Item 1.
Our partnership status may be a disadvantage to us in calculating our cost of service for rate-making purposes.
In May 2005, the FERC issued a policy statement permitting the inclusion of an income tax allowance in the cost of service-based rates of a pipeline organized as a tax pass-through partnership entity to reflect actual or potential income tax liability on public utility income, if the pipeline proves that the ultimate owner of its interests has an actual or potential income tax liability on such income. The policy statement also provides that whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. In August 2005, the FERC also dismissed requests for rehearing of its new policy statement. On December 16, 2005, the FERC issued its first significant case-specific review of the income tax allowance issue in another company’s rate case. The FERC reaffirmed its new income tax allowance policy and directed the subject pipeline to provide certain evidence necessary for the pipeline to determine its income tax allowance. The new tax allowance policy and the December 16 order was appealed to the United States Court of Appeals for the District of Columbia Circuit. On May 29, 2007, the Court of Appeals issued its order upholding the FERC policy providing an income tax allowance for any “actual or potential income tax liability” incurred by the respective partners of a limited partnership and the application of the policy in the case before the Court.
Environmental costs and liabilities and changing environmental regulation could materially affect our results of operations, cash flows and financial condition.
Our operations are subject to extensive federal, state and local regulatory requirements relating to environmental affairs, health and safety, waste management and chemical and petroleum products. Governmental authorities have the power to enforce compliance with applicable regulations and permits and to subject violators to civil and criminal penalties, including substantial fines, injunctions or both. Certain environmental laws, including CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to cleanup and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, third parties, including neighboring landowners, may also have the right to pursue legal actions to enforce compliance or to recover for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
We will make expenditures in connection with environmental matters as part of normal capital expenditure programs. However, future environmental law developments, such as stricter laws, regulations, permits or enforcement policies, could significantly increase some costs of our operations, including the handling, manufacture, use, emission or disposal of substances and wastes.
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 our unitholders.
The workplaces associated with our pipelines are subject to the requirements of 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 our unitholders.
We depend on EPO and certain other key customers for a significant portion of our revenues. The loss of any of these key customers could result in a decline in our revenues and cash available to make distributions to our unitholders.
We rely on a limited number of customers for a significant portion of revenues. For the year ended December 31, 2007 and 2006, EPO and its affiliates accounted for approximately 9% and 13% of
our total consolidated revenues, respectively. In addition, several of our assets also rely on only one or two customers for the asset’s cash flow. For example, the only shipper on our DEP South Texas NGL Pipeline System is EPO; there are only two customers on our Lou-Tex Propylene Pipeline; there is only one customer on our Sabine Propylene Pipeline; and there is only one shipper on the pipeline held by Evangeline. In order for new customers to use these pipelines, we or the new shippers would be required to construct interim pipeline connections.
We may be unable to negotiate extensions or replacements of these contracts and those with other key customers on favorable terms. The loss of all or even a portion of the contracted volumes of these customers, as a result of competition, creditworthiness or otherwise, could have a material adverse effect on our financial condition, results of operations and ability to make distributions to our unitholders, unless we are able to contract for comparable volumes from other customers at favorable rates.
We are exposed to the credit risks of our key customers, and any material nonpayment or nonperformance by our key customers could reduce our ability to make distributions to our unitholders.
We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any material nonpayment or nonperformance by our key customers could reduce our ability to make distributions to our unitholders. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks. We generally do not require collateral for our accounts receivable. If we fail to adequately assess the creditworthiness of existing or future customers, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment or nonperformance by them could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
We depend on the leadership and involvement of Dan L. Duncan and other key personnel for the success of our and our subsidiaries’ businesses.
We depend on the leadership, involvement and services of Dan L. Duncan, the founder of EPCO and the Chairman of our general partner. Mr. Duncan has been integral to the success of EPO and the success of EPCO, and will be integral to our success, 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 key members of our senior management team could have a material adverse effect on our business, results of operations, cash flows and financial condition.
Successful development of LNG import terminals outside our areas of operations could reduce the demand for our services.
Development of new, or expansion of existing, LNG facilities outside our areas of operations could reduce the need for customers to transport natural gas from supply basins connected to our pipelines. This could reduce the amount of gas transported by our pipelines for delivery off-system to other intrastate or interstate pipelines serving these customers. If we are not able to replace these volumes with volumes to other markets or other regions, throughput on our pipelines would decline which could have a material adverse effect on our financial condition, results of operations and ability to make distributions to our unitholders.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and facilities are located, and we are therefore subject to the risk of increased costs to maintain necessary land use. We obtain the rights to construct and operate certain of our pipelines and related facilities on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, or increased costs to renew such rights, could have a material adverse
effect on our business, results of operations, financial condition and ability to make distributions to our unitholders.
Mergers among our customers or competitors could result in lower volumes being shipped on our pipelines, thereby reducing the amount of cash we generate.
Mergers among our existing customers or competitors could provide strong economic incentives for the combined entities to utilize systems other than ours and we could experience difficulty in replacing lost volumes and revenues. Because most of our operating costs are fixed, a reduction in volumes would result in not only a reduction of revenues, but also a decline in net income and cash flow of a similar magnitude, which would reduce our ability to meet our financial obligations and make distributions to our unitholders.
Because of our lack of asset and geographic diversification, adverse developments in our pipeline operations would reduce our ability to make distributions to our unitholders.
We rely on the revenues generated from our pipelines and related assets. Furthermore, our assets are concentrated in Texas and Louisiana. Due to our lack of diversification in asset type and location, an adverse development in our business or our operating areas would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.
Terrorist attacks aimed at our facilities or our customers’ 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.
Risks Inherent in an Investment in Us
Enterprise Products Partners and its affiliates, EPO and EPCO and its affiliates may compete with us, and business opportunities may be directed by contract to those affiliates prior to us under the administrative services agreement.
Our partnership agreement does not prohibit Enterprise Products Partners and its affiliates, EPO and EPCO and their affiliates, other than our general partner, from owning and operating natural gas and NGL pipelines and storage assets or engaging in businesses that otherwise compete directly or indirectly with us. In addition, Enterprise Products Partners, EPO and EPCO may acquire, construct or dispose of additional midstream energy or other natural gas assets in the future, without any obligation to offer us the opportunity to purchase or construct any of these assets.
Under the amended and restated administrative services agreement we entered into at the closing of our initial public offering, if any business opportunity, other than a business opportunity to acquire general partner interests and other related equity securities in a publicly traded partnership, is presented to EPCO and its affiliates, us and our general partner, EPO, Enterprise Products Partners and its general partner, or Enterprise GP Holdings and its general partner, then EPO will have the first right to pursue such opportunity for itself or, in its sole discretion, to affirmatively direct the opportunity to us. If EPO abandons the business opportunity for itself or for us, then Enterprise GP Holdings will have the second right to pursue such opportunity. If any business opportunity to acquire general partner interests and other related equity securities in a publicly traded partnership is presented, then Enterprise GP Holdings will have the right to pursue such opportunity before EPO is given the opportunity to pursue it for itself or to direct it to us. Accordingly, we are limited by contract in our ability to take certain business opportunities for our partnership. See Item 13 of this annual report.
Our general partner and its affiliates own a controlling interest in us and have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to your detriment.
As of December 31, 2007, EPO directly owns a 2% general partner interest and approximately 26.4% of our outstanding common units and controls our general partner, which controls us. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage it and our general partner in a manner beneficial to Enterprise Products Partners and its affiliates. Furthermore, certain directors and officers of our general partner may be directors or officers of affiliates of our general partner. Conflicts of interest may arise between Enterprise Products Partners and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These potential conflicts include, among others, the following situations:
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Enterprise Products Partners, EPCO and their affiliates may engage in substantial competition with us on the terms set forth in an amended and restated administrative services agreement.
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Neither our partnership agreement nor any other agreement requires EPCO, Enterprise Products Partners, Enterprise GP Holdings and TEPPCO or their affiliates (other than our general partner) to pursue a business strategy that favors us. Directors and officers of EPCO and the general partners of Enterprise Products Partners, Enterprise GP Holdings and TEPPCO and their affiliates have a fiduciary duty to make decisions in the best interest of their shareholders or unitholders, which may be contrary to our interests.
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Our general partner is allowed to take into account the interests of parties other than us, such as EPCO, Enterprise Products Partners, Enterprise GP Holdings and TEPPCO and their affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders.
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Some of the officers of EPCO who provide services to us also may devote significant time to the business of Enterprise Products Partners, Enterprise GP Holdings and TEPPCO, and will be compensated by EPCO for such services.
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Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. By purchasing common units, unitholders will be deemed to have consented 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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Our general partner determines the amount and timing of asset purchases and sales, operating expenditures, capital expenditures, borrowings, repayments of indebtedness, issuances of additional partnership securities and cash reserves, each of which can affect the amount of cash that is available for distribution to our unitholders.
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Our general partner determines which costs, including allocated overhead, incurred by it and its affiliates are reimbursable by us.
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EPO or TEPPCO may propose to contribute additional assets to us and, in making such proposal, the directors of those entities have a fiduciary duty to their unitholders and not to our unitholders.
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Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.
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Our general partner intends to limit its liability regarding our contractual obligations.
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Our general partner may exercise its rights to call and purchase all of our common units if, at any
time, it and its affiliates own 80% or more of the outstanding common units.
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Our general partner controls the enforcement of obligations owed to us by it and its affiliates, including the administrative services agreement.
