. In the event this occurs, Duncan Energy Partners may pursue such acquisition.
In the event that Enterprise Products Partners abandons the business opportunity for itself and Duncan Energy Partners and so notifies the EPCO Group, EPE Holdings and DEP GP, Enterprise GP Holdings will have the second right to pursue such business opportunity. It will be presumed that Enterprise GP Holdings will pursue such acquisition until such time as its general partner declines such opportunity (in accordance with the procedures described above for Enterprise Products Partners) and advises the EPCO Group that it has abandoned the pursuit of such business opportunity. Should this occur, the EPCO Group may either pursue the business opportunity or offer the business opportunity to TEPPCO (including TEPPCO GP) and their controlled affiliates without any further obligation to any other party or offer such opportunity to other affiliates.
None of Enterprise Products Partners, Enterprise GP Holdings, Duncan Energy Partners or their respective general partners or the EPCO Group have any obligation to present business opportunities to TEPPCO (including TEPPCO GP) or their controlled affiliates. Likewise, TEPPCO (including TEPPCO GP) and their controlled affiliates have no obligation to present business opportunities to Enterprise Products Partners, Enterprise GP Holdings, Duncan Energy Partners or their respective general partners or the EPCO Group.
Relationship with TEPPCO
TEPPCO became a related party to us in February 2005 in connection with the acquisition of TEPPCO GP by a private company subsidiary of EPCO. In May 2007, Enterprise GP Holdings purchased TEPPCO GP from this private company subsidiary of EPCO.
We received $67.6 million, $42.9 million and a nominal amount from TEPPCO during the years ended December 31, 2007, 2006 and 2005, respectively, from the sale of hydrocarbon products. We paid TEPPCO $19.4 million, $24.0 million and $17.2 million for NGL pipeline transportation and storage services during the years ended December 31, 2007, 2006 and 2005, respectively.
Purchase of Pioneer I plant from TEPPCO. In March 2006, we paid TEPPCO $38.2 million for its Pioneer I natural gas processing plant located in Opal, Wyoming and certain natural gas processing rights related to natural gas production from the Jonah and Pinedale fields located in the Greater Green River Basin in Wyoming. After an in-depth consideration of all relevant factors, this transaction was approved by the ACG Committee of our general partner and the Audit and Conflicts Committee of the general partner of TEPPCO. In addition, each party received a fairness opinion rendered by an independent advisor. TEPPCO will have no continued involvement in the contracts or in the operations of the Pioneer facility.
Jonah Joint Venture with TEPPCO. In August 2006, we became a joint venture partner with TEPPCO in its Jonah Gas Gathering Company (“Jonah”), which owns the Jonah Gas 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 entered into in February 2006. In connection with the joint venture arrangement, we and TEPPCO plan to continue the Phase V expansion, which is expected to increase the capacity of the Jonah Gathering System from 1.5 Bcf/d to 2.4 Bcf/d and 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 has increased the system gathering capacity to 2.0 Bcf/d, was completed in July 2007 and the final phase of this expansion is expected to be completed by April 2008. The total anticipated cost of the Phase V expansion is expected to be approximately $505.0 million. We continue to manage the Phase V construction project.
Since August 1, 2006, we and TEPPCO have equally shared in the construction costs of the Phase V expansion. TEPPCO has reimbursed us $261.6 million, which represents 50% of total Phase V costs incurred through December 31, 2007. We had a receivable of $9.9 million from TEPPCO at December 31, 2007 for Phase V expansion costs.
TEPPCO was entitled to all distributions from the joint venture until specified milestones were achieved, at which point, we became entitled to receive 50% of the incremental cash flow from portions of the system placed in service as part of the expansion. Since the first phase of this expansion was reached in July 2007, we and TEPPCO have shared earnings based on a formula that takes into account our respective capital contributions, including expenditures by TEPPCO prior to the expansion.
At December 31, 2007, we owned an approximate 19.4% interest in Jonah and TEPPCO owns 80.6%. We operate the Jonah system. We account for our investment in the Jonah joint venture using the equity method.
The Jonah joint venture is governed by a management committee comprised of two representatives approved by us and two appointed by TEPPCO, each with equal voting power. After an in-depth consideration of all relevant factors, this transaction was approved by the ACG Committee of our general partner and the Audit and Conflicts Committee of the general partner of TEPPCO. The ACG Committee of our general partner received a fairness opinion in connection with this transaction. The
transaction was reviewed and recommended for approval by the Audit and Conflicts Committee of TEPPCO GP with assistance from an independent financial advisor.
We have agreed to indemnify TEPPCO from any and all losses, claims, demands, suits, liabilities, costs and expenses arising out of or related to breaches of our representations, warranties, or covenants related to the Jonah joint venture. A claim for indemnification cannot be filed until the losses suffered by TEPPCO exceed $1.0 million. The maximum potential amount of future payments under the indemnity agreement is limited to $100.0 million. All indemnity payments are net of insurance recoveries that TEPPCO may receive from third-party insurance carriers. We carry insurance coverage that may offset any payments required under the indemnification.
Purchase of Houston-area pipelines from TEPPCO. In October 2006, we purchased certain idle pipeline assets in the Houston, Texas area from TEPPCO for $11.7 million in cash. The acquired pipelines became part of our Texas Intrastate System. The purchase of this asset was in accordance with the Board-approved management authorization policy.
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. This pipeline segment is part of the DEP South Texas NGL Pipeline System that commenced operations in January 2007. In addition, we entered into a lease with TEPPCO for an 11-mile interconnecting pipeline located in the Houston area that is part of the DEP South Texas NGL Pipeline System. Although the primary term of the lease expired in September 2007, it is being renewed on a month-to-month basis until construction of a parallel pipeline is completed in early 2008. These transactions were in accordance with the Board-approved management authorization policy.
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 eight months ended December 31, 2007, we recorded $294.4 million of revenues from Energy Transfer Partners, L.P. (“ETP”), primarily from NGL marketing activities. We incurred $35.2 million in operating costs and expenses for the eight months ended December 31, 2007. 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
Many of our unconsolidated affiliates perform supporting or complementary roles to our other business operations. See Note 16 of the Notes to Consolidated Financial Statements for a discussion of this alignment of commercial interests. Since we and our affiliates hold ownership interests in these entities and directly or indirectly benefit from our related party transactions with such entities, they are presented here.
The following information summarizes significant related party transactions with our current unconsolidated affiliates:
Relationship with Duncan Energy Partners
In September 2006, we formed a consolidated subsidiary, Duncan Energy Partners, to acquire, own and operate a diversified portfolio of midstream energy assets and to support the growth objectives of EPO. On February 5, 2007, this subsidiary completed its initial public offering of 14,950,000 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 Enterprise Products Partners (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.
In addition to the 34% direct ownership interest we retained in certain subsidiaries of Duncan Energy Partners, we also own the 2% general partner interest in Duncan Energy Partners and 26.4% of Duncan Energy Partners’ outstanding common units. EPO directs the business operations of Duncan Energy Partners through its control of Duncan Holdings, LLC (“DEP GP”). Certain of our officers and directors are also beneficial owners of common units of Duncan Energy Partners (see Item 12).
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.
We have significant involvement with all of the subsidiaries of Duncan Energy Partners, including the following types of transactions: (i) we utilize storage services provided by Mont Belvieu Caverns to support our Mont Belvieu fractionation and other businesses; (ii) we buy natural gas from and sell natural gas to Acadian Gas in connection with our normal business activities; and (iii) we are the sole shipper on the DEP South Texas NGL Pipeline System.
We may contribute other equity interests in our subsidiaries to Duncan Energy Partners in the near term and use the proceeds we receive from Duncan Energy Partners to fund our capital spending program.
For additional information regarding Duncan Energy Partners, see “Other Items - Initial Public Offering of Duncan Energy Partners” under Item 7 of this annual report.
Omnibus Agreement. On February 5, 2007, EPO and Duncan Energy Partners entered into an Omnibus Agreement that governs our relationship with Duncan Energy Partners on the following matters:
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indemnification for certain environmental liabilities, tax liabilities and right-of-way defects;
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reimbursement of certain expenditures incurred by DEP South Texas NGL and Mont Belvieu Caverns;
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a right of first refusal to EPO in Duncan Energy Partners’ current and future subsidiaries and a right of first refusal on the material assets of these entities, other than sales of inventory and other assets in the ordinary course of business; and
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a preemptive right with respect to equity securities issued by certain of Duncan Energy Partners’ subsidiaries, other than as consideration in an acquisition or in connection with a loan or debt financing.
EPO has indemnified Duncan Energy Partners against certain pre-February 2007 environmental and related liabilities associated with the assets EPO contributed to Duncan Energy Partners at the time of its initial public offering. These liabilities include both known and unknown environmental and related liabilities. This indemnification obligation will terminate on February 5, 2010. There is an aggregate cap of $15.0 million on the amount of indemnity coverage. In addition, Duncan Energy Partners is not entitled to indemnification until the aggregate amount of claims it incurs exceeds $250 thousand. Liabilities resulting from a change of law after February 5, 2007 are excluded from the EPO environmental indemnity. In addition, EPO has indemnified Duncan Energy Partners for liabilities related to:
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certain defects in the easement rights or fee ownership interests in and to the lands on which any assets contributed to Duncan Energy Partners in connection with its initial public offering are located and failure to obtain certain consents and permits necessary to conduct its business that arise through February 5, 2010; and
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certain income tax liabilities attributable to the operation of the assets contributed to Duncan Energy Partners in connection with its initial public offering prior to February 5, 2007.
The Omnibus Agreement may not be amended without the prior approval of the ACG Committee if the proposed amendment will, in the reasonable discretion of DEP GP, adversely affect holders of the it’s common units.
Neither we, nor EPO and any of its affiliates are restricted under the Omnibus Agreement from competing with Duncan Energy Partners. Except as otherwise expressly agreed in the EPCO administrative services agreement, EPO and any of its affiliates may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer Duncan Energy Partners the opportunity to purchase or construct those assets. These agreements are in addition to other agreements relating to business opportunities and potential conflicts of interest set forth in the administrative services agreement with EPO, EPCO and other affiliates of EPCO.
In certain cases, EPO is responsible for funding 100% of project costs rather than sharing such costs with Duncan Energy Partners in accordance with the existing sharing ratio of 66% funded by Duncan Energy Partners and 34% funded by EPO. Under the Omnibus Agreement, EPO agreed to make additional contributions to Duncan Energy Partners as reimbursement for Duncan Energy Partners’ 66% share of any excess project costs above (i) the $28.6 million of estimated project costs to complete the Phase II expansions of the DEP South Texas NGL Pipeline System and (ii) $14.1 million of estimated project costs for additional Mont Belvieu brine production capacity and above-ground storage reservoir projects. These projects were in progress at the time of Duncan Energy Partners’ initial public offering. In December 2007, EPO made cash contributions totaling $9.9 million to Duncan Energy Partners’ subsidiaries in connection with the Omnibus Agreement.
In December 2007, EPO made an additional $38.1 million cash contribution to Mont Belvieu Caverns for capital expenditures in which Duncan Energy Partners is not a participant. This contribution was in accordance with provisions of the Mont Belvieu Caverns’ limited liability company agreement, which states that when Duncan Energy Partners elects to not participate in certain projects, then EPO is responsible for funding 100% of such projects. To the extent such non-participated projects generate incremental earnings for Mont Belvieu Caverns in the future, the sharing ratio for Mont Belvieu Caverns will be adjusted to allocate such incremental cash flows to EPO. Under the terms of the agreement, Duncan Energy Partners may elect to reacquire for consideration a 66% share of these projects at a later date.
Note 18. Provision for Income Taxes
Our provision for income taxes relates primarily to federal and state income taxes of Seminole and Dixie, our two largest corporations subject to such income taxes. In addition, with the amendment of the Texas Franchise Tax in 2006, we have become a taxable entity in the state of Texas. Our federal and state income tax provision is summarized below:
A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows:
Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2007 and 2006 are as follows:
We had net operating loss carryovers of $23.3 million and $19.2 million at December 31, 2007 and 2006, respectively. These losses expire in various years between 2008 and 2028 and are subject to limitations on their utilization. We record a valuation allowance to reduce our deferred tax assets to the amount of future tax benefit that is more likely than not to be realized. The valuation allowance was $5.3 million and $3.0 million at December 31, 2007 and 2006, respectively, and serves to reduce the recognized tax benefit associated with carryovers of our corporate entities to an amount that will, more likely than not, be realized. The $2.3 million increase in valuation allowance for 2007 is comprised primarily of $1.6 million for Canadian Enterprise Gas Products, Ltd.
On May 18, 2006, the State of Texas enacted House Bill 3 which revised the pre-existing state franchise tax. In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits.
Although the bill states that the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. Due to the enactment of the Revised Texas Franchise Tax, we recorded a net deferred tax liability of $3.8 million and $6.6 million during the years ended December 31, 2007 and 2006, respectively. The offsetting net charge of $3.8 million and $6.6 million is shown on our Statement of Consolidated Operations for the years ended December 31, 2007 and 2006, respectively, as a component of provision for income taxes.
Note 19. 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 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 EPGP for the periods indicated:
The following table presents our calculation of basic and diluted earnings per unit for the periods indicated:
Note 20. Commitments and Contingencies
Litigation
On occasion, we or our unconsolidated affiliates are named as defendants 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 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 17 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 hopeful that an expeditious resolution of this civil matter acceptable to all parties will be reached in the near future. Magellan has agreed to indemnify EPO for the civil matter. On September 4, 2007, we and the DOJ entered into a plea agreement whereby a wholly-owned subsidiary of EPO, Mapletree, LLC, pleaded guilty to a misdemeanor charge of negligence in connection with the releases and paid a fine of $1.0 million. The plea agreement concludes the DOJ’s criminal investigation into the ammonia releases. At this time, we do not believe that a final resolution of the civil claims by the ENRD will have a material impact on our consolidated financial position, cash flows or results of operations.
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, cash flows or results of operations.
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.
Contractual Obligations
The following table summarizes our various contractual obligations at December 31, 2007. A description of each type of contractual obligation follows:
Scheduled Maturities of Long-Term Debt. We have long-term and short-term payment obligations under debt agreements such as the indentures governing EPO’s senior notes and the credit agreement governing EPO’s Multi-Year Revolving Credit Facility. Amounts shown in the preceding table represent our scheduled future maturities of debt principal for the periods indicated. See Note 14 for additional information regarding our consolidated debt obligations.
Operating Lease Obligations. We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Amounts shown in the preceding table represent minimum cash lease payment obligations under our operating leases with terms in excess of one year.