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Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
See Item 13 of this annual report for additional information regarding our relationships with EPCO and EPO.
We may be limited in our ability to consummate transactions, including acquisitions with affiliates of our general partner.
We will have inherent conflicts of interest with affiliates of our general partner, including Enterprise Products Partners and TEPPCO. These conflicts may cause the Audit, Conflicts and Governance Committees of these entities not to approve, or unitholders of these entities to dispute, any transactions that may be proposed or consummated between or among us and these affiliates. This may inhibit or prevent us from consummating transactions, including acquisitions, with them.
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, Enterprise Products 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, see 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.
An affiliate of EPO has the power to appoint and remove our directors and management.
Because EPO owns 100% of DEP GP, it has the ability to elect all the members of the board of directors of our general partner. Our general partner has control over all decisions related to our operations. Furthermore, the goals and objectives of EPO relating to us may not be consistent with those of a majority of the public unitholders.
Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.
If at any time our general partner and its affiliates own 80% or more of our outstanding common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the
obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of:
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the average of the daily closing prices of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and
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the highest price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed.
As a result, our unitholders may be required to sell their common units at a price that is less than the initial offering price or, because of the manner in which the purchase price is determined, at a price less than the then current market price of our common units. In addition, this call right may be exercised at an otherwise undesirable time or price and unitholders may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units or other equity securities and exercising its call right. If our general partner exercised its call right, the effect would be to take us private and, if our common units were subsequently deregistered, we might no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. As of February 1, 2008, affiliates of Enterprise Products Partners, which owns our general partner, owned approximately 26.4% of our outstanding common units.
Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its rights to vote or transfer our common units it owns, its registration rights and the determination of whether to consent to any merger or consolidation of the partnership, or amendment to the partnership agreement;
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provides in the absence of bad faith by the Audit, Conflicts and Governance Committee or our general partner, the resolution, action or terms made, taken or provided in connection with a potential conflict of interest transaction will be conclusive and binding on all persons (including all partners) and will not constitute a breach of the partnership agreement or any standard of care or duty imposed by law;
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provides the general partner shall not be liable to the partnership or any partner for its good faith reliance on the provisions of the partnership agreement to the extent it has duties, including fiduciary duties, and liabilities at law or in equity;
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generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the audit and conflicts committee of the board of directors of our general partner must be on terms no less favorable to us than those generally provided to or available from unrelated third parties or be “fair and reasonable” to us;
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provides that it shall be presumed that the resolution of any conflicts of interest by our general partner or the audit, conflicts and governance committee was not made in bad faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting
such proceeding will have the burden of overcoming such presumption; and
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provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.
By purchasing a common unit, a unitholder will become bound by the provisions of our partnership agreement, including the provisions described above.
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.
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 will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, is chosen entirely by its owners and not by the unitholders. Furthermore, even if our unitholders were dissatisfied with the performance of our general partner, they will, practically speaking, have a limited ability to remove our general partner. As a result of these limitations, the price at which our common units trade could be diminished because of the absence or reduction of a control premium in the trading price.
The vote of the holders of at least 66 2/3% of all outstanding common units is required to remove our general partner. Enterprise Products Partners and its affiliates currently own approximately 26.4% of our outstanding common units.
We may issue additional units without our unitholders’ approval, which would dilute our unitholders’ ownership interests.
At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement does not give unitholders the right to approve our issuance of equity securities ranking junior to our common units at any time. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to our common units. The issuance by us of additional common units or other equity securities will have the following effects:
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the ownership interest of unitholders 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 relative voting strength of each previously outstanding common unit may be diminished;
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the ratio of taxable income to distributions may increase; and
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the market price of our common units may decline.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Our partnership agreement restricts unitholders’ voting rights by providing that any common units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information
about our operations, as well as other provisions limiting common unitholders’ ability to influence the manner or direction of management.
We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to make distributions to our unitholders.
We are a partnership holding company and our operating subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets, other than the ownership interests, in our subsidiaries and joint ventures. As a result, our ability to make distributions to our unitholders depends on the performance of our subsidiaries and joint ventures and their ability to distribute funds to us. The ability of our subsidiaries and joint ventures to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations, including FERC policies. For example, all cash flows from Evangeline are currently used to service its debt.
Affiliates of Enterprise Products Partners currently own a 34% minority equity interest in all of our operating subsidiaries and have a right of first refusal to acquire these subsidiaries or their material assets if we desire to sell them, other than inventory and other assets sold in the ordinary course of business. These rights may adversely affect our ability to dispose of these assets. In addition, our ownership interest in Mont Belvieu Caverns may be diluted, and the cash flow from our NGL & Petrochemical Storage Services segment may be reduced, if we do not contribute our proportionate share of certain future costs to fund expansion projects at Mont Belvieu Caverns.
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 common units and other limited partner interests may decrease in direct correlation with decreases in the amount we distribute per common unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue more equity to recapitalize.
Cost reimbursements to EPCO and its affiliates will reduce cash available for distribution to our unitholders.
Prior to making any distribution on our common units, we will reimburse EPCO and its affiliates 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, including allocated overhead, to EPCO and its affiliates could adversely affect our ability to make distributions to our unitholders. 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.
Unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business.
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. Unitholders 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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unitholders’ 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, 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.
Our general partner’s interest in us and the control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of DEP GP or EPO to transfer their equity interests in our general partner or 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 distributions to our unitholders would be substantially reduced.
The anticipated after-tax 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 income at the corporate tax rate, which is currently a maximum of 35%. Distributions to our unitholders could generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits could flow through to unitholders. Because a tax could be imposed upon us as a corporation, our cash available for distribution to our common unitholders could be substantially reduced. Thus, treatment of us as a corporation could 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, our operating subsidiaries are subject to a newly revised Texas franchise tax (the “Revised Texas Franchise Tax”) on the portion of their revenue that is generated in Texas beginning for tax reports due on or after January 1, 2008. 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 could 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. Any modification 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 of these changes, or other proposals, 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 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 resulting 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 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 by us, which decreases the unitholder’s tax basis in a 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.
Investment 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 treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could result in a decrease in the value of our common units.
Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could decrease 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, such as 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 own property or conduct business in Louisiana and Texas. We may own property or conduct business in other states or foreign countries in the future. It is the responsibility of the common unitholders to file all federal, state and local tax returns.
The sale or exchange of 50% or more of our capital and profits interests during a 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.
Item 1B. Unresolved Staff Comments.
None.
Item 3. Legal Proceedings.
On occasion, we are named as a defendant in litigation relating to our normal business operations, including regulatory and environmental matters. Although we insure 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 activity.
In 1997, Acadian Gas and numerous other energy companies were named as defendants in actions brought by Jack Grynberg on behalf of the U.S. Government under the False Claims Act. Generally, these complaints allege an industry-wide conspiracy to underreport the heating value, as well as the volumes, of natural gas produced from federal and Native American lands. The complaint alleges that the U.S. Government was deprived of royalties as a result of this conspiracy. The plaintiff in this case seeks royalties that he contends the U.S. government should have received had the heating value and volume been differently measured, analyzed, calculated and reported, together with interest, treble damages, civil penalties, expenses and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. These matters have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming, filed June 1997). On October 20, 2006, the U.S. District Court dismissed all of Grynberg’s claims with prejudice. Grynberg has appealed the matter.
We are not aware of any other significant litigation, pending or threatened, that may have a significant adverse effect on our financial position or results of operations.
Item 4. Submission of Matters to a Vote of Unitholders.
None.
PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.
We completed our initial public offering on February 5, 2007. Our common units are listed on the NYSE under the ticker symbol “DEP.” As of February 1, 2008, there were approximately 30 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 per unit 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.
We had no sales of unregistered securities during the eleven months ended December 31, 2007 and we have no common units authorized for issuance under an equity compensation plan. We did not repurchase any of our common units during the eleven months ended December 31, 2007.
Item 6. Selected Financial Data.
The following table presents selected historical consolidated financial data of Duncan Energy Partners and combined financial data of Duncan Energy Partners Predecessor. This information has been derived from our audited financial statements and should be read in conjunction with such statements included under Item 8 of this annual report. As presented in the table, amounts are in thousands (except per unit data).
(1)
Represents income before the cumulative effect of changes in accounting principles.
(2)
Represents cash distributions declared by the Partnership with respect to the eleven-month period since its initial public offering.
(3)
Total assets have increased since our initial public offering due to our capital spending program.
(4)
Represents the Partnership’s revolving credit facility. See Note 11 of the Notes to Financial Statements included under Item 8 of this annual report.
Information regarding our consolidated results of operations and liquidity and capital resources can be found under Item 7 of this annual report. The historical combined financial information of Duncan Energy Partners Predecessor reflects the assets, liabilities and operations contributed to us by EPO at the closing of our initial public offering on February 5, 2007 (effective February 1, 2007 for financial accounting and reporting purposes). Our historical consolidated financial information differs from the combined financial information of the Predecessor due to a variety of factors, including the following:
§
Partial ownership of operating assets;
§
No historical results for our NGL Pipelines & Services Segment;
§
Increase in outstanding indebtedness;
§
Increased storage fees;
§
Special allocation of storage well and operational measurement gains and losses;
§
Decrease in propylene transportation rates; and
§
Additional general and administrative expenses.
For additional information regarding these factors, see “Basis of Financial Statement Presentation” included under Item 7 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 financial statements and accompanying notes included under Item 8 of this annual report. Our discussion and analysis includes the following:
§
Cautionary Note Regarding Forward-Looking Statements.
§
Significant Relationships Referenced in this Discussion and Analysis.
§
Overview of Business.
§
Recent Developments - Discusses significant developments since our initial public offering in February 2007.
§
Basis of Financial Statement Presentation.
§
Results of Operations - Discusses material year-to-year variances in our Statements of Consolidated/Combined Operations.
§
Liquidity and Capital Resources - Addresses available sources of liquidity and capital resources and includes a discussion of our capital spending program.
§
Critical Accounting Policies and Estimates.
§
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
BBtus
Bcf
MBPD
MMBbls
MMBtus
MMcf
= per day
= billion British thermal units
= billion cubic feet
= thousand barrels per day
= million barrels
= million British thermal units
= million cubic feet
Our financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”).
Cautionary Note Regarding Forward-Looking Statements
This annual report 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 and interest rates. 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.
Interest Rate Risk Hedging Program
As presented in the following table, 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, we executed three floating-to-fixed interest rate swaps having a combined notional value of $175 million. The purpose of entering into transactions is to reduce the sensitivity of our earnings to variable interest rates charged under our revolving credit facility. We recognized a $0.2 million benefit from these swaps in interest expense during 2007, which includes ineffectiveness of $0.2 million and income of $0.4 million. In 2008, we expect 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).
Commodity Risk Hedging Program
In addition to its natural gas transportation business, Acadian Gas engages in the purchase and sale of natural gas to third party customers in the Louisiana area. The price of natural gas fluctuates in response to changes in supply, market uncertainty, and a variety of additional factors that are beyond our control. We may use commodity financial instruments such as futures, swaps and forward contracts to mitigate such risks. In general, the types of risks we attempt to hedge are those related to the variability of future earnings and cash flows resulting from changes in applicable commodity prices. The commodity financial instruments we utilize may be settled in cash or with another financial instrument.
Acadian Gas also enters into a small number of cash flow hedges in connection with its purchase of natural gas held-for-sale to third parties. In addition, Acadian Gas enters into a limited number of offsetting mark-to-market financial instruments that effectively fix the price of natural gas for certain of its customers.
Historically, the use of commodity financial instruments by Acadian Gas was governed by policies established by the general partner of Enterprise Products Partners. Our general partner now monitors the hedging strategies associated with the physical and financial risks of Acadian Gas, approves specific activities subject to the policy (including authorized products, instruments and markets) and establishes specific guidelines and procedures for implementing and ensuring compliance with the policy.
The fair value of the Acadian Gas commodity financial instrument portfolio was a negligible amount at both December 31, 2007 and 2006. We recorded losses of $0.7 million and $0.4 million for the eleven months ended December 31, 2007 and for the one month ended January 31, 2007. We also recorded losses of $0.8 million and $0.2 million for the years ended December 31, 2006 and 2005, respectively.
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 dates indicated within the following table. The following table presents the effect of hypothetical price movements on the estimated fair value (“FV”) of this portfolio at the dates presented (dollars in thousands):
Product purchase commitments
Acadian Gas has a long-term natural gas purchase contract with a third party. This purchase agreement expires in January 2013. Our purchase price under this contract approximates the market price of natural gas at the time we take delivery of the volumes. For additional information regarding our commitments, please read “Contractual Obligations” under Item 7 of this annual report.
Item 8.
Item 8. Financial Statements and Supplementary Data.
DUNCAN ENERGY PARTNERS L.P.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Unitholders of
DEP Holdings, LLC, the general partner of Duncan Energy Partners L.P.
Houston, Texas
We have audited the accompanying consolidated balance sheet of Duncan Energy Partners L.P. and subsidiaries (the “Company”) as of December 31, 2007 and the combined balance sheet of Duncan Energy Partners Predecessor (the “Predecessor”) as of December 31, 2006, and the related consolidated statements of operations and comprehensive income, cash flows and partners’ equity for the eleven months ended December 31, 2007 for the Company, and the related combined statements of operations and comprehensive income, cash flows and owners’ net investment for the month ended January 31, 2007 and for each of the two years in the period ended December 31, 2006 for the Predecessor. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 financial statements present fairly, in all material respects, the consolidated financial position of Duncan Energy Partners L.P. and subsidiaries at December 31, 2007, and the results of their consolidated operations and their cash flows for the eleven months in the period ended December 31, 2007 for the Company, and the combined financial position of Duncan Energy Partners Predecessor at December 31, 2006, and the combined results of its operations and its cash flows for the month ended January 31, 2007, and each of the two years in the period ended December 31, 2006 for the Predecessor, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 28, 2008
DUNCAN ENERGY PARTNERS L.P.
CONSOLIDATED/COMBINED BALANCE SHEETS
(Dollars in thousands)
See Notes to Financial Statements
DUNCAN ENERGY PARTNERS L.P.
STATEMENTS OF CONSOLIDATED/COMBINED OPERATIONS
AND COMPREHENSIVE INCOME
(Dollars in thousands)
See Notes to Financial Statements
DUNCAN ENERGY PARTNERS L.P.
STATEMENTS OF CONSOLIDATED/COMBINED CASH FLOWS
(Dollars in thousands)
See Notes to Financial Statements
DUNCAN ENERGY PARTNERS L.P.
STATEMENTS OF CONSOLIDATED PARTNERS’ EQUITY/OWNERS’ NET INVESTMENT
(Dollars in thousands)
See Notes to Financial Statements
DUNCAN ENERGY PARTNERS L.P.
NOTES TO FINANCIAL STATEMENTS
Except per unit amounts, or as noted within the context of each footnote disclosure, dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.
Note 1. Background and Basis of Financial Statement Presentation
Partnership Organization
Duncan Energy Partners L.P. (the “Partnership”) 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 “DEP.” The Partnership was formed in September 2006 to acquire, own and operate a diversified portfolio of midstream energy assets and to support the growth objectives of EPO. The Partnership is owned 98% by its limited partners and 2% by its general partner, DEP Holdings, LLC, which is a wholly owned subsidiary of Enterprise Products Operating LLC. DEP Holdings, LLC is responsible for managing all of the Partnership’s operations and activities. EPCO Inc. provides all employees and certain administrative services for the Partnership.
On February 5, 2007, the Partnership completed its initial public offering of 14,950,000 common units (including an overallotment amount of 1,950,000 common units) at a price of $21.00 per unit, which generated net proceeds to the Partnership of $290.5 million. As consideration for assets contributed and reimbursement for capital expenditures related to these assets, the Partnership distributed $260.6 million of these net proceeds to Enterprise Products Operating LLC, plus $198.9 million in borrowings under its credit facility and a final amount of 5,351,571 common units (after giving the effect to the redemption of 1,950,000 common units).
Duncan Energy Partners L.P. did not own any assets prior to February 5, 2007. The business and operations of Duncan Energy Partners L.P. prior to February 5, 2007 are referred to as “Duncan Energy Partners Predecessor” or “Predecessor.” Unless the context requires otherwise, references to “we,” “us,” “our,” “the Partnership” or “Duncan Energy Partners” are intended to mean the business and operations of Duncan Energy Partners L.P. and its consolidated subsidiaries since February 5, 2007.
References to “DEP GP” mean DEP Holdings, LLC, which is our general partner.
References to “DEP Operating Partnership” mean DEP Operating Partnership, L.P., which is a wholly owned subsidiary of Duncan Energy Partners that conducts substantially all of its business.
References to “Enterprise Products Partners” mean Enterprise Products Partners L.P., which owns 100% of Enterprise Products Operating LLC. Enterprise Products Partners is a publicly traded partnership, the common units of which are listed on the NYSE under the ticker symbol “EPD.”
References to “EPO” mean Enterprise Products Operating LLC (as successor in interest by merger to Enterprise Products Operating L.P.), which is our Parent, and its consolidated subsidiaries. EPO owns a 100% interest in the Partnership’s general partner and is a significant owner of the Partnership’s common units.
References to “EPGP” mean Enterprise Products GP, LLC, the general partner of Enterprise Products Partners.
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 L.P.
References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. (“ETP”). Energy Transfer Equity is a publicly traded Delaware limited partnership, the registered limited partnership interests of which are listed on the NYSE under the ticker symbol “ETE.” The general partner of Energy Transfer Equity is LE GP, LLC (“LE GP”). On May 7, 2007, Enterprise GP Holdings acquired non-controlling interests in both LE GP and Energy Transfer Equity.
References to “Enterprise GP Holdings” mean Enterprise GP Holdings L.P., which owns EPGP, TEPPCO GP and limited partner interests in Enterprise Products Partners and TEPPCO. Enterprise GP Holdings is a publicly traded partnership, the units of which are listed on the NYSE under the ticker symbol “EPE.”
References to “EPE Holdings” mean EPE Holdings, LLC, which is the general partner of Enterprise GP Holdings.
References to “EPCO” mean EPCO, Inc., which is a related party affiliate to all of the foregoing named entities.
All of the aforementioned entities are affiliates and under common control of Mr. Dan L. Duncan, the Group Co-Chairman and controlling shareholder of EPCO.