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, (iii) a railcar unloading terminal in Mont Belvieu, Texas and (iv) land held pursuant to right-of-way agreements. In general, our material lease agreements have original terms that range from 2 to 28 years and include renewal options that could extend the agreements for up to an additional 20 years.
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. We are generally required to perform routine maintenance on the underlying leased assets. In addition, certain leases give us the option to make leasehold improvements. Maintenance and repairs of leased assets resulting from our operations are charged to expense as incurred. We did not make any significant leasehold improvements during the years ended December 31, 2007, 2006 or 2005; however, we did incur $9.3 million of repair costs associated with our lease of an underground natural gas storage facility in 2006.
The operating lease commitments shown in the preceding table exclude the non-cash, related party expense associated with equipment leases contributed to us by EPCO at our formation (the “retained leases”). EPCO remains liable for the actual cash lease payments associated with these agreements, which it accounts for as operating leases. At December 31, 2007, the retained leases were for a cogeneration unit and approximately 100 railcars. EPCO’s minimum future rental payments under these leases are $2.1 million for 2008, $0.7 million for each of the years 2009 through 2015 and $0.3 million for 2016. We record the full value of these payments made by EPCO on our behalf as a non-cash related party operating lease expense, with the offset to partners’ equity accounted for as a general contribution to our partnership.
The retained lease agreements contain lessee purchase options, which are at prices that approximate fair value of the underlying leased assets. EPCO has assigned these purchase options to us.
Should we decide to exercise the remaining purchase options, up to an additional $2.3 million would be payable in 2008 and $3.1 million in 2016.
Lease and rental expense included in operating costs and expenses was $38.5 million, $39.3 million and $34.9 million during the years ended December 31, 2007, 2006 and 2005, respectively.
Purchase Obligations. We define a purchase obligation as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We have classified our unconditional purchase obligations into the following categories:
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We have long and short-term product purchase obligations for NGLs, certain petrochemicals and natural gas with third-party suppliers. The prices that we are obligated to pay under these contracts approximate market prices at the time we take delivery of the volumes. The preceding table shows our volume commitments and estimated payment obligations under these contracts for the periods indicated. Our estimated future payment obligations are based on the contractual price under each contract for purchases made at December 31, 2007 applied to all future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. At December 31, 2007, we do not have any product purchase commitments with fixed or minimum pricing provisions with remaining terms in excess of one year.
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We have long and short-term commitments to pay third-party providers for services such as equipment maintenance agreements. Our contractual payment obligations vary by contract. The preceding table shows our future payment obligations under these service contracts.
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We have short-term payment obligations relating to our capital projects and those of our unconsolidated affiliates. These commitments represent unconditional payment obligations to vendors for services rendered or products purchased. The preceding table presents our share of such commitments for the periods indicated.
Commitments under equity compensation plans of EPCO
In accordance with our agreements with EPCO, we reimburse EPCO for our share of its compensation expense associated with certain employees who perform management, administrative and operating functions for us (see Note 17). This includes costs associated with unit option awards granted to these employees to purchase our common units. At December 31, 2007, there were 2,315,000 unit options outstanding for which we were responsible for reimbursing EPCO for the costs of such awards.
The weighted-average strike price of unit option awards outstanding at December 31, 2007 was $26.18 per common unit. At December 31, 2007, 335,000 of these unit options were exercisable. An additional 285,000, 380,000, 510,000 and 805,000 of these unit options will be exercisable in 2008, 2009, 2010 and 2011, respectively. As these options are exercised, we will reimburse EPCO in the form of a special cash distribution for the difference between the strike price paid by the employee and the actual purchase price paid for the units awarded to the employee. See Note 5 for additional information regarding our accounting for equity awards.
Performance Guaranty
In December 2004, a subsidiary of ours entered into the Independence Hub Agreement (the “Agreement”) with six oil and natural gas producers. The Agreement, as amended, obligated our subsidiary to construct the Independence Hub offshore platform and to process 1 Bcf/d of natural gas and condensate for the 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. However at December 31, 2006, as a component of other current liabilities on our Consolidated Balance Sheet, we recorded the fair value of the performance guaranty at an estimated $1.2 million using
an expected present value approach. This was in accordance with FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,”
Other Claims
As part of our normal business activities with joint venture partners and certain customers and suppliers, we occasionally have claims made against us as a result of disputes related to contractual agreements or similar arrangements. As of December 31, 2007, claims against us totaled approximately $37.9 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.
Other Commitments
We transport and store natural gas, NGLs and petrochemicals for third parties under various processing, storage, transportation and similar agreements. These volumes are (i) accrued as product payables on our Consolidated Balance Sheets, (i) in transit for delivery to our customers or (iii) held at our storage facilities for redelivery to our customers. We are insured against any physical loss of such volumes due to catastrophic events. Under the terms of our natural gas, NGL and petrochemical storage agreements, we are generally required to redeliver volumes to the owner on demand. At December 31, 2007, NGL and petrochemical products aggregating 25.2 million barrels were due to be redelivered to their owners along with 16,223 BBtus of natural gas. See Note 2 for more information regarding accrued product payables.
Note 21. Significant Risks and Uncertainties
Nature of Operations in Midstream Energy Industry
Our operations are within the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs, certain petrochemicals and crude oil. As such, our results of operations, cash flows and financial condition may be affected by changes in the commodity prices of these hydrocarbon products, including changes in the relative price levels among these products. In general, the prices of natural gas, NGLs, crude oil and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.
Our profitability could be impacted by a decline in the volume of hydrocarbon products transported, gathered or processed at our facilities. A material decrease in natural gas or crude oil production or crude oil refining for reasons such as depressed commodity prices or a decrease in exploration and development activities, could result in a decline in the volume of natural gas, NGLs and crude oil handled by our facilities.
A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduced demand by consumers for the end products made using NGLs, (iii) increased competition from petroleum-based products due to pricing differences, (iv) adverse weather conditions, (v) government regulations affecting energy commodity prices, production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could adversely affect our results of operations, cash flows and financial position.
Credit Risk due to Industry Concentrations
A substantial portion of our revenues are derived from companies in the domestic natural gas, NGL and petrochemical industries. This concentration could affect our overall exposure to credit risk since these customers may be affected by similar economic or other conditions. We generally do not require collateral for our accounts receivable; however, we do attempt to negotiate offset, prepayment, or automatic
debit agreements with customers that are deemed to be credit risks in order to minimize our potential exposure to any defaults.
Our revenues are derived from a wide customer base. During 2007, 2006 and 2005, our largest customer was The Dow Chemical Company and its affiliates, which accounted for 6.9%, 6.1% and 6.8%, respectively, of our consolidated revenues.
Counterparty Risk with respect to Financial Instruments
Where we are exposed to credit risk in our financial instrument transactions, we analyze the counterparty’s financial condition prior to entering into an agreement, establish credit and/or margin limits and monitor the appropriateness of these limits on an ongoing basis. We generally do not require collateral for our financial instrument transactions.
Weather-Related Risks
We participate as named insureds in EPCO’s current insurance program, which provides us with property damage, business interruption and other coverages, which are customary for the nature and scope of our operations. EPCO attempts to place all insurance coverage with carriers having ratings of “A” or higher. However, two carriers associated with the EPCO insurance program were downgraded by Standard & Poor’s during 2006. One of these carriers is currently at “A-” and the other, “BBB.” At present, there is no indication that these two carriers would be unable to fulfill any insuring obligation. Furthermore, we currently do not have any claims which might be affected by these carriers. EPCO continues to monitor these situations.
We believe EPCO maintains adequate insurance coverage on our behalf; however, insurance will not cover every type of interruption that might occur. As a result of severe hurricanes such as Katrina and Rita that occurred in 2005, market conditions for obtaining property damage insurance coverage were difficult during 2006. Under EPCO’s renewed insurance programs, coverage was more restrictive, including increased physical damage and business interruption deductibles. For example, our deductible for onshore physical damage increased from $2.5 million to $5.0 million per event and our deductible period for onshore business interruption claims increased from 30 days to 60 days. Additional restrictions will be applied in connection with damage caused by named windstorms.
In addition to changes in coverage, the cost of property damage insurance increased substantially between 2006 and prior periods. At present, our annualized cost of insurance premiums for all lines of coverage is approximately $52.4 million. During the year ended December 31, 2006, our annualized cost of insurance premiums for all lines of coverage was approximately $49.2 million, which represented a $28.1 million, or 133%, increase from our 2005 annualized insurance cost.
If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient to reimburse us for repair costs or lost income. Any event that interrupts the revenues generated by our consolidated operations, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to pay distributions to partners and, accordingly, adversely affect the market price of our common units.
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.
Hurricane Ivan insurance claims. During the years ended December 31, 2007 and 2006, we received cash reimbursements from insurance carriers totaling $1.3 million and $24.1 million, respectively,
related to property damage claims. If the final recovery of funds is different than the amount previously expended, we will recognize an income impact at that time.
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. During the years ended December 31, 2007 and 2006, we received $0.4 million and $17.4 million of nonrefundable cash proceeds from such claims. We are continuing our efforts to collect residual balances and expect to complete the process during 2008. To the extent we receive nonrefundable cash proceeds from business interruption insurance claims, they are recorded as a gain in our Statements of Consolidated Operations in the period of receipt.
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. With respect to these storms, we have $37.6 million of estimated property damage claims outstanding at December 31, 2007, that we believe are probable of collection during the period 2008 through 2009. We continue to pursue collection of our property damage claims related to these named storms. As of December 31, 2007, we had received practically all proceeds from our business interruption claims related to these storm events.
The following table summarizes proceeds we received during the periods indicated from business interruption and property damage insurance claims with respect to certain named storms:
During 2007, we collected $0.8 million of business interruption proceeds that were not related to storm events. As well, during 2005, we received $4.8 million of nonrefundable cash proceeds from business interruption claims.
Note 22. Supplemental Cash Flow Information
The following table provides information regarding (i) the net effect of changes in our operating assets and liabilities; (ii) cash payments for interest and (iii) cash payments for federal and state income taxes for the periods indicated.
The following table provides supplemental cash flow information regarding business combinations we completed during the periods indicated. See Note 12, for additional information regarding our business combination transactions.
We incurred liabilities for construction in progress that had not been paid at December 31, 2007, 2006 and 2005 of $95.5 million, $195.1 million and $130.2 million, respectively. Such amounts are not included under the caption “Capital expenditures” on the Statements of Consolidated Cash Flows.
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 $57.5 million, $60.5 million and $47.0 million as contributions in aid of our construction costs during the years ended December 31, 2007, 2006 and 2005, respectively.
In June 2005, we received $47.5 million in cash from Cameron Highway as a return of investment. These funds were distributed to us in connection with the refinancing of Cameron Highway’s project debt.
Note 23. Quarterly Financial Information (Unaudited)
The following table presents selected quarterly financial data for the years ended December 31, 2007 and 2006:
Note 24. 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 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 14 for additional information regarding our consolidated debt obligations.
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:
The following table presents condensed consolidated statements of operations data for EPO for the periods indicated:
Note 25. Subsequent Event
Enterprise Products 2008 Long-Term Incentive Plan
On January 29, 2008, the unitholders of Enterprise Products Partners approved the Enterprise Products 2008 Long-Term Incentive Plan (the “Incentive Plan”), which provides for awards of the Partnership’s common units and other rights to the Partnership’s non-employee directors and to consultants and employees of EPCO and its affiliates providing services to the Partnership. Awards under the Incentive Plan may be granted in the form of restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The Incentive Plan will be administered by EPGP’s ACG Committee. Up to 10,000,000 of the Partnership’s common units may be granted as awards under the Incentive Plan, with such amount subject to adjustment as provided for under the terms of the plan.
The exercise price of unit options or UARs awarded to participants will be determined by the ACG Committee (at its discretion) at the date of grant and may be no less than the fair market value of the option award as of the date of grant. The Incentive Plan may be amended or terminated at any time by the Board of Directors of EPCO or EPGP’s ACG Committee; however, any material amendment, such as a significant increase in the number of units available under the plan or a change in the types of awards available under the plan, would require the approval of the unitholders of the Partnership. The ACG Committee is also authorized to make adjustments in the terms and conditions of, and the criteria included in awards under the plan in specified circumstances. The Incentive Plan is effective until January 29, 2018 or, if earlier, the time which all available units under the Incentive Plan have been delivered to participants or the time of termination of the plan by EPCO or EPGP’s ACG Committee.
Enterprise Unit L.P. Long-Term Incentive Plan
On February 20, 2008, EPCO formed Enterprise Unit L.P. (“Enterprise LP”) to serve as an incentive arrangement for certain employees of EPCO through a “profits interest” in Enterprise LP. On that date, EPCO Holdings, Inc. (“EPCO Holdings”) agreed to contribute $18,000,000 in the aggregate (the “Initial Contribution”) to Enterprise LP and was admitted as the Class A limited partner. Certain key employees of EPCO including our Chief Executive Officer and Chief Financial Officer were issued Class B limited partner interests and admitted as Class B limited partners of Enterprise LP without any capital contribution. As with the awards granted in connection with the other Employee Partnerships, these awards are designed to provide additional long-term incentive compensation for such employees. The profits interest awards (or Class B limited partner interests) in Enterprise LP entitle the holder to participate in the appreciation in value of Enterprise GP Holdings units and our common units and are subject to forfeiture.
A portion of the fair value of these equity awards will be allocated to us under the EPCO administrative services agreement as a non-cash expense. We will not reimburse EPCO, Enterprise LP or any of their affiliates or partners, through the administrative services agreement or otherwise, for any expenses related to Enterprise LP, including the Initial Contribution by EPCO Holdings.
The Class B limited partner interests in Enterprise LP 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 February 20, 2014, with customary exceptions for death, disability and certain retirements. The risk of forfeiture associated with the Class B limited partner interests in Enterprise LP will also lapse upon certain change of control events.
Unless otherwise agreed to by EPCO, EPCO Holdings and a majority in interest of the Class B limited partners of Enterprise LP, Enterprise LP will terminate at the earlier of February 20, 2014 (six years from the date of the agreement) or a change in control of us or Enterprise GP Holdings. Enterprise LP has the following material terms regarding its quarterly cash distribution to partners:
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Distributions of cash flow - Each quarter, 100% of the cash distributions received by Enterprise LP from Enterprise GP Holdings and us will be distributed to the Class A limited partner until EPCO Holdings has received an amount equal to the Class A preferred return (as defined below), and any remaining distributions received by Enterprise LP will be distributed to the Class B limited partners. The Class A preferred return equals the Class A capital base (as defined below) multiplied by 5.0% per annum. The Class A limited partner’s capital base equals the amount of any contributions of cash or cash equivalents made by the Class A limited partner to Enterprise LP, plus any unpaid Class A preferred return from prior periods, less any distributions made by Enterprise LP of proceeds from the sale of units owned by Enterprise LP (as described below).
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Liquidating Distributions - Upon liquidation of Enterprise LP, units having a fair market value equal to the Class A limited partner capital base will be distributed to EPCO Holdings, 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.
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Sale Proceeds - If Enterprise LP sells any units that it beneficially 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.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
Disclosure controls and procedures
Our management, with the participation of the chief executive officer (“CEO”) and chief financial officer (“CFO”) of our general partner, has evaluated the effectiveness of our disclosure controls and procedures, including internal controls over financial reporting, as of December 31, 2007. This evaluation concluded that our disclosure controls and procedures, including internal controls over financial reporting, are effective to provide us with a reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our management noted no material weaknesses in the design or operation of our internal controls over financial reporting that are likely to adversely affect our ability to record, process, summarize and report financial information. In addition, no fraud involving management or employees who have a significant role in our internal controls over financial reporting was detected.
The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and communicated to our management, including the CEO and CFO of our general partner, as appropriate to allow such persons to make timely decisions regarding required disclosures.
Our management does not expect that our disclosure controls and procedures will prevent all errors and all fraud. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Based on the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within Enterprise Products Partners have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Internal control over financial reporting
Our internal controls over financial reporting are designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements in accordance with GAAP. These internal controls over financial reporting were designed under the supervision of our management, including the CEO and CFO of our general partner, and include policies and procedures that:
(i)
pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets,
(ii)
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
(iii)
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
In accordance with Item 308 of SEC Regulation S-K, management is required to provide an annual report regarding internal controls over our financial reporting. This report, which includes management’s assessment of the effectiveness of our internal controls over financial reporting, is found elsewhere in this Item 9A.
There were no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) or in other factors during the fourth quarter of 2007, that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.
The certifications of our general partner’s CEO and CFO required under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 have been included as exhibits to this annual report on Form 10-K.
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING AS OF DECEMBER 31, 2007
The management of Enterprise Products Partners L.P. and its consolidated subsidiaries, including its Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Our internal control system was designed to provide reasonable assurance to Enterprise Products Partners’ management and board of directors regarding the preparation and fair presentation of published financial statements. However, our management does not represent that our disclosure controls and procedures or internal controls over financial reporting will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only a reasonable, not an absolute, assurance that the objectives of the control system are met.
Our management assessed the effectiveness of Enterprise Products Partners’ internal control over financial reporting as of December 31, 2007. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework. This assessment included design effectiveness and operating effectiveness of internal controls over financial reporting as well as the safeguarding of assets. Based on our assessment, we believe that, as of December 31, 2007, Enterprise Products Partners’ internal control over financial reporting is effective based on those criteria.
Our Audit, Conflicts and Governance Committee is composed of directors who are not officers or employees of our general partner. It meets regularly with members of management, the internal auditors and the representatives of the independent registered public accounting firm to discuss the adequacy of Enterprise Products Partners’ internal controls over financial reporting, financial statements and the nature, extent and results of the audit effort. Management reviews with the Audit, Conflicts and Governance Committee all of Enterprise Products Partners’ significant accounting policies and assumptions affecting the results of operations. Both the independent registered public accounting firm and internal auditors have direct access to the Audit, Conflicts and Governance Committee without the presence of management.
Our independent registered public accounting firm has issued an attestation report on our internal control over financial reporting. That report is included under Item 9A of this annual report.
Pursuant to the requirements of Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended, this Annual Report on Internal Control Over Financial Reporting has been signed below by the following persons on behalf of the registrant and in the capacities indicated below on February 29, 2008.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Enterprise Products GP, LLC and
Unitholders of Enterprise Products Partners L.P.
Houston, Texas
We have audited the internal control over financial reporting of Enterprise Products Partners LP and subsidiaries (the “Company”) as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting as of December 31, 2007. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and the related statements of consolidated operations, consolidated comprehensive income, consolidated cash flows, and consolidated partners’ equity
as of and for the year ended December 31, 2007 of the Company and our report dated February 28, 2008 expressed an unqualified opinion on those financial statements.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 28, 2008
Item 9B.
Item 9B. Other Information.
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
Partnership Management
As is commonly the case with publicly traded limited partnerships, we do not directly employ any of the persons responsible for the management or operations of our business. These functions are performed by the employees of EPCO pursuant to an administrative services agreement under the direction of the Board of Directors (the “Board”) and executive officers of EPGP. For a description of the administrative services agreement, see “Certain Relationships and Related Transactions - Relationship with EPCO” under Item 13 of this annual report.
The executive officers of our general partner are elected for one-year terms and may be removed, with or without cause, only by the Board. Our unitholders do not elect the officers or directors of our general partner. Dan. L. Duncan, through his indirect control of EPGP, has the ability to elect, remove and replace at any time, all of the officers and directors of our general partner. Each member of the Board of our general partner serves until such member’s death, resignation or removal. The employees of EPCO who served as directors of EPGP were Messrs. Dan L. Duncan, Michael A. Creel, W. Randall Fowler, Ralph S. Cunningham and Richard H. Bachmann.
Because we are a limited partnership and meet the definition of a “controlled company” under the listing standards of the NYSE, we are not required to comply with certain requirements of the NYSE. Accordingly, we have elected to not comply with Section 303A.01 of the NYSE Listed Company Manual, which would require that the Board of our general partner be comprised of a majority of independent directors. In addition, we have elected to not comply with Sections 303A.04 and 303A.05 of the NYSE Listed Company Manual, which would require that the Board of our general partner maintain a Nominating Committee and a Compensation Committee, each consisting entirely of independent directors.
Notwithstanding any contractual limitation on its obligations or duties, EPGP is liable for all debts we incur (to the extent not paid by us), except to the extent that such indebtedness or other obligations are non-recourse to EPGP. Whenever possible, EPGP intends to make any such indebtedness or other obligations non-recourse to itself.
Under our limited partnership agreement and subject to specified limitations, we will indemnify to the fullest extent permitted by Delaware law, from and against all losses, claims, damages or similar events any director or officer, or while serving as director or officer, any person who is or was serving as a tax matters member or as a director, officer, tax matters member, employee, partner, manager, fiduciary or trustee of our partnership or any of our affiliates. Additionally, we will indemnify to the fullest extent permitted by law, from and against all losses, claims, damages or similar events any person who is or was an employee (other than an officer) or agent of our partnership.
Corporate Governance
We are committed to sound principles of governance. Such principles are critical for us to achieve our performance goals, and maintain the trust and confidence of investors, employees, suppliers, business partners and stakeholders.
A key element for strong governance is independent members of the Board of Directors. Pursuant to the NYSE listing standards, a director will be considered independent if the Board determines that he or she does not have a material relationship with EPGP or us (either directly or as a partner, unitholder or officer of an organization that has a material relationship with EPGP or us). Based on the foregoing, the Board has affirmatively determined that Messrs. Rex C. Ross, Charles M. Rampacek and E. William Barnett are “independent” directors under the NYSE rules.
As required by the Sarbanes-Oxley Act of 2002, the SEC adopted rules that direct national securities exchanges and associations to prohibit the listing of securities of a public company if its audit committee members do not satisfy a heightened independence standard. In order to meet this standard, members of such audit committees may not receive any consulting fee, advisory fee or other compensation from the public company other than fees for service as a director or committee member and may not be considered an affiliate of the public company. Neither EPGP nor any individual member of its ACG Committee has relied on any exemption in the NYSE rules to establish such individual’s independence. Based on the foregoing criteria, the Board has affirmatively determined that all members of its ACG Committee satisfy this heightened independence requirement.
Code of Conduct and Ethics and Corporate Governance Guidelines
EPGP has adopted a “Code of Conduct” that applies to all directors, officers and employees. This code sets out our requirements for compliance with legal and ethical standards in the conduct of our business, including general business principles, legal and ethical obligations, compliance policies for specific subjects, obtaining guidance, the reporting of compliance issues and discipline for violations of the code.
Our Code of Conduct also establishes policies applicable to our chief executive officer, chief financial officer, principal accounting officer and senior financial and other managers to prevent wrongdoing and to promote honest and ethical conduct, including ethical handling of actual and apparent conflicts of interest, compliance with applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in public communications and prompt internal reporting of violations of the code.
Governance guidelines, together with committee charter, provide the framework for effective governance. The Board has adopted the Governance Guidelines of Enterprise Products Partners, which address several matters, including qualifications for directors, responsibilities of directors, retirement of directors, the composition and responsibility of ACG Committee, the conduct and frequency of board and committee meetings, management succession, director access to management and outside advisors, director compensation, director orientation and continuing education, and annual self-evaluation of the board. The Board recognizes that effective governance is an on-going process, and thus, the Board will review the Governance Guidelines of Duncan Energy Partners annually or more often as deemed necessary.
We provide access through our website at www.epplp.com to current information relating to governance, including the Code of Conduct, the Governance Guidelines of Enterprise Products Partners and other matters impacting our governance principles. You may also contact our investor relations department at (866) 230-0745 for printed copies of these documents free of charge.
ACG Committee
The sole committee of the Board is its ACG Committee. In accordance with NYSE rules and Section 3(a)(58)(A) of the Securities Exchange Act of 1934, the Board has named three of its members to
serve on its ACG Committee. The members of the ACG Committee are independent directors, free from any relationship with us or any of our subsidiaries that would interfere with the exercise of independent judgment.
The members of the ACG Committee must have a basic understanding of finance and accounting and be able to read and understand fundamental financial statements, and at least one member of the ACG Committee shall have accounting or related financial management expertise. The members of the ACG Committee are Messrs. Ross, Rampacek and Barnett. The Board has affirmatively determined that Mr. Rampacek satisfies the definition of “audit committee financial expert” as defined in Item 401(h) of Regulation S-K promulgated by the SEC.
The ACG Committee’s duties are addressing audit and conflicts-related items and general corporate governance. From an audit and conflicts standpoint, the primary responsibilities of the ACG Committee include:
§
review potential conflicts of interest, including related party transactions;
§
monitoring the integrity of our financial reporting process and related systems of internal control;
§
ensuring our legal and regulatory compliance and that of EPGP;
§
overseeing the independence and performance of our independent public accountant;
§
approving all services performed by our independent public accountant;
§
providing for an avenue of communication among the independent public accountant, management, internal audit function and the Board;
§
encouraging adherence to and continuous improvement of our policies, procedures and practices at all levels;
§
reviewing areas of potential significant financial risk to our businesses; and
§
approving awards granted under our long-term incentive plans.
If the Board believes that a particular matter presents a conflict of interest and proposes a resolution, the ACG Committee has the authority to review such matter to determine if the proposed resolution is fair and reasonable to us. Any matters approved by the ACG Committee are conclusively deemed to be fair and reasonable to our business, approved by all of our partners and not a breach by EPGP or the Board of any duties they may owe us or our unitholders.
Pursuant to its formal written charter, the ACG Committee has the authority to conduct any investigation appropriate to fulfilling its responsibilities, and it has direct access to our independent public accountants as well as any EPCO personnel whom it deems necessary in fulfilling its responsibilities. The ACG Committee has the ability to retain, at our expense, special legal, accounting or other consultants or experts it deems necessary in the performance of its duties.
From a governance standpoint, the ACG Committee’s primary duties and responsibilities are to develop and recommend to the Board a set of governance principles applicable to us and review such guidelines from time to time, making any changes that the ACG Committee deems necessary. The ACG Committee assists the Board in fulfilling its oversight responsibilities.
A copy of the ACG Committee charter is available on our website, www.epplp.com. You may also contact our investor relations department at (866) 230-0745 for a printed copy of this document free of charge.
NYSE Corporate Governance Listing Standards
On April 2, 2007, Robert G. Phillips, our chief executive officer on such date, certified to the NYSE (as required by Section 303A.12(a) of the NYSE Listed Company Manual) that he was not aware of any violation by us of the NYSE’s Corporate Governance listing standards as of April 2, 2007.
Executive Sessions of Non-Management Directors
The Board holds regular executive sessions in which non-management directors meet without any members of management present. The purpose of these executive sessions is to promote open and candid discussion among the non-management directors. During such executive sessions, one director is designated as the “presiding director,” who is responsible for leading and facilitating such executive sessions. Currently, the presiding director is Mr. Barnett.
In accordance with NYSE rules, we have established a toll-free, confidential telephone hotline (the “Hotline”) so that interested parties may communicate with the presiding director or with all the non-management directors as a group. All calls to this Hotline are reported to the chairman of the ACG Committee, who is responsible for communicating any necessary information to the other non-management directors. The number of our confidential Hotline is (877) 888-0002.
Directors and Executive Officers of EPGP
The following table sets forth the name, age and position of each of the directors and executive officers of EPGP at February 29, 2008. Each executive officer holds the same respective office shown below in the general partner of the Operating Partnership.
(1)
Executive officer
(2)
Member of ACG Committee
(3)
Chairman of ACG Committee
The following information presents a brief history of the business experience of our directors and executive officers serving as of December 31, 2007:
Dan L. Duncan. Mr. Duncan was elected Chairman and a Director of EPGP in April 1998, Chairman and a Director of the general partner of EPO in December 2003, Chairman and a Director of EPE Holdings in August 2005 and Chairman and a Director of DEP GP in October 2006. Mr. Duncan served as the sole Chairman of EPCO from 1979 to December 2007. Mr. Duncan now serves as Group Co-Chairman of EPCO with his daughter, Ms. Randa Duncan Williams, also a Director of EPE Holdings. He also serves as a Honorary Trustee of the Board of Trustees of the Texas Heart Institute at Saint Luke’s Episcopal Hospital.
Michael A. Creel. Mr. Creel was elected President and Chief Executive Officer of EPGP in August 2007. From June 2000 to August 2007, Mr. Creel served as Chief Financial Officer of EPGP and an Executive Vice President of EPGP from January 2001 to August 2007. Mr. Creel, a certified public accountant, also served as a Senior Vice President of EPGP from November 1999 to January 2001.
In December 2007, Mr. Creel was elected Group Vice Chairman and Chief Financial Officer of EPCO. Prior to these elections in EPCO, Mr. Creel served as Chief Operating Officer from April 2005 to December 2007 and Chief Financial Officer from June 2000 to April 2005 for EPCO. He also serves as a Director of DEP GP and EPGP since October 2006 and 2005, respectively. Mr. Creel served as President, Chief Executive Officer and a Director of EPE Holdings from August 2005 through August 2007. In October 2005, Mr. Creel was elected a Director of Edge Petroleum Corporation (a publicly traded oil and natural gas exploration and production company).