Predecessor Company
Duncan Energy Partners Predecessor was engaged in the business of (i) receiving, storing and delivering natural gas liquids (“NGLs”) and petrochemical products, (ii) gathering, transporting, storing and marketing natural gas and (iii) transporting propylene. The principal business entities included in the historical combined financial statements of Duncan Energy Partners Predecessor are (on a 100% basis): (i) Mont Belvieu Caverns, LLC (“Mont Belvieu Caverns”), a Delaware limited liability company; (ii) Acadian Gas, LLC (“Acadian Gas”), a Delaware limited liability company; (iii) Enterprise Lou-Tex Propylene Pipeline L.P. (“Lou-Tex Propylene”), a Delaware limited partnership, including its general partner; (iv) Sabine Propylene Pipeline L.P. (“Sabine Propylene”), a Delaware limited partnership, including its general partner; and (v) South Texas NGL Pipelines, LLC (“South Texas NGL”), a Delaware limited liability company. EPO contributed a 66% equity interest in each of these five entities to us on February 5, 2007. EPO retained the remaining 34% equity interests in each of these subsidiaries.
The following is a brief description of the businesses of which 66% of the ownership interests were contributed to us by EPO effective February 1, 2007:
§
Mont Belvieu Caverns owns and operates 33 salt dome caverns located in Mont Belvieu, Texas, with an underground storage capacity of approximately 100 million barrels (“MMBbls”), and a brine system with approximately 20 MMBbls of above ground storage capacity and two brine production wells. Mont Belvieu Caverns gathers, stores and delivers NGLs and petrochemical products for industrial customers located along the upper Texas Gulf Coast.
§
Acadian Gas gathers, transports, stores and markets natural gas in Louisiana utilizing over 1,000 miles of high-pressure transmission pipelines and lateral and gathering lines with an aggregate throughput capacity of one billion cubic feet per day (“Bcf/d”) including a 27-mile pipeline owned by its joint venture unconsolidated affiliate, Evangeline Gas Pipeline L.P., (“Evangeline”) and a leased storage cavern with 3 Bcf of storage capacity (see Note 9).
§
Lou-Tex Propylene owns a 263-mile pipeline used to transport chemical-grade propylene from Sorrento, Louisiana to Mont Belvieu, Texas.
§
Sabine Propylene owns a 21-mile pipeline used to transport polymer-grade propylene from Port Arthur, Texas to a pipeline interconnect in Cameron Parish, Louisiana on a transport-or-pay basis.
§
South Texas NGL owns a 286-mile pipeline system extending from Corpus Christi, Texas to Mont Belvieu, Texas. In January 2007, this pipeline commenced transportation of NGLs from two of EPO’s processing facilities located in South Texas to Mont Belvieu, Texas.
The financial information and related notes included under this Item that pertain to periods prior to our initial public offering reflect the assets, liabilities and operations contributed to us by EPO at the closing of our initial public offering on February 5, 2007 (effective February 1, 2007 for financial accounting and reporting purposes). The historical financial information has been prepared using EPO’s separate historical accounting records related to the operations owned by Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene, Sabine Propylene and South Texas NGL. We refer to these historical assets, liabilities and operations as the assets, liabilities and operations of Duncan Energy Partners Predecessor.
EPO had owned controlling interests and operated the underlying assets of Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene and Sabine Propylene for several years prior to its contribution of interests in such entities to us. On February 5, 2007, DEP Operating Partnership (the primary operating subsidiary of the Partnership) directly or indirectly assumed such operating responsibilities.
EPO may contribute or sell other equity interests in its subsidiaries or other of its or its subsidiaries’ assets to the Partnership and use the proceeds it receives to fund its capital spending program. EPO has no obligation or commitment to make such contributions or sales to the Partnership.
In certain cases, EPO is responsible for funding 100% of project costs rather than sharing such costs with the Partnership in accordance with the existing sharing ratio of 66% funded by the Partnership and 34% funded by EPO. See Note 15 for information regarding recent cash contributions made by EPO in connection with the Omnibus Agreement and Mont Belvieu Caverns’ limited liability company agreement.
Basis of Financial Statement Presentation
We have presented our results of operations following the completion of our initial public offering separately from those pertaining to Duncan Energy Partners Predecessor. We acquired all of the assets and operations of the Predecessor that are included in our financial statements. There are a number of agreements and other items that went into effect at the time of our initial public offering that affect the comparability of our current operating results with the historical operating results of Duncan Energy Partners Predecessor. These differences include:
§
the fees we charge EPO for underground storage services at the facility owned by Mont Belvieu Caverns increased as a result of new agreements executed in connection with our initial public offering;
§
all storage well measurement gains and losses relating to Mont Belvieu Caverns’ facility are now retained by EPO;
§
Mont Belvieu Caverns now makes a special allocation of operational measurement gains and losses to EPO; and
§
the transportation revenues recorded by Lou-Tex Propylene and Sabine Propylene decreased after our initial public offering due to the assignment of certain exchange agreements to us by EPO.
Our financial statements reflect the accounts of subsidiaries in which we have a controlling interest, after the elimination of all significant intercompany accounts and transactions. In the opinion of management, all adjustments necessary for a fair presentation of the financial statements, in accordance with generally accepted accounting principles in the United States of America (referred to as “GAAP”), have been made.
Note 2. Summary of Significant Accounting Policies
Allowance for Doubtful Accounts
Our allowance for doubtful accounts balance is generally determined based on specific identification and estimates of future uncollectible accounts, as appropriate. Our procedure for recording an allowance for doubtful accounts is based on (i) our historical experience, (ii) the financial stability of our customers and (iii) the levels of credit granted to customers. In addition, we may also increase the allowance account in response to the specific identification of customers involved in bankruptcy proceedings and those experiencing other financial difficulties. On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure we have recorded sufficient reserves to cover potential losses. As applicable our allowance also includes estimates for uncollectible natural gas imbalances based on specific identification of accounts. Our allowance for doubtful accounts was $47 thousand and $0.4 million at December 31, 2007 and 2006, respectively. The reduction in the allowance for doubtful accounts is due to final receipts and adjustments related to a customer involved in a bankruptcy proceeding.
(1)
In 2006 we adjusted the allowance account for the receipt of a contingent asset related to a prior business acquisition.
Cash and Cash Equivalents
Prior to our initial public offering in February 2007, we operated within the EPO cash management program. For purposes of presentation in the Statements of Consolidated/Combined Cash Flows, cash flows received (or used) in financing activities represent transfers of excess cash from us to our prior owners equal to net cash flow provided by operating activities less cash used in investing activities. Such transfers of excess cash are shown as permanent distributions to owners on our Statement of Consolidated Partners’ Equity/Owners’ Net Investment prior to February 2007. Conversely, if cash used in investing activities was greater than net cash flow provided by operating activities, then a deemed permanent contribution by owners was reflected. As a result, our financial statements prior to February 2007 do not present cash balances. Following our initial public offering, we ceased participation in the EPO cash management program and maintain our cash balances separately from affiliates. To the extent that our subsidiaries have operating cash flows beyond their expected needs, such amounts are permanently distributed to the Partnership and EPO at ratios reflective of their interests.
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/Combined 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/combined financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions.
If an investee is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50% and we exercise significant influence over the investee’s operating and financial policies. For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee’s operating and financial policies. Our proportionate share of profits and losses from transactions with our equity method unconsolidated affiliate are eliminated in consolidation and remain on our balance sheet (or those of our equity method investee) in inventory or similar accounts.
To the extent applicable, we would 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 our ownership interest in an investee does not provide us with either control or significant influence over the investee, we would 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 legal counsel evaluate such contingent liabilities, and such evaluations inherently involve an exercise in judgment. In assessing loss contingencies, our legal counsel evaluates the perceived merits of legal proceedings that are pending against us and unasserted claims that may result in proceedings, if any, as well as the perceived merits of the amount of relief sought or expected to be sought therein from each.
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 is accrued in our financial statements. If the assessment indicates that a potential 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, 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 Revenue
In our storage business, we occasionally bill customers in advance of the periods in which we provide storage services. We record such amounts as deferred revenue. We recognize these revenues ratably over the applicable service period. Our deferred revenue was $1.2 million and $1.4 million at December 31, 2007 and 2006, respectively.
Deposits from Customers
Natural gas customers that pose a credit risk are required to make a prepayment (i.e., a deposit) to us in connection with sales transactions. Deposits from customers were approximately $41 thousand and $0.1 million at December 31, 2007 and 2006, respectively.
Earnings per Unit
See Note 16 for more information regarding our earnings per unit.
Environmental Costs
Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s estimate of the ultimate cost to remediate a site. Ongoing environmental compliance costs are charged to expense as incurred. Expenditures to mitigate or prevent future environmental contamination are capitalized. Our operations include activities that are subject to federal and state environmental regulations.
Expenses for environmental compliance and monitoring were $0.1 million, $0.4 million, and $0.3 million during 2007, 2006 and 2005, respectively. Our reserve for environmental remediation projects totaled $0.3 million December 31, 2007.
Equity-Based Compensation
We do not directly employ any of the persons responsible for the management and operations of our businesses. These functions were performed by employees of EPCO pursuant to an administrative services agreement under the direction of the Board of Directors and executive officers of Enterprise Products OLPGP, Inc., the general partner of EPO.
Certain key employees of EPCO participate in long-term incentive compensation plans managed by EPCO. Such awards were immaterial to our consolidated financial position, results of operation, and cash flows for all periods presented in this annual report. The compensation expense we record related to unit-based awards is based on an allocation of the total cost of such incentive plans to EPCO. We record our pro rata share of such costs based on the percentage of time each employee spends on our consolidated business activities. The amount of equity-based compensation allocable to the Company’s businesses was $205 thousand for the eleven months ended December 31, 2007 and nominal amounts for prior periods.
In connection with the incentive plans of EPCO, we record amounts related to restricted unit awards and profit interests. Prior to January 1, 2006, EPCO accounted for these awards using the provisions of Accounting Principles Board Opinion 25, “Accounting for Stock Issued to Employees.” On January 1, 2006, EPCO adopted Statement of Financial Accounting Standard (“SFAS”) 123(R), “Accounting for Stock-Based Compensation,” to account for its equity awards. Upon adoption of this accounting standard, we recognized a cumulative effect of change in accounting principle of $9 thousand (a benefit). 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.
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 (i.e. time-vested units under SFAS 123(R)) 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 (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 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.
Restricted Unit Awards
Under the Enterprise Products 1998 Long-Term Incentive Plan (the “1998 Plan”), EPCO’s key employees who perform management, administrative or operational functions for us or other affiliates of Enterprise Products Partners may be awarded restricted common units of Enterprise Products Partners. In general, 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 non-vested 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 from Enterprise Products Partners equal to the product of the number of restricted units outstanding for the participant and the cash distribution per unit paid by Enterprise Products Partners to its unitholders.
As used in the context of the EPCO plan, the term “restricted unit” represents a time-vested unit under SFAS 123(R). Such awards are non-vested until the required service period expires.
Employee Partnership 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. 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.
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 Enterprise Products Partners’ 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.
At December 31, 2007, the total grant date fair value of the EPE Unit I awards was approximately $12.4 million, of which we are allocated our pro rata share by EPCO. We will recognize our share of these costs in accordance with the EPCO administrative services agreement over a weighted-average period of 2.7 years.
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.
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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 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.
At December 31, 2007, the total grant date fair value of the EPE Unit III awards was approximately $23.0 million, of which we are allocated our pro rata share by EPCO. We will recognize our share of these costs in accordance with the EPCO administrative services agreement over a weighted-average period of 4.4 years.
See Note 21 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.
Estimates
Preparing our financial statements in conformity with GAAP requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during a given 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.
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. We have not recognized any such costs for the periods presented.
Fair Value Information
Due to their short-term nature, accounts receivable, accounts payable and accrued expenses are carried at amounts which reasonably approximate their fair values. The fair values associated with our commodity financial instruments 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)
Represents commodity financial instrument transactions that have either (i) not settled or (ii) 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.
We are exposed to financial market risks, including changes in commodity prices and interest rates. 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.
Interest Rate Risk Hedging Program
In September 2007, we executed three floating-to-fixed interest rate swaps having a combined notional value of $175 million. The purpose of these financial instruments, which are accounted for as cash flow hedges, is to reduce the sensitivity of our earnings to variable interest rates charged under our revolving credit facility. At December 31, 2007, we recognized a $0.2 million benefit from these swaps in interest expense, which includes ineffectiveness of $0.2 million and income of $0.4 million. In 2008, we expect to reclassify $0.7 million of accumulated other comprehensive loss that was generated by these interest rate swaps as an increase to interest expense. The aggregate fair value of these interest rate swaps was a liability of $3.8 million.
Commodity Risk Hedging Program
In addition to its natural gas transportation business, Acadian Gas engages in the purchase and sale of natural gas. The price of natural gas fluctuates in response to changes in supply, market uncertainty, and a variety of additional factors that are beyond our control. Acadian Gas may enter into risk management transactions to manage price risk, basis risk, physical risk or other risks related to its commodity positions on both a short-term (less than 30 days) and a long-term basis, not to exceed 24 months.
Acadian Gas may use commodity financial instruments such as futures, swaps and forward contracts to mitigate such risks. In general, the types of risks Acadian Gas attempts to hedge are those related to the variability of its future earnings and cash flows resulting from changes in applicable commodity prices. The commodity financial instruments that Acadian Gas utilizes may be settled in cash or with another financial instrument.
Acadian Gas enters into a small number of cash flow hedges in connection with its purchase of natural gas held for sale. In addition, Acadian Gas enters into a limited number of offsetting financial instruments that effectively fix the price of natural gas for certain of its customers.
The fair value of the Acadian Gas commodity financial instrument portfolio was a negligible amount at both December 31, 2007 and 2006. We recorded losses of $0.7 million and $0.4 million for the eleven months ended December 31, 2007 and for the one month ended January 31, 2007, respectively. We also recorded losses of $0.8 million $0.2 million and for the years ended December 31, 2006 and 2005, respectively.
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 whenever 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 carrying value of a long-lived asset exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge is recognized equal to the excess of the asset’s carrying value over its estimated fair value. Fair value is defined as the estimated amount at which an asset or liability could be bought or settled, respectively, in an arm’s-length transaction. We measure fair value using market prices or, in the absence of such data, appropriate valuation techniques. We had no such impairment charges during the periods presented.
Impairment Testing for Unconsolidated Affiliate
We evaluate our equity method investment for impairment whenever events or changes in circumstances indicate that there is a potential loss in value of the investment (other than a temporary decline). Examples of such events or changes in circumstances include a history of investee operating losses or long-term adverse changes in the investee’s industry. If we determine that a loss in the investment’s value is attributable to an event other than temporary decline, we adjust the carrying value of the investment to its fair value through a charge to earnings. We had no such impairment charges during the periods presented.
Inventories
Our inventory consists of natural gas volumes 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. As volumes are sold and delivered out of inventory, the average cost of these products is 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.
At December 31, 2007 and 2006, the value of our natural gas inventory was $8.5 million and $13.5 million, respectively. As a result of fluctuating market conditions, we recognize lower of average cost or market (“LCM”) adjustments when the historical cost of our inventory exceeds its net realizable value. These non-cash adjustments are recorded as a component of operating costs and expenses. For the years ended December 31, 2007 and 2006, we recognized LCM adjustments of approximately $0.3 million and $0.2 million, respectively.
Natural Gas Imbalances
Natural gas imbalances result when a customer injects more or less gas into a pipeline than it withdraws. Our imbalance receivables and payables are valued at market prices which represent cost. At December 31, 2007 and 2006, our imbalance receivables were $0.9 million and $2.6 million, respectively. Imbalance receivables are reflected as a component of “Accounts receivable - trade” on our Consolidated Balance Sheets. At December 31, 2007 and 2006, our imbalance payables were $0.4 million and $0.5 million, respectively. Imbalance payables are reflected as a component of “Accrued products payables” on our Consolidated Balance Sheets.
Property, Plant and Equipment
Property, plant and equipment is recorded at cost. Expenditures for major additions and improvements are capitalized and minor replacements, maintenance, and repairs are charged to expense as incurred. We use the expense-as-incurred method for 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.
When property and equipment are retired or otherwise disposed of, the cost and accumulated depreciation are removed from the accounts and any resulting gain or loss is included in results of operations for the respective period. We record depreciation over the estimated useful lives of our assets primarily using the straight-line method for financial statement purposes. We use other depreciation methods (generally accelerated) for tax purposes where appropriate.
We account for asset retirement obligations (“AROs”) using SFAS 143, “Accounting for Asset Retirement Obligations,” as interpreted by Financial Accounting Standards Board Interpretation (“FIN”) 47, “Accounting for Conditional Asset Retirement Obligations.” Asset retirement obligations are legal obligations associated with the retirement of a tangible long-lived asset that result from the asset’s acquisition, construction, development and/or normal operation. An ARO is initially measured at its estimated fair value. Upon initial recognition of an ARO, we record an increase to the carrying amount of the related long-lived asset and an offsetting ARO liability. We depreciate the combined cost of the asset and the capitalized asset retirement obligation using a systematic and rational allocation method over the period during which the long-lived asset is expected to provide benefits. After the initial period of ARO recognition, the ARO liability will change as a result of either the passage of time or revisions to the original estimates of either the amounts of estimated cash flows or their timing. Changes due to the passage of time increase the carrying amount of the liability because there are fewer periods remaining from the initial measurement date until the settlement date. Therefore, the present value of the discounted future settlement amount increases. These changes are recorded as a period cost called accretion expense. Upon settlement, our ARO obligations will be extinguished at either the recorded amount or we will incur a gain or loss on the difference between the recorded amount and the actual settlement cost.
See Note 8 for additional information regarding our property, plant and equipment and related AROs.
Provision for Income Taxes
We are organized as a pass-through entity for income tax purposes. As a result, our partners are responsible for federal income taxes on their share of our taxable income. Our provision for income taxes for the eleven months ended December 31, 2007 and year ended December 31, 2006 is $307 thousand and $21 thousand, respectively. The provision for income taxes is applicable to state tax obligations under the Revised Texas Franchise Tax.
In accordance with FIN 48, “Accounting for Uncertainty in Income Taxes,” we 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.
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 start-up costs. Organization costs include legal fees, promotional costs and similar charges incurred in connection with the formation of a business. We did not record any such costs during the periods presented.
Storage Well and Operational Measurement Gains and Losses
Storage well measurement gains and losses occur when product movements into a storage well are different than those redelivered to customers. In connection with storage agreements entered into between EPO and Mont Belvieu Caverns effective concurrently with the closing of our initial public offering, EPO agreed to assume all storage well measurement gains and losses.