W. Randall Fowler. Mr. Fowler was elected Executive Vice President and Chief Financial Officer of EPGP, EPE Holdings and DEP GP in August 2007. Mr. Fowler has served as Senior Vice President and Treasurer of EPGP from February 2005 to August 2007 and of DEP GP from October 2006 to August 2007. In February 2006, Mr. Fowler became a Director of EPGP and EPE Holdings and of DEP GP since October 2006. Mr. Fowler also served as Senior Vice President and Chief Financial Officer of EPE Holdings from August 2005 to August 2007.
Mr. Fowler was elected President and Chief Executive Officer of EPCO in December 2007. Prior to these elections, he served as Chief Financial Officer of EPCO from April 2005 to December 2007. Mr. Fowler, a certified public accountant (inactive), joined Enterprise Products Partners as Director of Investor Relations in January 1999.
Richard H. Bachmann. Mr. Bachmann was elected an Executive Vice President, Chief Legal Officer and Secretary of EPGP and a Director of EPGP in February 2006. He previously served as a Director of EPGP from June 2000 to January 2004. Mr. Bachmann has served as a Director of the general partner of EPO since December 2003 and has served as Executive Vice President, Chief Legal Officer and Secretary of EPE Holdings since August 2005.
Mr. Bachmann was elected Group Vice Chairman, Chief Legal Officer and Secretary of EPCO in December 2007. In October 2006, Mr. Bachmann was elected President, Chief Executive Officer and a Director of DEP GP. Mr. Bachmann was also elected a Director of DEP GP in October 2006 and a Director of EPE Holdings in February 2006. Since January 1999, Mr. Bachmann has served as a Director of EPCO. In November 2006, Mr. Bachmann was appointed an independent manager of Constellation Energy Partners LLC. Mr. Bachmann also serves as a member of the audit, compensation and nominating and governance committee of Constellation Energy Partners LLC.
Dr. Ralph S. Cunningham. Dr. Cunningham was elected a Director of EPGP in February 2006 and also served as a Director of EPGP from 1998 until March 2005. In addition to these duties Dr. Cunningham served as Group Executive Vice President and Chief Operating Officer of EPGP from December 2005 to August 2007 and Interim President and Interim Chief Executive Officer from June 2007 to August 2007. Dr. Cunningham was elected President and Chief Executive Officer of EPE Holdings in August 2007. He served as Chairman and a Director of TEPPCO GP from March 2005 until November 2005.
Dr. Cunningham was elected a Group Vice Chairman of EPCO in December 2007 and served as a Director from 1987 to 1997. He serves as a Director of Tetra Technologies, Inc. (a publicly traded energy services and chemical company), EnCana Corporation (a Canadian publicly traded independent oil and natural gas company) and Agrium, Inc. (a Canadian publicly traded agricultural chemicals company). Dr. Cunningham retired in 1997 from CITGO Petroleum Corporation, where he had served as President and Chief Executive Officer since 1995.
E. William Barnett. Mr. Barnett was elected a Director of EPGP in March 2005. Mr. Barnett is a member of our ACG Committee and serves as its Chairman. Mr. Barnett practiced law with Baker Botts
L.L.P. from 1958 until his retirement in 2004. In 1984, he became Managing Partner of Baker Botts L.L.P. and continued in that role for fourteen years until 1998. He was Senior Counsel to the firm from 1998 until June 2004, when he retired from the firm. Mr. Barnett served as Chairman of the Board of Trustees of Rice University from 1996 to July 2005.
Mr. Barnett is a Life Trustee of The University of Texas Law School Foundation; a Director of St. Luke’s Episcopal Health System; and a Director and former Chairman of the Houston Zoo, Inc. (the operating arm of the Houston Zoo). He is a Director of Reliant Energy, Inc. (a publicly traded electric services company) and Westlake Chemical Corporation (a publicly traded chemical company). Mr. Barnett is Chairman of the Advisory Board of the Baker Institute for Public Policy at Rice University and a Director and former Chairman of the Greater Houston Partnership. Mr. Barnett served as a Trustee of the Baylor College of Medicine from 1993 until 2004.
Rex C. Ross. Mr. Ross was elected a Director of EPGP in October 2006 and is a member of its ACG Committee. Mr. Ross serves as a Director of Schlumberger Technology Corporation, the holding company for all Schlumberger Limited assets and entities in the United States. Prior to his executive retirement from Schlumberger Limited in May 2004, Mr. Ross held a number of executive management positions during his 11-year career with the company, including President of Schlumberger Oilfield Services North America; President, Schlumberger GeoQuest; and President of SchlumbergerSema North & South America. Mr. Ross also serves on the board of directors of Gulfmark Offshore, Inc. (a publicly traded offshore marine services company) and is a member of its Governance Committee.
Charles M. Rampacek. Mr. Rampacek was elected a Director of EPGP in October 2006 and is a member of its ACG Committee. Mr. Rampacek is currently a business and management consultant in the energy industry. Mr. Rampacek served as Chairman, Chief Executive Officer and President of Probex Corporation (“Probex”), an energy technology company that developed a proprietary used oil recovery process, from 2000 until his retirement in 2003. Prior to joining Probex Corporation, Mr. Rampacek was President and Chief Executive Officer of Lyondell-Citgo Refining L.P, a manufacturer of petroleum products, from 1996 through 2000. From 1982 to 1995, he held various executive positions with Tenneco Inc. and its energy-related subsidiaries, including President of Tenneco Gas Transportation Company, Executive Vice President of Tenneco Gas Operations and Senior Vice President of Refining and Supply. Mr. Rampacek also spent 16 years with Exxon Company USA, where he held various supervisory and management positions. Mr. Rampacek has been a Director of Flowserve Corporation since 1998 and is Chairman of its Corporate Governance and Nominating Committee and a member of its Organization and Compensation Committee.
In 2005, two complaints requesting recovery of certain costs were filed against former officers and directors of Probex Corporation as a result of the bankruptcy of Probex in 2003. These complaints were defended under Probex’s director and officer insurance by AIG and settlement was reached and paid by AIG with bankruptcy court approval in the first half of 2006. An additional complaint was filed in 2005 against noteholders of certain Probex debt of which Mr. Rampacek was one. A settlement of $2,000 was reached and approved by the bankruptcy court in the first half of 2006.
William Ordemann. Mr. Ordemann was elected an Executive Vice President and the Chief Operating Officer of EPGP in August 2007. He previously served as a Senior Vice President of EPGP from September 2001 to August 2007 and was a Vice President of EPGP from October 1999 to September 2001. Mr. Ordemann joined us in connection with our purchase of certain midstream energy assets from affiliates of Shell Oil Company in 1999. Prior to joining us, he was a Vice President of Shell Midstream Enterprises, LLC from January 1997 to February 1998, and Vice President of Tejas Natural Gas Liquids, LLC from February 1998 to September 1999.
James H. Lytal. Mr. Lytal was elected an Executive Vice President of EPGP in September 2004. Mr. Lytal served as a Director of the general partner of GulfTerra Energy Partners, L.P. from August 1994 until September 2004, and as President of GulfTerra and its general partner from July 1995 until September 2004. He served as a Senior Vice President of GulfTerra and its general partner from August 1994 to June 1995. Prior to joining GulfTerra, Mr. Lytal served in various capacities with the oil and gas exploration
and production and natural gas pipeline businesses of United Gas Pipeline Company, Texas Oil and Gas, Inc. and American Pipeline Company
A.J. Teague. Mr. Teague was elected an Executive Vice President of EPGP in November 1999. Mr. Teague joined us in connection with our purchase of certain midstream energy assets from affiliates of Shell Oil Company in 1999. From 1998 to 1999, Mr. Teague served as President of Tejas Natural Gas Liquids, LLC
Gil H. Radtke. Mr. Radtke was elected a Senior Vice President of EPGP in February 2002. Mr. Radtke joined us in connection with our purchase of Diamond-Koch’s storage and propylene fractionation assets in 2002. Before joining us, Mr. Radtke served as president of the Diamond-Koch joint venture from 1999 to 2002, where he was responsible for its storage, propylene fractionation, pipeline and NGL fractionation businesses. From 1997 to 1999 he was Vice President, Petrochemicals and Storage of Diamond-Koch. In October 2006, Mr. Radtke was elected a Senior Vice President, Chief Operating Officer and a Director of the general partner of Duncan Energy Partners.
James M. Collingsworth. Mr. Collingsworth was elected a Vice President of EPGP in November 2001 and subsequently promoted to a Senior Vice President in November 2002. Mr. Collingsworth joined us in connection with our acquisition of the Mid-America and Seminole Pipeline Systems in 2002. Before joining us, he served as a board member of Texaco Canada Petroleum Inc. from July 1998 to October 2001 and was employed by Texaco from 1991 to 2001 in various management positions, including Senior Vice President of NGL Assets and Business Services from July 1998 to October 2001.
Michael J. Knesek. Mr. Knesek, a certified public accountant, was elected a Senior Vice President of EPGP in February 2005 having served as a Vice President of EPGP since August 2000. Mr. Knesek has been the Principal Accounting Officer and Controller of EPGP since August 2000, EPE Holdings since August 2005 and DEP GP since October 2006. He has served as Senior Vice President of EPE Holdings since August 2005 and of DEP GP since October 2006. Mr. Knesek has been the Controller of EPCO since 1990 and currently serves as one of its Senior Vice Presidents.
Section 16(a) Beneficial Ownership Reporting Compliance
Under federal securities laws, EPGP, directors and executive officers of EPGP, and certain other officers, and any persons holding more than 10% of our common units are required to report their ownership of common units and any changes in their ownership levels to us and the SEC. Specific due dates for these reports have been established by regulation, and we are required to disclose in this annual report any failure to file this information within the specified timeframes. With the exception of the following late filing, all such reporting was done in a timely manner in 2007.
The spouse of Mr. Rex Ross serves as trustee for a trust that benefits, in part, certain of his immediate family members. This trust holds 4,500 common units of Enterprise that have not been previously reported for Section 16 purposes. On November 14, 2007, this trust purchased 1,000 common units of Enterprise at an average price of $31.95 per unit. The remaining 3,500 common units held in the trust were purchased more than six months before Mr. Ross became a Director of EPGP and should have been reflected on his Form 3, which was filed on October 23, 2006. These trust holdings were properly reflected on a Form 4 for Mr. Ross on Friday, February 29, 2008.
Item 11.
Item 11. Executive Compensation.
Executive Officer Compensation
We do not directly employ any of the persons responsible for managing our partnership. Instead, we are managed by our general partner, the executive officers of which are employees of EPCO. Our reimbursement of EPCO’s compensation costs is governed by the administrative services agreement with EPCO (see Item 13).
Summary Compensation Table
The following table presents consolidated compensation amounts paid, accrued or otherwise expensed by us with respect to the years ended December 31, 2007 and 2006 for our general partner’s Chief Executive Officer (“CEO”), Chief Financial Officer (“CFO”) and three other most highly compensated executive officers as of December 31, 2007. We also include Robert G. Phillips and Dr. Ralph S. Cunningham, both of whom served as our CEO during 2007 prior to Michael A. Creel’s appointment to this position effective August 1, 2007. Collectively, these seven individuals were our “Named Executive Officers” for 2007. Compensation paid or awarded by us with respect to such Named Executive Officers reflects only that portion of compensation paid by EPCO allocated to us pursuant to an administrative services agreement, including an allocation of a portion of the cost of EPCO’s equity-based long-term incentive plans.
Compensation Discussion and Analysis
With respect to our Named Executive Officers, compensation paid or awarded by us for the last two fiscal years reflects only that portion of compensation paid by EPCO allocated to us pursuant to the administrative services agreement, including an allocation of a portion of the cost of equity-based long-term incentive plans of EPCO. Dan L. Duncan controls EPCO and has ultimate decision-making authority with respect to the compensation of our Named Executive Officers. The following elements of compensation, and EPCO’s decisions with respect to determination of payments, are not subject to approvals by our Board or the ACG Committee. Awards under EPCO’s long-term incentive plans are approved by the ACG Committee. We do not have a separate compensation committee.
As discussed below, the elements of EPCO’s compensation program, along with EPCO’s other rewards (e.g., benefits, work environment, career development), are intended to provide a total rewards package to employees. The compensation package is designed to reward contributions by employees in support of the business strategies of EPCO and its affiliates at both the partnership and individual levels. With respect to the years ended December 31, 2007 and 2006, EPCO’s compensation package for Named Executive Officers did not include any elements based on targeted performance-related criteria.
The primary elements of EPCO’s compensation program are a combination of annual cash and long-term equity-based incentive compensation. For the years ended December 31, 2007 and 2006, the elements of compensation for the Named Executive Officers consisted of the following:
§
Annual base salary;
§
Discretionary annual cash awards;
§
Awards under long-term incentive arrangements; and
§
Other compensation, including very limited perquisites.
In order to assist Mr. Duncan and EPCO with compensation decisions, our Chief Executive Officer and the Senior Vice President of Human Resources for EPCO formulate preliminary compensation recommendations for all of the Named Executive Officers other than our Chief Executive Officer. Mr. Duncan, after consulting with the Senior Vice President of Human Resources for EPCO, independently makes compensation decisions with respect to our Chief Executive Officer. EPCO takes note of market data for determining relevant compensation levels and compensation program elements through the review of and, in certain cases, participation in, various relevant compensation surveys. Mr. Duncan and EPCO do not use any formula or specific performance-based criteria for our Named Executive Officers in connection with services performed for us. All compensation determinations are discretionary and, as noted above, subject to Mr. Duncan’s ultimate decision-making authority.
The discretionary cash awards paid to each of our Named Executive Officers were determined by consultation among Mr. Duncan, our Chief Executive Officer and the Senior Vice President of Human Resources for EPCO, subject to Mr. Duncan’s final determination. These cash awards, in combination with annual base salaries, are intended to yield competitive total cash compensation levels for the Named Executive Officers and drive performance in support of our business strategies, as well as the performance of other EPCO affiliates for which the Named Executive Officers perform services. It is EPCO’s general policy to pay these awards during the first quarter of each year.