Operational measurement gains and losses are created when product is moved between storage wells and are attributable to pipeline and well connection measurement variances. Beginning February 2007, the Mont Belvieu Caverns’ limited liability company agreement allocates to EPO any items of income or loss relating to net operational measurement gains and losses, including amounts that Mont Belvieu Caverns may retain as handling losses. As such, EPO is required each period to contribute cash to Mont Belvieu Caverns for net operational measurement losses and is entitled to receive distributions from Mont Belvieu Caverns for net operational measurement gains. We continue to record operational measurement gains and losses associated with the operation of our Mont Belvieu storage facility.
However, these operational measurement gains and losses should not affect our net income or have a significant impact on us with respect to the timing of our net cash flows provided by operating activities and, accordingly, we have not established a reserve for operational measurement losses on our balance sheet.
Note 3. Recent Accounting Developments
The following information summarizes recently issued accounting guidance that will or may affect our future financial statements. See Note 6 for new accounting principles adopted.
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.
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
We recognize revenue using the following criteria: (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) collectibility is reasonably assured.
We collect storage revenues under our NGL and petrochemical 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. In addition, we derive brine production revenues from customers that use brine in the production of feedstocks for production of polyvinyl chloride (“PVC”).
Under our natural gas, NGL and petrochemical pipeline transportation contracts, revenue is recognized when volumes have been delivered to customers. Revenue from these contracts is generally based on a fixed fee per unit of volume transported (typically in million British thermal units for natural gas and thousand barrels per day for NGLs and petrochemicals) multiplied by the volume delivered. The transportation fees charged under these arrangements are contractual. All revenue recognized under our NGL transportation agreements is with related parties (see Note 15).
Prior to 2004, Sabine Propylene was regulated by the Federal Energy Regulatory Commission (“FERC”). Lou-Tex Propylene was also subject to the FERC’s jurisdiction until 2005. The revenues recorded by Sabine Propylene and Lou-Tex Propylene during the period in which each entity was regulated were based on the maximum tariff rates approved by the FERC.
We have natural gas sales contracts associated with Acadian Gas whereby revenue is recognized when we sell and deliver a volume of natural gas to customers. Revenues from these sales contracts are based upon market-related prices as determined by the individual agreements.
Note 5. Financial Instruments
We are exposed to financial market risks, including changes in commodity prices and interest rates. 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.
Interest Rate Risk Hedging Program
As presented in the following table, 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, we executed three floating-to-fixed interest rate swaps having a combined notional value of $175 million. The purpose of these financial instruments is to reduce the sensitivity of our earnings to variable interest rates charged under our
revolving credit facility. We recognized a $0.2 million benefit from these swaps in interest expense during 2007, which includes ineffectiveness of $0.2 million and income of $0.4 million. In 2008, we expect 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.
Commodity Risk Hedging Program
In addition to its natural gas transportation business, Acadian Gas engages in the purchase and sale of natural gas to third party customers in the Louisiana area. The price of natural gas fluctuates in response to changes in supply, market uncertainty, and a variety of additional factors that are beyond our control. We may use commodity financial instruments such as futures, swaps and forward contracts to mitigate such risks. In general, the types of risks we attempt to hedge are those related to the variability of future earnings and cash flows resulting from changes in applicable commodity prices. The commodity financial instruments we utilize may be settled in cash or with another financial instrument.
Acadian Gas enters into a small number of cash flow hedges in connection with its purchase of natural gas held-for-sale. In addition, Acadian Gas enters into a limited number of offsetting mark-to-market financial instruments that effectively fix the price of natural gas for certain of its customers.
Historically, the use of commodity financial instruments by Acadian Gas was governed by policies established by the general partner of Enterprise Products Partners. The objective of this policy was to assist Acadian Gas in achieving its profitability goals while maintaining a portfolio with an acceptable level of risk, defined as remaining within the position limits established by the general partner of Enterprise Products Partners. In general, Acadian Gas may enter into risk management transactions to manage price risk, basis risk, physical risk or other risks related to its commodity positions on both a short-term (less than 30 days) and long-term basis, not to exceed 24 months.
The general partner of Enterprise Products Partners monitored the hedging strategies associated with the physical and financial risks of Acadian Gas (such as those mentioned previously), approved specific activities subject to the policy (including authorized products, instruments and markets) and established specific guidelines and procedures for implementing and ensuring compliance with the policy. The Partnership’s general partner will continue such policies in the future.
The fair value of the Acadian Gas commodity financial instrument portfolio was a negligible amount at both December 31, 2007 and 2006. We recorded losses of $0.7 million and $0.4 million for the eleven months ended December 31, 2007 and for one month ended January 31, 2007. We also recorded losses of $0.8 million $0.2 million and for the years ended December 31, 2006 and 2005, respectively.
Note 6. Cumulative Effect of Changes in Accounting Principles
For the year ended December 31, 2007, we did not record any cumulative effect of changes in accounting principles. For the year ended December 31, 2006, we recorded a benefit of $9 thousand related to the implementation of SFAS 123(R).
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 financial statements.
Effect of Implementation of SFAS 123(R)
SFAS 123(R) requires us to recognize compensation expense related to our equity awards based on the fair value of the award at the grant date. The fair value of an equity award is estimated using the Black-Scholes option pricing model. Under SFAS 123(R), the fair value of an award is amortized to earnings on a straight-line basis over the requisite service or vesting period. Previously recognized deferred compensation related to restricted units was reversed on January 1, 2006.
Upon our adoption of SFAS 123(R), we recognized, as a benefit, a cumulative effect of a change in accounting principle of $9 thousand 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. See Note 2 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 $0.6 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 8 for additional information regarding our AROs.
Note 7. Inventories
Our inventory consists of natural gas volumes valued at the lower of average cost or market. At the years ended December 31, 2007 and 2006, the value of our natural gas inventory was $8.5 million and $13.5 million, respectively.
Operating costs and expenses, as presented on our Statements of Consolidated/Combined Operations and Comprehensive Income, included cost of sales amounts related to the sale of natural gas inventory. We recorded costs of sales of $669.3 million, $54.2 million and $795.2 million for the eleven months ended December 31, 2007, for the month of January 2007 and for the year ended December 31, 2006, respectively.
As a result of fluctuating market conditions, we recognize lower of average cost or market (“LCM”) adjustments when the historical cost of our inventory exceeds its net realizable value. These non-cash adjustments are recorded as a component of cost of sales. For the eleven months ended December 31, 2007 and for the month ended January 31, 2007, we recognized LCM adjustments of approximately $0.3 million and $37 thousand, respectively. No LCM adjustments were required during the year ended December 31, 2006.
Note 8. Property, Plant and Equipment
Our property, plant and equipment values and accumulated depreciation balances were as follows at the dates indicated:
(1)
Includes natural gas, NGL and petrochemical pipelines, office furniture and equipment, buildings, and related assets.
(2)
Underground storage facilities include underground product storage caverns and related assets such as pipes and compressors.
(3)
Transportation equipment includes vehicles and similar assets used in our operations.
(4)
In general, the estimated useful life of major components of this category are: pipelines, 18-35 years (with some equipment at 5 years); office furniture and equipment, 3-20 years; and buildings 20-35 years.
(5)
In general, the estimated useful life of underground storage facilities is 20-35 years (with some components at 5 years).
Depreciation expense for the eleven months ended December 31, 2007 and one month ended January 31, 2007 was $26.8 million and $2.2 million, respectively. Depreciation expense was $21.4 million and $19.2 million for the years ended December 31, 2006 and 2005, respectively.
We have recorded conditional AROs in connection with certain right-of-way agreements, leases and regulatory requirements. Conditional AROs are obligations in which the timing and/or amount of settlement are uncertain. None of our assets are legally restricted for purposes of settling AROs. Our accrued liability for AROs was approximately $0.8 million at both December 31, 2007 and 2006. We recorded $62 thousand of accretion expense for the year ended December 31, 2007.
We recorded a cumulative effect of a change in accounting principle of $0.6 million in connection with our implementation of FIN 47 in December 2005, which represents the depreciation and accretion expense we would have recognized had we recorded these conditional AROs when incurred. Based on information currently available, we estimate that annual accretion expense will be approximately $72 thousand, $79 thousand, $86 thousand, $94 thousand and $103 thousand for the years 2008 through 2012, respectively.
Note 9. Investments in and Advances to Unconsolidated Affiliate - Evangeline
Acadian Gas, through a wholly owned subsidiary, owns a collective 49.51% equity interest in Evangeline, which consists of a 45% direct ownership interest in Evangeline Gas Pipeline, L.P. (“EGP”) and a 45.05% direct interest in Evangeline Gas Corp. (“EGC”). EGC also owns a 10% direct interest in EGP. Third parties own the remaining equity interests in EGP and EGC. Acadian Gas does not have a controlling interest in the Evangeline entities, but does exercise significant influence on Evangeline’s operating policies. Acadian Gas accounts for its financial investment in Evangeline using the equity method.
At December 31, 2007 and 2006, the carrying value of our investment in Evangeline was $3.5 million and $3.4 million, respectively. Our Statements of Consolidated/Combined Operations and Comprehensive Income reflects equity earnings from Evangeline of $0.2 million and $25 thousand for the eleven months ended December 31, 2007 and the one month ended January 31, 2007, respectively. We
recorded equity earnings from Evangeline of $1.0 million and $0.3 million for the years ended December 31, 2006 and 2005, respectively. Our investment in Evangeline is classified within our Onshore Natural Gas Pipelines & Services business segment.