The equity awards granted under the EPCO 1998 Plan to our Named Executive Officers
were determined by consultation among Mr. Duncan, our Chief Executive Officer and the Senior Vice President of Human Resources for EPCO, and were approved by our general partner’s ACG Committee. These awards (restricted units and unit options) are intended to align the long-term interests of the executive officers with those of our unitholders. It is EPCO’s general policy to recommend, and the ACG Committee typically approves, these grants to employees during the second quarter of each fiscal year. In addition, our Named Executive Officers are Class B limited partners in certain of the Employee Partnerships. Mr. Duncan approves the issuance of all limited partnership interests in such Employee Partnerships to our Named Executive Officers. See “Summary of Long-Term Incentive Arrangements Underlying 2007 Award Grants” within this Item 11 for information regarding the long-term incentive plans. See Notes 2 and 5 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding the accounting for such awards.
EPCO generally does not pay for perquisites for any of our Named Executive Officers, other than reimbursement of certain parking expenses, and expects to continue its policy of covering very limited perquisites allocable to our Named Executive Officers. EPCO also makes matching contributions under its 401(k) plan for the benefit of our Named Executive Officers in the same manner as it does for other EPCO employees.
EPCO does not offer our Named Executive Officers a defined benefit pension plan. Also, none of our Named Executive Officers had nonqualified deferred compensation during the years ended December 31, 2007 or 2006.
We believe that each of the base salary, cash awards, and incentive awards fit the overall compensation objectives of us and of EPCO, as stated above (i.e., to provide competitive compensation opportunities to align and drive employee performance toward the creation of sustained long-term unitholder value, which will also allow us to attract, motivate and retain high quality talent with the skills and competencies required by us).
Compensation Committee Report
We do not have a separate compensation committee. As discussed in the Compensation Discussion and Analysis, we do not directly employ or compensate our Named Executive Officers. Rather, under the administrative services agreement with EPCO, we reimburse EPCO for the compensation of our executive officers. Accordingly, to the extent that decisions are made regarding the compensation policies pursuant to which our Named Executive Officers are compensated, they are made by Dan L. Duncan and EPCO (except for equity awards under long-term incentive plans, as discussed above), and not by our Board of Directors.
In light of the foregoing, the Board of Directors of our general partner has reviewed and discussed the Compensation Discussion and Analysis with management. Based on our review of and discussion with management with respect to the Compensation Discussion and Analysis, we determined that the Compensation Discussion and Analysis be included in this Report.
Submitted by: Dan L. Duncan
Michael A. Creel
W. Randall Fowler
Richard H. Bachmann
Dr. Ralph S. Cunningham
E. William Barnett
Charles M. Rampacek
Rex C. Ross
Notwithstanding anything to the contrary set forth in any previous filings under the Securities Act, as amended, or the Exchange Act, as amended, that incorporate future filings, including this Report, in whole or in part, the foregoing report shall not be incorporated by reference into any such filings.
Grants of Plan-Based Awards in Fiscal Year 2007
The following table presents information concerning each grant of a plan-based award made to a Named Executive Officer in 2007. The restricted unit and unit option awards granted during 2007 were under EPCO’s 1998 Long-Term Incentive Plan (the “1998 Plan”). See “Summary of Long-Term Incentive Arrangements Underlying 2007 Award Grants” within this Item 11 for additional information regarding EPCO’s long-term incentive plans.
(1)
Amounts presented reflect that portion of grant date fair value allocable to us based on the percentage of time each Named Executive Officer spent on our consolidated business activities during 2007. Based on current allocations, we estimate that the consolidated compensation expense we record for each Named Executive Officer with respect to these awards will equal these amounts over time.
(2)
For the period in which the restricted unit awards were outstanding during 2007, we recognized a total of $0.4 million of consolidated compensation expense related to these awards. The remaining portion of grant date fair value will be recognized as expense in future periods.
(3)
For the period in which the unit option awards were outstanding during 2007, we recognized a total of $72 thousand of consolidated compensation expense related to these awards. The remaining portion of grant date fair value will be recognized as expense in future periods.
(4)
For the period in which the profits interest awards were outstanding during 2007, we recognized a total of $1.0 million of consolidated compensation expense related to these awards. The remaining portion of grant date fair value will be recognized as expense in future periods.
The fair value amounts shown in the preceding table are based on certain assumptions and considerations made by management. The grant date fair values of restricted unit awards issued in May 2007 were based on a market price of Enterprise Products Partners’ common units of $30.96 per unit.
The grant date fair values of unit option awards issued in May 2007 were based on the following assumptions: (i) expected life of the options of seven years; (ii) risk-free interest rate of 4.8%; (iii) an expected distribution yield on our common units of 8.4%; and (iv) an expected unit price volatility of our common units of 23.2%.
The fair value of the EPE Unit III profits interest awards issued in May 2007 was based on the following assumptions: (i) remaining life of the award of five years; (ii) risk-free interest rate of 4.6%; (iii) an expected distribution yield on Enterprise GP Holdings’ units of 4.1% and (iv) an expected unit price volatility of Enterprise GP Holdings’ units of 17.6%.
Awards granted to Robert G. Phillips in May 2007 were cancelled in connection with his $8.8 million cash separation payment paid in June 2007.
Summary of Long-Term Incentive Arrangements Underlying 2007 Award Grants
The following information summarizes the types of awards granted to our Named Executive Officers during the year ended December 31, 2007. For detailed information regarding our accounting for unit-based awards, see Note 5 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
Unit option awards. Under EPCO’s 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 or our affiliates. When issued, the exercise price of each option grant is equivalent to the market price of the underlying equity on the date of grant. In general, options granted under the 1998 Plan have a vesting period of four years and remain exercisable for ten years from the date of grant. In order to fund its obligations under the 1998 Plan, EPCO may purchase common units at fair value either in the open market or directly from us. When employees exercise unit options, we reimburse EPCO for the cash difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the units issued to the employee.
Restricted unit awards. Under the 1998 Plan, EPCO’s key employees who perform management, administrative or operational functions for us or our affiliates may be awarded restricted common units. In general, our restricted unit awards allow recipients to acquire the underlying common units (at no cost to the recipient) once a defined vesting period expires, subject to certain forfeiture provisions. The restrictions on such nonvested units generally lapse four years from the date of grant. The fair value of restricted units is based on the market price of the underlying common units on the date of grant less an allowance for estimated forfeitures. Each recipient is also entitled to cash distributions equal to the product of the number of restricted units outstanding for the participant and the cash distribution per unit paid by us to our unitholders.
As used in the context of the EPCO plans, the term “restricted unit” represents a time-vested unit under SFAS 123(R). Such awards are non-vested until the required service period expires.
Phantom unit awards. The EPCO 1998 Plan also provides for the issuance of phantom unit awards. These liability awards are automatically redeemed for cash based on the vested portion of the fair market value of the phantom units at redemption dates in each award. The fair market value of each phantom unit award is equal to the market closing price of our common units on the redemption date. Each participant is required to redeem their phantom units as they vest, which typically is four years from the date the award is granted. No phantom unit awards have been issued to date under the EPCO 1998 Plan.
The EPCO 1998 Plan also provides for the award of distribution equivalent rights (“DERs”) in tandem with its phantom unit awards. A DER entitles the participant to cash distributions equal to the product of the number of phantom units outstanding for the participant and the cash distribution rate paid by us to our unitholders.
Profits interests awards. EPCO formed the Employee Partnerships to serve as long-term incentive arrangements for certain employees of EPCO by providing “profits interests” in the underlying limited partnerships (i.e. EPE Unit I, EPE Unit II and EPE Unit III). Our Named Executive Officers have been granted profits interest awards in EPE Unit I (formed in August 2005), EPE Unit II (formed in December 2006) and EPE Unit III (formed in May 2007). The profits interest awards (or Class B limited partner interests) entitle each holder to participate in the appreciation in value of Enterprise GP Holdings’ units and are subject to forfeiture. See Item 13 of this annual report for additional information regarding the Employee Partnerships.
The following table provides information regarding the Named Executive Officers’ share of such profits interest at December 31, 2007:
See Note 25 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding the formation of Enterprise Products 2008 Long-Term Incentive Plan in January 2008 and Enterprise Unit L.P. in February 2008.
Equity Awards Outstanding at December 31, 2007
The following tables present information concerning each Named Executive Officer’s nonvested restricted units and unexercised unit options as of December 31, 2007.
The following tables present information concerning each Named Executive Officer’s nonvested profits interest awards as of December 31, 2007.
Option Exercises and Stock Vested Table
The Named Executive Officers did not exercise any unit options during 2007. In addition, the Named Executive Officers did not vest in any equity-based awards during the year.
Director Compensation
The following table presents information regarding compensation paid to the independent directors of our general partner for the year ended December 31, 2007.
Neither we nor EPGP provide any additional compensation to employees of EPCO who serve as directors of EPGP. The employees of EPCO who served as directors of EPGP during 2007 were Messrs. Duncan, Creel, Fowler, Bachmann, Cunningham and Phillips.
Currently, EPGP’s three independent directors, Messrs. Barnett, Ross and Rampacek, are provided cash compensation for their services as follows:
The independent directors of our general partner have also received unit-based compensation in the form of UARs. These awards consist of letter agreements with each of the independent directors and are not part of any established long-term incentive plan of the EPCO group of companies. The awards are based upon an incentive plan of EPE Holdings, and are made in the form of UAR grants for non-employee directors. The compensation expense associated with these awards is recognized by EPGP. These UARs entitle the directors to receive a cash amount in the future equal to the excess, if any, of the fair market value of Enterprise GP Holdings’ units (determined as of a future vesting date) over the grant date price of such units. If a director resigns prior to vesting, his UAR awards are forfeited.
In August 2006, Mr. Barnett was granted 10,000 UARs under the letter agreement format. The grant date price of these rights was $35.71 per unit. These awards vest in August 2011 or on the date of certain qualifying events (as set forth in the form of grant). At December 31, 2007, the total fair value of these 10,000 UARs was $28 thousand, which was based on the following assumptions: (i) remaining life of award of four years; (ii) risk-free interest rate of 3.6%; (iii) an expected distribution yield on Enterprise GP Holdings’ units of 4.4%; and (iv) an expected unit price volatility of Enterprise GP Holdings’ units of 16.9%.
In November 2006, Mr. Barnett was issued an additional 20,000 UARs and Mr. Ross and Mr. Rampacek were each granted 30,000 UARs under the letter agreement format. The grant date price of these UARs was $34.10 per unit. These awards vest in November 2011 or on the date of certain qualifying events (as set forth in the form of grant). At December 31, 2007, the total fair value of these 80,000 UARs was $272 thousand, which was based on the following assumptions: (i) remaining life of award of four years; (ii) risk-free interest rate of 3.6%; (iii) an expected distribution yield on Enterprise GP Holdings’ units of 4.4%; and (iv) an expected unit price volatility of Enterprise GP Holdings’ units of 16.9%.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.
Security Ownership of Certain Beneficial Owners
The following table sets forth certain information as of February 1, 2008, regarding each person known by our general partner to beneficially own more than 5% of our common units.
(1)
For a detailed listing of ownership amounts that comprise Mr. Duncan’s total beneficial ownership of our common units, see the table presented in the following section, “Security Ownership of Management,” within this Item 12.
Security Ownership of Management
Enterprise Products Partners L.P. and Enterprise GP Holdings L.P.
The following table sets forth certain information regarding the beneficial ownership of our common units and the units of Enterprise GP Holdings L.P. as of February 1, 2008 by:
§
our Named Executive Officers;
§
the current Directors of EPGP; and
§
the current directors and executive officers of EPGP as a group.
If an individual does not own any securities in the foregoing registrants, he is not listed in the following table.
Enterprise GP Holdings owns 100% of the membership interests of EPGP. All information with respect to beneficial ownership has been furnished by the respective directors or officers. Each person has sole voting and dispositive power over the securities shown unless otherwise indicated below. The beneficial ownership amounts of certain individuals include options to acquire our common units that are exercisable within 60 days of the filing date of this annual report.
Mr. Duncan owns 50.4% of the voting stock of EPCO and, accordingly, exercises sole voting and dispositive power with respect to our common units beneficially owned by EPCO and its affiliates. The remaining shares of EPCO capital stock are owned primarily by trusts for the benefit of members of Mr. Duncan’s family. The address of EPCO is 1100 Louisiana Street, 10th Floor, Houston, Texas 77002.
*
The beneficial ownership of each individual is less than 1% of the registrant’s common units outstanding.
(1)
As a result of EPCO’s ownership of the general partners of the Employee Partnerships, Mr. Duncan is deemed beneficial owner of the securities held by these entities.
(2)
Mr. Duncan is deemed beneficial owner of the securities held by certain family trusts, the beneficiaries of which are shareholders of EPCO.
(3)
These individuals are Named Executive Officers.
(4)
Cumulatively, this group’s beneficial ownership amount includes 150,000 options to acquire common units of Enterprise Products Partners L.P. that were issued under the 1998 Plan. These options are exercisable within 60 days of the filing date of this report.
Essentially all of the ownership interests in us and Enterprise GP Holdings that are owned or controlled by EPCO are pledged as security under the credit facility of an EPCO affiliate. This credit facility contains customary and other events of default relating to EPCO and certain of its affiliates, including Enterprise GP Holdings, TEPPCO and us. In the event of a default under this credit facility, a change in control of Enterprise GP Holdings or us could occur, including a change in control of our respective general partners.
Duncan Energy Partners L.P.
On February 5, 2007, Duncan Energy Partners, a consolidated subsidiary of ours, completed its initial public offering of 14,950,000 common units. Certain of our directors and executive officers purchased common units of Duncan Energy Partners in this offering. The following table presents the beneficial ownership of common units of Duncan Energy Partners by our directors, Named Executive Officers and all directors and officers of our general partner (as a group) at February 1, 2008.
*
The beneficial ownership of each individual is less than 1% of the registrant’s units outstanding.
(1)
The number of common units shown for Dan L. Duncan represents the final amount of common units issued to EPO in connection with its contribution of equity interests to Duncan Energy Partners in February 2007.
(2)
Mr. Bachmann is the Chief Executive Officer of Duncan Energy Partners.
(3)
These individuals are Named Executive Officers.
(4)
Mr. Fowler is the Chief Financial Officer of Duncan Energy Partners.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table sets forth certain information as of December 31, 2007 regarding the 1998 Plan, under which our common units are authorized for issuance to EPCO’s key employees and to directors of EPGP through the exercise of unit options.