Evangeline owns a 27-mile natural gas pipeline system extending from Taft, Louisiana to Westwego, Louisiana that connects three electric generation stations owned by Entergy Louisiana (“Entergy”). Evangeline’s most significant contract is a 21-year natural gas sales agreement with Entergy. Evangeline is obligated to make available-for-sale and deliver to Entergy certain specified minimum contract quantities of natural gas on an hourly, daily, monthly and annual basis. The sales contract provides for minimum annual quantities of 36.75 BBtus, until the contract expires on January 1, 2013. Quantities delivered to Entergy for the years ended December 31, 2007, 2006 and 2005 under the contract totaled 36.77 BBtus, 36.75 BBtus and 37.61 BBtus, respectively.
The sales contract contains provisions whereby Entergy is obligated to pay Evangeline a minimum fee each period, whether or not it is able to take delivery of natural gas volumes. The following table presents these minimum amounts for the annual periods presented:
In connection with the Entergy sales contract, Evangeline has entered into a natural gas purchase contract with Acadian Gas that contains annual purchase provisions. The minimum annual purchase quantities under this contract correspond to the aforementioned Entergy natural gas sales contract. The pricing terms of the sales agreement with Entergy and Evangeline’s purchase agreement with Acadian Gas are based on a weighted-average cost of natural gas each month (subject to certain market index price ceilings and incentive margins) plus a predetermined margin. Due to this pricing methodology, Evangeline’s monthly net sales margin under the Entergy gas sales contract is essentially fixed.
Entergy has the option to purchase the Evangeline pipeline system or an equity interest in Evangeline. In 1991, Evangeline entered into an agreement with Entergy whereby Entergy was granted the right to acquire Evangeline’s pipeline system for a nominal price, plus the assumption of all of Evangeline’s obligations under the natural gas sales contract. The option period begins the earlier of July 1, 2010 or upon the payment in full of Evangeline’s Series B notes as discussed below. It terminates on December 31, 2012. We cannot ascertain when, or if, Entergy will exercise this option. This uncertainty results from factors which include Entergy’s management decisions and regulatory approvals that may be required for Entergy to acquire Evangeline’s assets at the time the option is exercisable.
Summarized financial information of Evangeline is presented below.
Note 10. Intangible Assets
At December 31, 2007 and 2006 our intangible assets consisted primarily of the value attributable to renewable storage contracts with various customers that we acquired in connection with the purchase of storage caverns from a third party in January 2002. We classify these intangible assets within our NGL & Petrochemical Storage Services business segment. Due to the renewable nature of the underlying contracts, we amortize our intangible assets on a straight-line basis over the estimated remaining economic life of the storage assets to which they relate.
The gross value of our intangible assets was $8.1 million at inception. At December 31, 2007 and 2006, the carrying value of these intangible assets was $6.7 million and $7.0 million, respectively. We recorded $0.2 million in amortization expense associated with these intangible assets for all periods presented. Based on information currently available, we estimate that amortization expense associated with existing intangible assets will approximate $0.2 million per year for each of the years 2008 through 2012.
Note 11. Debt Obligations
On February 5, 2007, we entered into a $300.0 million revolving credit facility having a $30.0 million sublimit for Swingline loans. We may also issue up to $300.0 million of letters of credit under this facility. Letters of credit outstanding under this facility reduce the amount available for borrowings. At the closing of our initial public offering, we made an initial draw of $200.0 million under this facility to fund the $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 and letters of credit outstanding were $1.1 million. As of February 1, 2008, we had $1.1 million of letters of credit outstanding. This $200.0 million amount consists of $25.0 million in variable rate obligations and three floating-to-fixed interest rate swaps with a notional value of $175.0 million. See Note 2 - Interest Rate Risk Hedging Program, for more detail concerning our interest rate swaps.
This credit facility matures in February 2011 and will be used by us in the future to fund working capital and other capital requirements and for general partnership purposes. We may make up to two requests for one-year extensions of the maturity date (subject to certain restrictions). The revolving credit facility is also available to help fund distributions. We can increase the borrowing capacity under our 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.
Our revolving credit facility offers the following unsecured loans, each having different minimum amount and interest requirements:
§
London Interbank Offered Rate (“LIBOR”) Loans. LIBOR loans can be exercised in a minimum amount of $5.0 million and multiples of $1.0 million thereafter. No more than eight LIBOR loans may be outstanding at any time under the revolving credit facility. LIBOR loans will bear interest, at a rate per annum, equal to the LIBOR rate plus the applicable LIBOR margin.
§
Base Rate Loans. Base Rate loans can be exercised in a minimum amount of $1.0 million and multiples of $500.0 thousand thereafter. These loans bear interest, at a rate per annum, equal to the Base Rate plus zero. The Base Rate is the higher of (i) the rate of interest publicly announced by the administrative agent, Wachovia Bank, National Association, as its Base Rate and (ii) 0.5% per annum above the Federal Funds Rate in effect on such date.
§
Swingline Loans. Swingline loans can be exercised in a minimum amount of $1.0 million and multiples of $100.0 thousand thereafter. These loans bear interest at the LIBOR rate plus the applicable LIBOR margin.
At December 31, 2007, our year-to-date weighted-average variable interest rate paid was 6.23%. Our interest rates during 2007 ranged from a low of 5.52% to a high of 6.42%.
Borrowings outstanding under our revolving credit facility may be prepaid in whole or in part at any time upon same day notice, in a minimum amount of $3.0 million with respect to LIBOR loans and $1.0 million with respect to Base Rate Loans (or any lesser amount equal to outstanding borrowings), and integral multiples of $1.0 million above that amount. Unless LIBOR loans are prepaid on interest payment dates, breakage costs could be incurred.
The revolving credit facility requires us to maintain a leverage ratio for the prior four fiscal quarters of not more than 4.75 to 1.00 at the last day of each fiscal quarter commencing June 30, 2007; provided, upon the closing of a permitted acquisition, such ratio shall not exceed (a) 5.25 to 1.00 at the last day of the fiscal quarter in which such specified acquisition occurred and at the last day of each of the two fiscal quarters following the fiscal quarter in which such specified acquisition occurred, and (b) 4.75 to 1.00 at the last day of each fiscal quarter thereafter. In addition, prior to obtaining an investment-grade rating by Standard & Poor’s Ratings Services, Moody’s Investors Service or Fitch Ratings, our interest coverage ratio, for the prior four fiscal quarters shall not be less than 2.75 to 1.00 at the last day of each fiscal quarter commencing June 30, 2007.
Our revolving credit facility contains various operating and financial covenants, including those restricting or limiting our ability, and the ability of certain of our subsidiaries, to:
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make distributions;
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incur additional indebtedness;
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grant liens or make certain negative pledges;
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engage in certain asset conveyances, sales, leases, transfers, distributions or otherwise dispose of certain assets, businesses or operations;
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make certain investments;
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enter into a merger, consolidation, or dissolution;
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engage in transactions with affiliates;
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directly or indirectly make or permit any payment or distribution in respect of our partnership interests; or
§
permit or incur any limitation on the ability of any of our subsidiaries to pay dividends or make distributions to, repay indebtedness to, or make subordinated loans or advances to us.
If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Each of the following is an event of default under the credit agreement:
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non-payment of any principal, interest or fees when due under the credit agreement subject to grace periods to be negotiated;
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non-performance of covenants subject to grace periods to be negotiated;
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failure of any representation or warranty to be true and correct in any material respect;
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failure to pay any other material debt exceeding $10.0 million in the aggregate;
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a change of control; and
§
other customary defaults, including specified bankruptcy or insolvency events, the Employee Retirement Income Security Act of 1974, or ERISA, violations, and judgment defaults.
At December 31, 2007, we were in compliance with the covenants of this credit facility.
Evangeline joint venture debt obligation
The Series B notes are collateralized by (i) Evangeline’s property, plant and equipment; (ii) proceeds from its Entergy natural gas sales contract; and (iii) 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 was in compliance with such covenants during the periods presented.
Evangeline incurred the $7.5 million LL&E Note obligations in connection with its acquisition of the Entergy natural gas sales contract in 1991 and formation of the venture. The LL&E 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 note holders are either fully cash secured through debt service accounts or have been completely repaid. Variable rate interest accrues on the subordinated note at the LIBOR rate plus 0.5%. Variable interest rates charged on this note at December 31, 2007, 2006 and 2005 were 5.88%, 6.08%, and 4.23%, respectively. At December 31, 2007, 2006 and 2005, the amount of accrued but unpaid interest on the LL&E Note is approximately $9.1 million, $7.9 million and $7.1 million, respectively.
Note 12. Partners’ Equity/Owners’ Net Investment and Distributions
We are a Delaware limited partnership that was formed in September 2006. We are owned 98% by our limited partners and 2% by our general partner, DEP GP, which is a wholly owned subsidiary of EPO.
Capital accounts, as defined in our Partnership Agreement, are maintained by us for our general partner and our 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 financial statements. Earnings and cash distributions are allocated to our partners in accordance with their respective percentage interests.
As discussed in Note 1, we completed our initial public offering of 14,950,000 common units (including an overallotment amount of 1,950,000 common units) on February 5, 2007 at a price of $21.00 per unit, which generated net proceeds to the Partnership of $290.5 million. As consideration for assets contributed and reimbursement for capital expenditures related to these assets, we distributed $260.6 million of these net proceeds to EPO, along with $198.9 million in borrowings under our revolving credit facility (see Note 11) and a final amount of 5,351,571 common units of the Partnership.