1998 Plan
The 1998 Plan is effective until either all available common units under the plan have been issued to participants or the earlier termination of the 1998 Plan by EPCO. The 1998 Plan also provides for the issuance of restricted common units, of which 1,688,540 were outstanding at December 31, 2007. During 2007, a total of 738,040 restricted unit awards were issued to key employees of EPCO and our independent directors. For additional information regarding the 1998 Plan, see Note 5 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
Enterprise Products 2008 Long-Term Incentive Plan
On January 29, 2008, the unitholders of Enterprise Products Partners approved the Enterprise Products 2008 Long-Term Incentive Plan (the “Incentive Plan”), which provides for awards of the Partnership’s common units and other rights to the Partnership’s non-employee directors and to consultants and employees of EPCO and its affiliates providing services to the Partnership. Awards under the Incentive Plan may be granted in the form of restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The Incentive Plan will be administered by EPGP’s ACG Committee. Up to 10,000,000 of the Partnership’s common units may be granted as awards under the Incentive Plan, with such amount subject to adjustment as provided for under the terms of the plan.
The exercise price of unit options or UARs awarded to participants will be determined by the ACG Committee (at its discretion) at the date of grant and may be no less than the fair market value of the option award as of the date of grant. The Incentive Plan may be amended or terminated at any time by the Board of Directors of EPCO or EPGP’s ACG Committee; however, any material amendment, such as a significant increase in the number of units available under the plan or a change in the types of awards available under the plan, would require the approval of the unitholders of the Partnership. The ACG Committee is also authorized to make adjustments in the terms and conditions of, and the criteria included in awards under the plan in specified circumstances. The Incentive Plan is effective until January 29, 2018 or, if earlier, the time which all available units under the Incentive Plan have been delivered to participants or the time of termination of the plan by EPCO or EPGP’s ACG Committee.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Certain Relationships and Related Transactions
The following information summarizes our business relationships and transactions with related parties during the year ended December 31, 2007. We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties. For additional information regarding our related party transactions, see Note 17 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
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 a part of our consolidated group of companies:
§
EPCO and its private company subsidiaries;
§
EPGP, our sole general partner;
§
Enterprise GP Holdings, which owns and controls our general partner;
§
the Employee Partnerships;
§
TEPPCO, which is owned and controlled by Enterprise GP Holdings; and
§
Energy Transfer Equity, an equity method investment of Enterprise GP Holdings.
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.
EPCO is a private company controlled by Dan L. Duncan, who is also a Director and Chairman of EPGP, our general partner. At December 31, 2007, EPCO and its affiliates beneficially owned 147,986,045 (or 34.0%) of our outstanding common units, which includes 13,454,498 of our common units owned by Enterprise GP Holdings. In addition, at December 31, 2007, EPCO and its affiliates beneficially owned 77.1% 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 EPGP. The principal business activity of EPGP is to act as our managing partner. The executive officers and certain of the directors of EPGP and EPE Holdings are employees of EPCO.
As our general partner, EPGP received cash distributions of $124.4 million from us during the year ended December 31, 2007. This amount includes incentive distributions of $107.4 million.
We and EPGP 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 and affiliates 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. EPCO and its private company affiliates received $355.5 million in cash distributions from us and Enterprise GP Holdings during the year ended December 31, 2007.
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, TEPPCO and us.
An affiliate of EPCO provides us trucking services for the transportation of NGLs and other products. For the year ended December 31, 2007, we paid this trucking affiliate $17.5 million for such services.
We lease office space in various buildings from affiliates of EPCO. The rental rates in these lease agreements approximate market rates. For the year ended December 31, 2007, we paid EPCO $5.6 million for office space leases.
EPCO Administrative Services Agreement. We have no employees. All of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to an administrative services agreement (the “ASA”). We, Duncan Energy Partners, Enterprise GP Holdings, TEPPCO and our respective general partners are parties to the ASA. The significant terms of the ASA are as follows:
§
EPCO will provide selling, general and administrative services, and management and operating services, as may be necessary to manage and operate our businesses, properties and assets (all in accordance with prudent industry practices). EPCO will employ or otherwise retain the services of such personnel as may be necessary to provide such services.
§
We are required to reimburse EPCO for its services in an amount equal to the sum of all costs and expenses incurred by EPCO which are directly or indirectly related to our business or activities (including expenses reasonably allocated to us by EPCO). In addition, we have agreed to pay all sales, use, excise, value added or similar taxes, if any, that may be applicable from time to time in respect of the services provided to us by EPCO.
§
EPCO will allow us to participate as named insureds in its overall insurance program, with the associated premiums and other costs being allocated to us.
Under the ASA, EPCO subleases to us (for $1 per year) certain equipment which it holds pursuant to operating leases and has assigned to us its purchase option under such leases (the “retained leases”). EPCO remains liable for the actual cash lease payments associated with these agreements. We record the full value of these payments made by EPCO on our behalf as a non-cash related party operating lease expense, with the offset to partners’ equity accounted for as a general contribution to our partnership. At December 31, 2007, the retained leases were for a cogeneration unit and approximately 100 railcars. Should we decide to exercise the purchase options associated with the retained leases, $2.3 million would be payable in 2008 and $3.1 million in 2016.
Our operating costs and expenses for the year ended December 31, 2007 include reimbursement payments to EPCO for the costs it incurs to operate our facilities, including compensation of employees. We reimburse EPCO for actual direct and indirect expenses it incurs related to the operation of our assets. Such reimbursements were $273.0 million during the year ended December 31, 2007.
Likewise, our general and administrative costs for the year ended December 31, 2007 includes amounts we reimburse to EPCO for administrative services, including compensation of employees. In general, our reimbursement to EPCO for administrative services is either (i) on an actual basis for direct expenses it may incur on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to ASA based on the estimated use of such services by each party (e.g., the allocation of general legal or accounting salaries based on estimates of time spent on each entity’s business and affairs). Such reimbursements were $56.5 million during the year ended December 31, 2007.
The ASA also addresses potential conflicts that may arise among Enterprise Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), Duncan Energy Partners (including DEP GP), and the EPCO Group. The EPCO Group includes EPCO and its other affiliates, but excludes Enterprise Products Partners, Enterprise GP Holdings, Duncan Energy Partners and their respective general partners. With respect to potential conflicts, the ASA provides, among other things, that:
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If a business opportunity to acquire “equity securities” (as defined below) is presented to the EPCO Group, Enterprise Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), Duncan Energy Partners (including DEP GP), then Enterprise GP Holdings will have the first right to pursue such opportunity. The term “equity securities” is defined to include:
§
general partner interests (or securities which have characteristics similar to general partner interests) or interests in “persons” that own or control such general partner or similar interests (collectively, “GP Interests”) and securities convertible, exercisable, exchangeable or otherwise representing ownership or control of such GP Interests; and
§
incentive distribution rights and limited partner interests (or securities which have characteristics similar to incentive distribution rights or limited partner interests) in publicly traded partnerships or interests in “persons” that own or control such limited partner or similar interests (collectively, “non-GP Interests”); provided that such non-GP Interests are associated with GP Interests and are owned by the owners of GP Interests or their respective affiliates.
Enterprise GP Holdings will be presumed to want to acquire the equity securities until such time as EPE Holdings advises the EPCO Group, EPGP and DEP GP that it has abandoned the pursuit of such business opportunity. In the event that the purchase price of the equity securities is reasonably likely to equal or exceed $100 million, the decision to decline the acquisition will be made by the Chief Executive Officer of EPE Holdings after consultation with and subject to the approval of the ACG Committee of EPE Holdings. If the purchase price is reasonably likely to be less than $100 million, the Chief Executive Officer of EPE Holdings may make the determination to decline the acquisition without consulting the ACG Committee of EPE Holdings.
In the event that Enterprise GP Holdings abandons the acquisition and so notifies the EPCO Group, EPGP and DEP GP, Enterprise Products Partners will have the second right to pursue such acquisition. Enterprise Products Partners will be presumed to want to acquire the equity securities until such time as EPGP advises the EPCO Group and DEP GP that Enterprise Products Partners has abandoned the pursuit of such acquisition. In determining whether or not to pursue the acquisition, Enterprise Products Partners will follow the same procedures applicable to Enterprise GP Holdings, as described above but utilizing EPGP’s Chief Executive Officer and ACG Committee.
In its sole discretion, Enterprise Products Partners may affirmatively direct such acquisition opportunity to Duncan Energy Partners. In the event this occurs, Duncan Energy Partners may pursue such acquisition.
In the event Enterprise Products Partners abandons the acquisition opportunity for the equity securities and so notifies the EPCO Group and DEP GP, the EPCO Group may pursue the acquisition or offer the opportunity to TEPPCO (including TEPPCO GP) and their controlled affiliates, in either case, without any further obligation to any other party or offer such opportunity to other affiliates.
§
If any business opportunity not covered by the preceding bullet point (i.e. not involving “equity securities”) is presented to the EPCO Group, Enterprise Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), or Duncan Energy Partners (including DEP GP), Enterprise Products Partners will have the first right to pursue such opportunity either for itself or, if desired by Enterprise Products Partners in its sole discretion, for the benefit of Duncan
Energy Partners. It will be presumed that Enterprise Products Partners will pursue the business opportunity until such time as its general partner advises the EPCO Group, EPE Holdings and DEP GP that it has abandoned the pursuit of such business opportunity.
In the event the purchase price or cost associated with the business opportunity is reasonably likely to equal or exceed $100 million, any decision to decline the business opportunity will be made by the Chief Executive Officer of EPGP after consultation with and subject to the approval of the ACG Committee of EPGP. If the purchase price or cost is reasonably likely to be less than $100 million, the Chief Executive Officer of EPGP may make the determination to decline the business opportunity without consulting EPGP’s ACG Committee.
In its sole discretion, Enterprise Products Partners may affirmatively direct such acquisition opportunity to Duncan Energy Partners. In the event this occurs, Duncan Energy Partners may pursue such acquisition.
In the event that Enterprise Products Partners abandons the business opportunity for itself and Duncan Energy Partners and so notifies the EPCO Group, EPE Holdings and DEP GP, Enterprise GP Holdings will have the second right to pursue such business opportunity. It will be presumed that Enterprise GP Holdings will pursue such acquisition until such time as its general partner declines such opportunity (in accordance with the procedures described above for Enterprise Products Partners) and advises the EPCO Group that it has abandoned the pursuit of such business opportunity. Should this occur, the EPCO Group may either pursue the business opportunity or offer the business opportunity to TEPPCO (including TEPPCO GP) and their controlled affiliates without any further obligation to any other party or offer such opportunity to other affiliates.
None of Enterprise Products Partners, Enterprise GP Holdings, Duncan Energy Partners or their respective general partners or the EPCO Group have any obligation to present business opportunities to TEPPCO (including TEPPCO GP) or their controlled affiliates. Likewise, TEPPCO (including TEPPCO GP) and their controlled affiliates have no obligation to present business opportunities to Enterprise Products Partners, Enterprise GP Holdings, Duncan Energy Partners or their respective general partners or the EPCO Group.
Employee Partnerships. EPCO formed the Employee Partnerships to serve as an incentive arrangement for key employees of EPCO by providing them a “profits interest” in such partnerships. Certain EPCO employees who work on behalf of us and EPCO were issued Class B limited partner interests and admitted as Class B limited partners without any capital contribution. The profits interest awards (i.e., the Class B limited partner interests) in the Employee Partnerships entitles each holder to participate in the appreciation in value of the Parent Company’s Units. For information regarding the Employee Partnerships, see Note 5 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
Relationship with TEPPCO
TEPPCO became a related party to us in February 2005 in connection with the acquisition of TEPPCO GP by a private company subsidiary of EPCO. In May 2007, Enterprise GP Holdings purchased TEPPCO GP from this private company subsidiary of EPCO.
We received $67.6 million from TEPPCO during the year ended December 31, 2007 from the sale of hydrocarbon products. We paid TEPPCO $19.4 million for NGL pipeline transportation and storage services during the year ended December 31, 2007.
In August 2006, we became a joint venture partner with TEPPCO in its Jonah Gas Gathering Company (“Jonah”), which owns the Jonah Gas 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 entered into in February 2006. In connection with the joint venture arrangement, we and TEPPCO plan to continue the Phase V expansion, which is expected to increase the capacity of the Jonah Gathering System from 1.5 Bcf/d to 2.4 Bcf/d and 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 has increased the system gathering capacity to 2.0 Bcf/d, was completed in July 2007 and the final phase of this expansion is expected to be completed by April 2008. The total anticipated cost of the Phase V expansion is expected to be approximately $505.0 million. We continue to manage the Phase V construction project.
Since August 1, 2006, we and TEPPCO have equally shared in the construction costs of the Phase V expansion. TEPPCO has reimbursed us $261.6 million, which represents 50% of total Phase V costs incurred through December 31, 2007. We had a receivable of $9.9 million from TEPPCO at December 31, 2007 for Phase V expansion costs.
TEPPCO was entitled to all distributions from the joint venture until specified milestones were achieved, at which point, we became entitled to receive 50% of the incremental cash flow from portions of the system placed in service as part of the expansion. Since the first phase of this expansion was reached in July 2007, we and TEPPCO have shared earnings based on a formula that takes into account our respective capital contributions, including expenditures by TEPPCO prior to the expansion.
At December 31, 2007, we owned an approximate 19.4% interest in Jonah and TEPPCO owns 80.6%. We operate the Jonah system. We account for our investment in the Jonah joint venture using the equity method.
The Jonah joint venture is governed by a management committee comprised of two representatives approved by us and two appointed by TEPPCO, each with equal voting power. After an in-depth consideration of all relevant factors, this transaction was approved by the ACG Committee of our general partner and the Audit and Conflicts Committee of the general partner of TEPPCO. The ACG Committee of our general partner received a fairness opinion in connection with this transaction. The transaction was reviewed and recommended for approval by the Audit and Conflicts Committee of TEPPCO GP with assistance from an independent financial advisor.
We have agreed to indemnify TEPPCO from any and all losses, claims, demands, suits, liabilities, costs and expenses arising out of or related to breaches of our representations, warranties, or covenants related to the Jonah joint venture. A claim for indemnification cannot be filed until the losses suffered by TEPPCO exceed $1.0 million. The maximum potential amount of future payments under the indemnity agreement is limited to $100.0 million. All indemnity payments are net of insurance recoveries that TEPPCO may receive from third-party insurance carriers. We carry insurance coverage that may offset any payments required under the indemnification.
In January 2007, we purchased a 10-mile segment of pipeline from TEPPCO located in the Houston area for $8.0 million. This pipeline segment is part of the DEP South Texas NGL Pipeline System that commenced operations in January 2007. In addition, we entered into a lease with TEPPCO for an 11-mile interconnecting pipeline located in the Houston area that is part of the DEP South Texas NGL Pipeline System. Although the primary term of the lease expired in September 2007, it is being renewed on a month-to-month basis until construction of a parallel pipeline is completed in early 2008. These transactions were in accordance with the Board-approved management authorization policy.
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 eight months ended December 31, 2007, we recorded $294.4 million of revenues from Energy Transfer Partners, L.P. (“ETP”), primarily from NGL marketing activities. We incurred $35.2 million in operating costs and expenses for the eight months ended December 31, 2007. 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
Many of our unconsolidated affiliates perform supporting or complementary roles to our other business operations. Since we and our affiliates hold ownership interests in these entities and directly or indirectly benefit from our related party transactions with such entities, they are presented here. The following information summarizes significant related party transactions with our current unconsolidated affiliates:
Relationship with Duncan Energy Partners
In September 2006, we formed a consolidated subsidiary, Duncan Energy Partners, to acquire, own and operate a diversified portfolio of midstream energy assets and to support the growth objectives of EPO. On February 5, 2007, this subsidiary completed its initial public offering of 14,950,000 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 Enterprise Products Partners (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.
In addition to the 34% direct ownership interest we retained in certain subsidiaries of Duncan Energy Partners, we also own the 2% general partner interest in Duncan Energy Partners and 26.4% of Duncan Energy Partners’ outstanding common units. EPO directs the business operations of Duncan Energy Partners through its control of Duncan Holdings, LLC (“DEP GP”). Certain of our officers and directors are also beneficial owners of common units of Duncan Energy Partners (see Item 12).
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.
We have significant involvement with all of the subsidiaries of Duncan Energy Partners, including the following types of transactions: (i) we utilize storage services provided by Mont Belvieu Caverns to support our Mont Belvieu fractionation and other businesses; (ii) we buy natural gas from and sell natural gas to Acadian Gas in connection with our normal business activities; and (iii) we are the sole shipper on the DEP South Texas NGL Pipeline System.
We may contribute other equity interests in our subsidiaries to Duncan Energy Partners in the near term and use the proceeds we receive from Duncan Energy Partners to fund our capital spending program.
For additional information regarding Duncan Energy Partners, see “Other Items - Initial Public Offering of Duncan Energy Partners” under Item 7 of this annual report.
Omnibus Agreement. On February 5, 2007, EPO and Duncan Energy Partners entered into an Omnibus Agreement that governs our relationship with Duncan Energy Partners on the following matters:
§
indemnification for certain environmental liabilities, tax liabilities and right-of-way defects;
§
reimbursement of certain expenditures incurred by DEP South Texas NGL and Mont Belvieu Caverns;
§
a right of first refusal to EPO in Duncan Energy Partners’ current and future subsidiaries and a right of first refusal on the material assets of these entities, other than sales of inventory and other assets in the ordinary course of business; and
§
a preemptive right with respect to equity securities issued by certain of Duncan Energy Partners’ subsidiaries, other than as consideration in an acquisition or in connection with a loan or debt financing.
EPO has indemnified Duncan Energy Partners against certain pre-February 2007 environmental and related liabilities associated with the assets EPO contributed to Duncan Energy Partners at the time of its initial public offering. These liabilities include both known and unknown environmental and related liabilities. This indemnification obligation will terminate on February 5, 2010. There is an aggregate cap of $15.0 million on the amount of indemnity coverage. In addition, Duncan Energy Partners is not entitled to indemnification until the aggregate amount of claims it incurs exceeds $250 thousand. Liabilities resulting from a change of law after February 5, 2007 are excluded from the EPO environmental indemnity. In addition, EPO has indemnified Duncan Energy Partners for liabilities related to:
§
certain defects in the easement rights or fee ownership interests in and to the lands on which any assets contributed to Duncan Energy Partners in connection with its initial public offering are located and failure to obtain certain consents and permits necessary to conduct its business that arise through February 5, 2010; and
§
certain income tax liabilities attributable to the operation of the assets contributed to Duncan Energy Partners in connection with its initial public offering prior to February 5, 2007.
The Omnibus Agreement may not be amended without the prior approval of the ACG Committee if the proposed amendment will, in the reasonable discretion of DEP GP, adversely affect holders of the it’s common units.
Neither we, nor EPO and any of its affiliates are restricted under the Omnibus Agreement from competing with Duncan Energy Partners. Except as otherwise expressly agreed in the EPCO administrative services agreement, EPO and any of its affiliates may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer Duncan Energy Partners the opportunity to purchase or construct those assets. These agreements are in addition to other agreements relating to business opportunities and potential conflicts of interest set forth in the administrative services agreement with EPO, EPCO and other affiliates of EPCO.
Under the Omnibus Agreement, EPO agreed to make additional contributions to Duncan Energy Partners as reimbursement for its 66% share of any excess construction costs above (i) the $28.6 million of estimated capital expenditures to complete the Phase II expansions of the DEP South Texas NGL Pipeline System and (ii) $14.1 million of estimated construction costs for additional brine production capacity and above-ground storage reservoir projects at Mont Belvieu, Texas. Both projects were underway at the time of Duncan Energy Partners’ initial public offering. In December 2007, EPO made contributions totaling $9.9 million to Duncan Energy Partners’ subsidiaries in connection with this provision of the Omnibus Agreement.
Review and Approval of Transactions with Related Parties
Our partnership agreement and ACG Committee charter set forth policies and procedures for the review and approval of certain transactions with persons affiliated with or related to us. As further described below, our partnership agreement and ACG Committee charter set forth procedures by which related party transactions and conflicts of interest may be approved or resolved by our general partner or the ACG Committee. Under our partnership agreement, whenever a potential conflict of interest exists or arises between our general partner or any of its affiliates, on the one hand, and us, any of our subsidiaries or any partner, on the other hand, any resolution or course of action by our general partner or its affiliates in respect of such conflict of interest is permitted and deemed approved by all of our partners, and will not constitute a breach of our partnership agreement or any agreement contemplated by such agreement, or of any duty stated or implied by law or equity, if the resolution or course of action is or, by operation of the partnership agreement is deemed to be, fair and reasonable to us; provided that, any conflict of interest and any resolution of such conflict of interest will be conclusively deemed fair and reasonable to us if such conflict of interest or resolution is (i) approved by a majority of the members of our ACG Committee (“Special Approval”), or (ii) on terms objectively demonstrable to be no less favorable to us than those generally being provided to or available from unrelated third parties.
The ACG Committee (in connection with Special Approval) is authorized in connection with its resolution of any conflict of interest to consider:
§
the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest;
§
the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership);
§
any customary or accepted industry practices and any customary or historical dealings with a particular person;
§
any applicable generally accepted accounting or engineering practices or principles;
§
the relative cost of capital of the parties and the consequent rates of return to the equity holders of the parties; and
§
such additional factors as the committee determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.
The review and approval process of the ACG Committee, including factual matters that may be considered in determining whether a transaction is fair and reasonable, is generally governed by Section 7.9 of our partnership agreement. As discussed above, the ACG Committee’s Special Approval is conclusively deemed fair and reasonable to us under the partnership agreement.
Related party transactions that do not occur under the ASA and that are not reviewed by the ACG Committee, as described above, may be subject to our general partner’s Board-approved written internal review and approval policies and procedures. These internal policies and procedures, which apply to related party transactions as well as transactions with unrelated parties, specify thresholds for our general partner’s officers and managers to authorize various categories of transactions, including purchases and sales of assets, expenditures, commercial and financial transactions and legal agreements. The specified thresholds for some categories of transactions are less than $120,000 and for others are substantially greater.
In submitting a matter to the ACG Committee, the Board or the general partner may charge the committee with reviewing the transaction and providing the Board a recommendation, or it may delegate to the committee the power to approve the matter. When so engaged, the ACG Committee Charter provides that, unless the ACG Committee determines otherwise, the committee shall perform the following functions:
§
Review a summary of the proposed transaction(s) that outlines (i) its terms and conditions (explicit and implicit), (ii) a brief history of the transaction, and (iii) the impact that the transaction will have on our unitholders and personnel, including earnings per unit and distributable cash flow.
§
Review due diligence findings by management and make additional due diligence requests, if deemed necessary.
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Engage third-party independent advisors, where necessary, to provide committee members with comparable market values, legal advice and similar services directly related to the proposed transaction.
§
Conduct interviews regarding the proposed transaction with the most knowledgeable company officials to ensure that the committee members have all relevant facts before rendering their judgment.
On November 6, 2007, the ACG Committee charter was amended and restated. The amended and restated charter provides, among other things, that the ACG Committee will review and approve related-party transactions (i) for which Board approval is required by the partnership’s management authorization policy (generally, for transactions involving amounts greater than $100 million), (ii) where an officer or director of our general partner or of any partnership subsidiary is a party, (iii) when requested to do so by management of the partnership or the Board, or (iv) pursuant to the limited partnership agreement of the partnership or the limited liability company agreement of our general partner.
In the normal course of business, our management routinely reviews all other related party transactions, including proposed asset purchases and business combinations and purchases and sales of product. As a matter of course, management reviews the terms and conditions of the proposed transactions, performs appropriate levels of due diligence and assesses the impact of the transaction on our partnership. In addition, the ACG Committee reviews a summary of all related party transactions with management on a quarterly basis where the amounts involved exceed $1.0 million and the underlying prices are not market-based. In connection with such review, the ACG Committee received no indication that such transactions were not fair and reasonable to the Company or that management of the Company improperly exercised its authority under our general partner’s written internal review and approval policies and procedures.
The ACG Committee does not separately review individual transactions covered by our administrative services agreement with EPCO, which agreement and related allocation methods have been previously reviewed and approved by the ACG Committee and/or the Board. The administrative services agreement governs numerous day-to-day transactions between us and our subsidiaries and EPCO and its affiliates, including the provision by EPCO of administrative and other services to us and our subsidiaries and our reimbursement of costs for those services.
During the year ended December 31, 2006, the ACG Committee reviewed and approved the purchase of the Pioneer plant from TEPPCO and Jonah Joint Venture with TEPPCO referenced elsewhere in this Item 13. All other transactions with related parties were either governed by the administrative services agreement or effected under our general partner’s written internal review and approval policies and procedures.
Director Independence
Messrs. Barnett, Ross and Rampacek have been determined to be independent under the applicable NYSE listing standards and are independent under the rules of the SEC applicable to audit committees. For a discussion of independence standards applicable to the Board and factors considered by the Board in making its independence determinations, please refer to “Corporate Governance” and “ACG Committee” under Item 10 of this annual report.
Item 14.
Item 14. Principal Accountant Fees and Services.
We have engaged Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, “Deloitte & Touche”) as our independent auditor. The following table summarizes fees we paid Deloitte & Touche for independent auditing, tax and related services for each of the last two fiscal years (dollars in thousands):
(1)
Audit fees represent amounts billed for each of the years presented for professional services rendered in connection with (i) the audit of our annual financial statements and internal controls over financial reporting, (ii) the review of our quarterly financial statements or (iii) those services normally provided in connection with statutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters. This information is presented as of the latest practicable date for this annual report.
(2)
Audit-related fees represent amounts we were billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterly reviews. This category primarily includes services relating to internal control assessments and accounting-related consulting.
(3)
Tax fees represent amounts we were billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice, and tax planning. This category primarily includes services relating to the preparation of unitholder annual K-1 statements and partnership tax planning.
(4)
All other fees represent amounts we were billed in each of the years presented for services not classifiable under the other categories listed in the table above. No such services were rendered by Deloitte & Touche during the last two years.
The ACG Committee of our general partner has approved the use of Deloitte & Touche as our independent principal accountant. In connection with its oversight responsibilities, the ACG Committee has adopted a pre-approval policy regarding any services proposed to be performed by Deloitte & Touche. The pre-approval policy includes four primary service categories: Audit, Audit-related, Tax and Other.
In general, as services are required, management and Deloitte & Touche submit a detailed proposal to the ACG Committee discussing the reasons for the request, the scope of work to be performed, and an estimate of the fee to be charged by Deloitte & Touche for such work. The ACG Committee
discusses the request with management and Deloitte & Touche, and if the work is deemed necessary and appropriate for Deloitte & Touche to perform, approves the request subject to the fee amount presented (the initial “pre-approved” fee amount). As part of these discussions, the ACG Committee must determine whether or not the proposed services are permitted under the rules and regulations concerning auditor independence under the Sarbanes-Oxley Act of 2002 as well as rules of the American Institute of Certified Public Accountants. If at a later date, it appears that the initial pre-approved fee amount may be insufficient to complete the work, then management and Deloitte & Touche must present a request to the ACG Committee to increase the approved amount and the reasons for the increase.
Under the pre-approval policy, management cannot act upon its own to authorize an expenditure for services outside of the pre-approved amounts. On a quarterly basis, the ACG Committee is provided a schedule showing Deloitte & Touche’s pre-approved amounts compared to actual fees billed for each of the primary service categories. The ACG Committee’s pre-approval process helps to ensure the independence of our principal accountant from management.
In order for Deloitte & Touche to maintain its independence, we are prohibited from using them to perform general bookkeeping, management or human resource functions, and any other service not permitted by the Public Company Accounting Oversight Board. The ACG Committee’s pre-approval policy also precludes Deloitte & Touche from performing any of these services for us.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules.
(a)(1) Financial Statements
Our consolidated financial statements are included under Part II, Item 8 of this annual report. For a listing of these statements and accompanying footnotes, see “Index to Financial Statements” under Item 8 of this annual report.
(a)(2) Financial Statement Schedules
All schedules, have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.
(a)(3) Exhibits
2.1
Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed December 15, 2003).
2.2
Amendment No. 1 to Merger Agreement, dated as of August 31, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2004).
2.3
Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.2 to Form 8-K filed December 15, 2003).
2.4
Amendment No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.1 to the Form 8-K filed April 21, 2004).
2.5
Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (incorporated by reference to Exhibit 2.4 to Form 8-K filed December 15, 2003).
3.1
Certificate of Limited Partnership of Enterprise Products Partners L.P. (incorporated by reference to Exhibit 3.6 to Form 10-Q filed November 8, 2007).
3.2
Fifth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 8, 2005 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 10, 2005).
3.3
First Amendment to Fifth Amended and Restated Partnership Agreement of Enterprise Products Partners L.P. dated as of December 27, 2007 (incorporated by reference to Exhibit 3.1 to Form 8-K/A filed January 3, 2008).
3.4
Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, dated as of November 7, 2007 (incorporated by reference to Exhibit 3.2 to Form 10-Q filed November 8, 2007).
3.5
Limited Liability Company Agreement of Enterprise Products Operating LLC dated as of June 30, 2007 (incorporated by reference to Exhibit 3.3 to Form 10-Q filed on August 8, 2007).
3.6
Certificate of Incorporation of Enterprise Products OLPGP, Inc., dated December 3, 2003 (incorporated by reference to Exhibit 3.5 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
3.7
Bylaws of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
3.8
Certificate of Limited Partnership of Duncan Energy Partners L.P. (incorporated by reference to Exhibit 3.1 to Duncan Energy Partners L.P. Form S-1 Registration Statement, Reg. No. 333-138371, filed November 2, 2006).
3.9
Amended and Restated Agreement of Limited Partnership of Duncan Energy Partners L.P., dated February 5, 2007 (incorporated by reference to Exhibit 3.1 to Duncan Energy Partners L.P.’s Form 8-K/A filed February 5, 2007).
3.10
First Amendment to Amended and Restated Partnership Agreement of Duncan Energy Partners L.P. dated as of December 27, 2007 (incorporated by reference to Exhibit 3.1 to Duncan Energy Partners L.P.’s Form 8-K filed on January 3, 2008).
4.1
Form of Common Unit certificate (incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-1/A; File No. 333-52537, filed July 21, 1998).
4.2
Indenture dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 10, 2000).
4.3
First Supplemental Indenture dated as of January 22, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
4.4
Second Supplemental Indenture dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31, 2003).
4.5
Third Supplemental Indenture dated as of June 30, 2007, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and U.S. Bank National Association, as successor Trustee (incorporated by reference to Exhibit 4.55 to Form 10-Q filed on August 8, 2007) .
4.6
Amended and Restated Revolving Credit Agreement dated as of November 19, 2007 among Enterprise Products Operating LLC, the financial institutions party thereto as lenders, Wachovia Bank, National Association, as Administrative Agent, Issuing Bank and Swingline Lender, Citibank, N.A. and JPMorgan Chase Bank, as Co-Syndication Agents, and SunTrust Bank, Mizuho Corporate Bank, Ltd. and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Form 8-K filed on November 20, 2007).
4.7
Amended and Restated Guaranty Agreement dated as of November 19, 2007 executed by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.2 to Form 8-K filed on November 20, 2007).
4.8
Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed on October 6, 2004).
4.9
First Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed on October 6, 2004).
4.10
Second Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on October 6, 2004).
4.11
Third Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed on October 6, 2004).
4.12
Fourth Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.5 to Form 8-K filed on October 6, 2004).
4.13
Fifth Supplemental Indenture dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed on March 3, 2005).
4.14
Sixth Supplemental Indenture dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on March 3, 2005).
4.15
Seventh Supplemental Indenture dated as of June 1, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.46 to Form 10-Q filed November 4, 2005).
4.16
Eighth Supplemental Indenture dated as of July 18, 2006 to Indenture dated October 4, 2004 among Enterprise Products Operating L.P., as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to exhibit 4.2 to Form 8-K filed July 19, 2006).
4.17
Ninth Supplemental Indenture, dated as of May 24, 2007, by and among Enterprise Products Operating L.P., as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed by Enterprise Products Partners L.P. on May 24, 2007).
4.18
Tenth Supplemental Indenture, dated as of June 30, 2007, by and among Enterprise Products Operating LLC, as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.54 to Form 10-Q filed August 8, 2007).
4.19
Eleventh Supplemental Indenture, dated as of September 4, 2007, by and among Enterprise Products Operating LLC, as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on September 5, 2007).
4.20
Global Note representing $350 million principal amount of 6.375% Series B Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
4.21
Global Note representing $500 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit 4.8 to Form 10-K filed March 31, 2003).
4.22
Global Notes representing $450 million principal amount of 7.50% Senior Notes due 2011 (incorporated by reference to Exhibit 4.1 to Form 8-K filed January 25, 2001).
4.23
Global Note representing $500 million principal amount of 4.000% Series B Senior Notes due 2007 with attached Guarantee (incorporated by reference to Exhibit 4.14 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).
4.24
Global Note representing $500 million principal amount of 5.600% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.17 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).
4.25
Global Note representing $150 million principal amount of 5.600% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.18 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).
4.26
Global Note representing $350 million principal amount of 6.650% Series B Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit 4.19 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).
4.27
Global Note representing $500 million principal amount of 4.625% Series B Senior Notes due 2009 with attached Guarantee (incorporated by reference to Exhibit 4.27 to Form 10-K for the year ended December 31, 2004 filed on March 15, 2005).
4.28
Global Note representing $250,000,000 principal amount of 5.00% Series B Senior Notes due 2015 with attached Guarantee (incorporated by reference to Exhibit 4.31 to Form 10-Q filed on November 4, 2005).
4.29
Global Note representing $250,000,000 principal amount of 5.75% Series B Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit 4.32 to Form 10-Q filed on November 4, 2005).
4.30
Global Note representing $500,000,000 principal amount of 4.95% Senior Notes due 2010 with attached Guarantee (incorporated by reference to Exhibit 4.47 to Form 10-Q filed November 4, 2005).
4.31
Form of Junior Note, including Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K file July 19, 2006).
4.32
Global Note representing $800,000,000 principal amount of 6.30% Senior Notes due 2017 with attached Guarantee (incorporated by reference to Exhibit 4.38 to Form 10-Q filed November 8, 2007).
4.33
Amended and Restated Credit Agreement dated as of June 29, 2005, among Cameron Highway Oil Pipeline Company, the Lenders party thereto, and SunTrust Bank, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 4.1 to Form 8-K filed on July 1, 2005).
4.34
Replacement Capital Covenant, dated May 24, 2007, executed by Enterprise Products Operating L.P. and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed by Enterprise Products Partners L.P. on May 24, 2007).
4.35
First Amendment to Replacement Capital Covenant dated August 25, 2006, executed by Enterprise Products Operating L.P. in favor of the covered debtholders described therein (Incorporated by reference to Exhibit 99.2 to Form 8-K filed August 25, 2006).
4.36
Purchase Agreement, dated as of July 12, 2006 between Cerrito Gathering Company, Ltd., Cerrito Gas Marketing, Ltd., Encinal Gathering, Ltd., as Sellers, Lewis Energy Group, L.P. as Guarantor, and Enterprise Products Partners L.P., as buyer (incorporated by reference to Exhibit 4.6 to Form 10-Q filed August 8, 2006).
10.1
Transportation Contract between Enterprise Products Operating L.P. and Enterprise Transportation Company dated June 1, 1998 (incorporated by reference to Exhibit 10.3 to Registration Statement Form S-1/A filed July 8, 1998).
10.2***
Enterprise Products 1998 Long-Term Incentive Plan, amended and restated as of November 9 2007 (incorporated by reference to Exhibit 10.1 to Form 10-Q filed on November 8, 2007).
10.3***
Form of Option Grant Award under Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Form 10-Q filed on November 8, 2007).
10.4***
Form of Restricted Unit Grant under the Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to Form 10-Q filed on November 8, 2007).
10.5***
EPE Unit L.P. Agreement of Limited Partnership (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by Enterprise GP Holdings L.P., Commission file no. 1-32610, on September 1, 2005).
10.6***
First Amendment to EPE Unit L.P. Agreement of limited partnership dated August 7, 2007 (incorporated by reference to Exhibit 10.3 to Form 10-Q filed by Duncan Energy Partners L.P. on August 8, 2007).
10.7***
EPE Unit II, L.P. Agreement of Limited Partnership (incorporated by reference to Exhibit 10.13 to Form 10-K filed on February 28, 2007).
10.8***
First Amendment to EPE Unit II, L.P. Agreement of limited partnership dated August 7, 2007 (incorporated by reference to Exhibit 10.4 to Form 10-Q filed by Duncan Energy Partners L.P. on August 8, 2007).
10.9***
EPE Unit III, L.P. Agreement of Limited Partnership dated May 7, 2007 (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K filed by Enterprise GP Holdings L.P. on May 10, 2007).
10.10***
First Amendment to EPE Unit III, L.P. Agreement of limited partnership dated August 7, 2007 (incorporated by reference to Exhibit 10.5 to Form 10-Q filed by Duncan Energy Partners L.P. on August 8, 2007).
10.11***
Enterprise Products Company 2005 EPE Long-Term Incentive Plan (amended and restated) (incorporated by reference to Exhibit 10.1 to Form 8-K filed by Enterprise GP Holdings L.P. on May 8, 2006).
10.12***
Form of Restricted Unit Grant under the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.29 to Amendment No. 3 to Form S-1 Registration Statement (Reg. No. 333-124320) filed by Enterprise GP Holdings L.P. on August 11, 2005).
10.13***
Form of Phantom Unit Grant under the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.30 to Amendment No. 3 to Form S-1 Registration Statement (Reg. No. 333-124320) filed by Enterprise GP Holdings L.P. on August 11, 2005).
10.14***
Form of Unit Appreciation Right Grant (Enterprise Products GP, LLC Directors) based upon the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to Form 8-K filed by Enterprise GP Holdings on May 8, 2006).
10.15***
Enterprise Products 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit A to the Proxy Statement filed on December 31, 2007).
10.16
Fourth Amended and Restated Administrative Services Agreement by and among EPCO, Inc., Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products GP, LLC, Enterprise Products OLPGP, Inc., Enterprise GP Holdings L.P., EPE Holdings, LLC, DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC, DEP Operating Partnership L.P., TEPPCO Partners, L.P., Texas Eastern Products Pipeline Company, LLC, TE Products Pipeline Company, Limited Partnership, TEPPCO Midstream Companies, L.P., TCTM, L.P. and TEPPCO GP, Inc. dated January 30, 2007, but effective as of February 5, 2007 (incorporated by reference to Exhibit 10 to Form 8-K filed February 5, 2007 by Duncan Energy Partners).
10.17
First Amendment to the Fourth Amended and Restated Administrative Services Agreement dated February 28, 2007 (incorporated by reference to Exhibit 10.8 to Form 10-K filed on February 28, 2007).
10.18
Second Amendment to Fourth Amended and Restated Administrative Services Agreement dated August 7, 2007, but effective as of May 7, 2007 (incorporated by reference to Exhibit 10.1 to Form 10-Q filed by Duncan Energy Partners L.P. on August 8, 2007).
10.19
Omnibus Agreement, dated as of February 5, 2007 by and among Enterprise Products Operating L.P., DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC, DEP Operating Partnership, L.P., Enterprise Lou-Tex Propylene Pipeline L.P., Sabine Propylene Pipeline L.P., Acadian Gas, LLC, Mont Belvieu Caverns, LLC, South Texas NGL Pipelines, LLC (incorporated by reference to Exhibit 10.19 to Form 8-K filed February 5, 2007 by Duncan Energy Partners).
10.20
Contribution, Conveyance And Assumption Agreement dated as of February 5, 2007, by and among Enterprise Products Operating L.P., DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC and DEP Operating Partnership, L.P. (incorporated by reference to Exhibit 1.1 to Form 8-K filed February 5, 2007 by Duncan Energy Partners).
10.21
Agreement and Release, dated May 31, 2007, between EPCO, Inc. and Robert G. Phillips (incorporated by reference to Exhibit 10.3 to Form 10-Q filed on August 8, 2007).
10.22
Revolving Credit Agreement, dated as of January 5, 2007, among Duncan Energy Partners L.P., as borrower, Wachovia Bank, National Association, as Administrative Agent, The Bank of Nova Scotia and Citibank, N.A., as Co-Syndication Agents, JPMorgan Chase Bank, N.A. and Mizuho Corporate Bank, Ltd., as Co-Documentation Agents, and Wachovia Capital Markets, LLC, The Bank of Nova Scotia and Citigroup Global Markets Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 10.20 to Amendment No. 2 to Form S-1 Registration Statement (Reg. No. 333-138371) filed January 12, 2007).
10.23
First Amendment to Revolving Credit Agreement, dated as of June 30, 2007, among Duncan Energy Partners L.P., as borrower, Wachovia Bank, National Association, as Administrative Agent, The Bank of Nova Scotia and Citibank, N.A., as Co-Syndication Agents, JPMorgan Chase Bank, N.A. and Mizuho Corporate Bank, Ltd., as Co-Documentation Agents, and Wachovia Capital Markets, LLC, The Bank of Nova Scotia and Citigroup Global Markets Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 4.2 to Form 10-Q filed August 8, 2007 by Duncan Energy Partners).
12.1#
Computation of ratio of earnings to fixed charges for each of the five years ended December 31, 2007, 2006, 2005, 2004 and 2003.
21.1#
List of subsidiaries as of February 1, 2008.
23.1#
Consent of Deloitte & Touche LLP dated February 28, 2008.
31.1#
Sarbanes-Oxley Section 302 certification of Michael A. Creel for Enterprise Products Partners L.P. for the December 31, 2007 annual report on Form 10-K.
31.2#
Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Enterprise Products Partners L.P. for the December 31, 2007 annual report on Form 10-K.
32.1#
Section 1350 certification of Michael A. Creel for the December 31, 2007 annual report on Form 10-K.
32.2#
Section 1350 certification of W. Randall Fowler for the December 31, 2007 annual report on Form 10-K.
*
With respect to any exhibits incorporated by reference to any Exchange Act filings, the Commission file number for Enterprise Products Partners L.P. is 1-14323.
***
Identifies management contract and compensatory plan arrangements.
#
Filed with this report.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on February 29, 2008.
Pursuant to the requirements of the Securities Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated below on February 29, 2008.
Signature
Title (Position with Enterprise Products GP, LLC)
/s/ Dan L. Duncan
Dan L. Duncan
Director and Chairman
/s/ Michael A. Creel
Michael A. Creel
Director, President and Chief Executive Officer
/s/ W. Randall Fowler
W. Randall Fowler
Director, Executive Vice President and Chief Financial Officer
/s/ Richard H. Bachmann
Richard H. Bachmann
Director, Executive Vice President, Chief Legal Officer and Secretary
/s/ Dr. Ralph S. Cunningham
Dr. Ralph S. Cunningham
Director
/s/ E. William Barnett
E. William Barnett
Director
/s/ Charles M. Rampacek
Charles M. Rampacek
Director
/s/ Rex C. Ross
Rex C. Ross
Director
/s/ Michael J. Knesek
Michael J. Knesek
Senior Vice President, Controller and Principal Accounting Officer
Exhibit Index
*
With respect to any exhibits incorporated by reference to any Exchange Act filings, the Commission file number for Enterprise Products Partners L.P. is 1-14323.
***
Identifies management contract and compensatory plan arrangements.
#
Filed with this report.