The following table presents the adjustments made to the owners’ net investment balance of Duncan Energy Partners Predecessor at December 31, 2006 to arrive at our total partners’ equity balance after completion of our initial public offering effective February 1, 2007:
(1)
Reflects the retention by EPO of the storage well measurement imbalance account.
(2)
Reflects the retention by EPO (the sponsor of the Partnership) of a 34% ownership interest in each of operating subsidiaries.
In September 2007, Enterprise Texas Pipeline LLC, a wholly owned subsidiary of EPO, purchased certain parcels of land and regulatory permits from Mont Belvieu Caverns for $3.2 million. Due to common control considerations, the approximate $3.2 million excess of the proceeds received from EPO over the carrying value of assets sold was recorded as a general contribution by Mont Belvieu Caverns. The parent company has reflected its share of the excess amount, or $2.1 million, as an increase in partners’ equity. The remaining $1.1 million is included in parent interest in subsidiaries on our consolidated balance sheet.
Unit History
The following table details changes in our outstanding common units since our initial public offering on February 5, 2007. The Partnership 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 EPO, resulting in a final amount of 5,351,571 common units beneficially owned by EPO.
Distributions
Our partnership agreement requires us to distribute all of our available cash (as defined in our Partnership Agreement) to our partners on a quarterly basis. Such distributions are not cumulative. In addition, we do not have a legal obligation to pay distributions at our initial distribution rate or at any other rate except as provided in our partnership agreement. Our general partner is entitled to 2% of all distributions; however, it has no incentive distribution rights.
Our quarterly cash distributions for 2007 are presented in the following table:
Note 13. Parent Interest in Subsidiaries
In connection with our initial public offering (see Note 1), EPO contributed to us a 66% equity interest in Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene, Sabine Propylene and South Texas NGL. EPO retained the remaining 34% equity interest in each of these entities. We account for EPO’s share of our subsidiaries’ net assets and income as Parent interest in a manner similar to minority interest.
The following table presents the change in Parent interest in subsidiaries as shown on our Consolidated Balance Sheet at December 31, 2007:
Since our initial public offering, our operating subsidiaries distribute 34% of their operating cash flows to EPO. These distributions totaled $31.4 million for the eleven months ended December 31, 2007.
The following table presents our calculation of Parent interest in income of subsidiaries for the eleven months ended December 31, 2007:
EPO’s current sharing ratio of 34% in Mont Belvieu Caverns may increase in the future depending on the extent certain well optimization projects generate incremental cash flows (see Note 15).
Note 14. Business Segments
We classify our midstream energy operations into four reportable business segments: NGL & Petrochemical Storage Services, Onshore Natural Gas Pipelines & Services, Petrochemical Pipeline Services and NGL Pipelines & Services. Our business segments are generally organized and managed according to the type of services rendered (or technology 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 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 as an alternative to GAAP operating income.
We define total segment gross operating margin as operating income before: (i) depreciation, amortization and accretion expense; (ii) gains and losses on the sale of assets; and (iii) general and administrative expenses. Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, minority interest, extraordinary charges and the cumulative effect of changes in accounting principles. 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 any intersegment and intrasegment transactions. Our consolidated revenues reflect the elimination of all material intercompany transactions.
We include equity earnings from Evangeline in our measurement of segment gross operating margin and operating income. Our equity investments in midstream energy operations such as those conducted by Evangeline are a vital component of our long-term business strategy and important to the operations of Acadian Gas. This method of operation enables us to achieve favorable economies of scale relative to our level of investment and also lowers our exposure to business risks compared to the profile we would have on a stand-alone basis. Our equity investee is within the same industry as our consolidated operations, thus we believe treatment of earnings from our equity method investee as a component of gross operating margin and operating income is appropriate.
Our consolidated revenues were earned in the United States. Our underground storage wells in southeast Texas receive, store and deliver NGLs and petrochemical products for refinery and other customers along the upper Texas Gulf Coast. Acadian Gas gathers, transports, stores and markets natural gas to customers primarily in Louisiana. Our petrochemical pipelines provide propylene transportation services to shippers in southeast Texas and southwestern Louisiana. Our DEP South Texas NGL Pipeline System transports NGLs from south Texas to Mont Belvieu, Texas for EPO.
Consolidated property, plant and equipment and investments in and advances to our unconsolidated affiliate are allocated to each segment based on the primary operations of each asset or investment. The principal reconciling item between consolidated property, plant and equipment and the total value of segment assets is construction-in-progress. Segment assets represent the net carrying value of assets that contribute to the gross operating margin of a particular segment. Since assets under construction generally do not contribute to segment gross operating margin until completed, such assets are excluded from segment asset totals until they are deemed operational.
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/Combined Operations and Comprehensive Income.
(2)
These non-cash expenses are taken from the operating activities section of our Statements of Consolidated/Combined Cash Flows.
A reconciliation of total segment gross operating margin to operating income and income before 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:
The following table provides additional information regarding our consolidated revenues and costs and expenses for the periods indicated:
Revenues from the purchase and resale of natural gas included in the Onshore Natural Gas Pipelines & Services segment, accounted for 86%, 88% and 90% of total consolidated revenues for the years ended December 31, 2007, 2006 and 2005, respectively. The cost of natural gas sales accounted for 89%, 91% and 92% of total consolidated operating costs and expenses for the years ended December 31, 2007, 2006 and 2005, respectively.
Revenues from EPO accounted for 8%, 13% and 9% of total consolidated revenues for the years ended December 31, 2007, 2006 and 2005, respectively. EPO accounted for 100% of the revenues recorded by our Petrochemical Pipeline Services segment for the years ended December 31, 2006 and 2005. EPO accounted for 41%, 34% and 33% of the revenues recorded by our NGL & Petrochemical Storage Services segment for the years ended December 31, 2007, 2006 and 2005, respectively. EPO accounted for 100% of the revenues recorded by our NGL Pipelines & Services for the year ended December 31, 2007.
Revenues from Evangeline, our unconsolidated affiliate (see Note 9), accounted for 31%, 35% and 32% of total consolidated revenues for the years ended December 31, 2007, 2006 and 2005, respectively. See Note 15 for information regarding our related party transactions.
In 2007, ExxonMobil accounted for 11.4% of our total revenues and 11.6% of revenues of our Onshore Natural Gas Pipelines & Services segment. In 2006, ExxonMobil accounted for 9.9% of our consolidated revenues and 10.2% of revenues of our Onshore Natural Gas Pipelines & Services segment. In 2005, ExxonMobil accounted for 9.1% of our consolidated revenues and 9.3% of revenues of our Onshore Natural Gas Pipelines & Services segment.
Note 15. Related Party Transactions
We have business relationships with EPO, Evangeline, EPCO and certain other affiliates that give rise to various related party transactions. The following table summarizes our significant transactions with related parties during 2007.
Relationship with EPO
We have an extensive and ongoing relationship with EPO, which is our Parent company. The following information describes the significant ongoing and historical transactions that affected us and Duncan Energy Partners Predecessor.
Natural gas sales and purchases. We buy natural gas from and sell natural gas to EPO. We use the natural gas purchased from EPO to meet our fuel and other requirements. We recorded $18.3 million in revenues and $21.6 million in operating costs and expenses related to these transactions during the eleven months ended December 31, 2007.
NGL and petrochemical storage services. Mont Belvieu Caverns provides underground storage services to EPO. Prior to our initial public offering, the intercompany storage fees charged EPO by Mont Belvieu Caverns were below market. As a result of contracts executed in connection with our initial public offering, Mont Belvieu Caverns increased the storage fees it charges EPO to market-based rates. The terms of these new agreements commenced February 1, 2007 and end on December 31, 2016. We recorded $27.3 million in storage revenues from EPO during the eleven months ending December 31, 2007 under these new agreements.
Also effective with our initial public offering, EPO agreed to retain all storage well measurement gains and losses and to be allocated all operational measurement gains and losses relating to Mont Belvieu Caverns’ underground storage activities. Storage well measurement gains and losses occur when product movements into a storage well are different than those redelivered to customers. In connection with storage agreements entered into between EPO and Mont Belvieu Caverns effective concurrently with the closing of our initial public offering, EPO agreed to assume all storage well measurement gains and losses.
Operational measurement gains and losses are created when product is moved between storage wells and are attributable to pipeline and well connection measurement variances. Beginning February 2007, the Mont Belvieu Caverns’ limited liability company agreement allocates to EPO any items of income or loss relating to net operational measurement gains and losses, including amounts that Mont Belvieu Caverns may retain as handling losses. As such, EPO is required each period to contribute cash to Mont Belvieu Caverns for net operational measurement losses and is entitled to receive distributions from Mont Belvieu Caverns for net operational measurement gains. We continue to record operational measurement gains and losses associated with our Mont Belvieu storage facility. However, these operational measurement gains and losses should not affect our net income or have a significant impact on us with respect to the timing of our net cash flows provided by operating activities and, accordingly, we have not established a reserve for operational measurement losses on our balance sheet. We allocated EPO operational measurement gains totaling $4.5 million during the eleven months ended December 31, 2007. For additional information regarding our historical storage well and operational measurement gains and losses, see Note 2 of the Notes to Financial Statements included under Item 8 of this annual report.
An affiliate of EPO assigned a ground lease to Mont Belvieu Caverns effective February 1, 2007. Under this ground lease, EPO, as lessee, is required to pay a monthly rental fee to Mont Belvieu Caverns, as lessor. The initial term of this ground lease commenced on January 17, 2002 and continues until the earlier to occur of (i) December 31, 2100 or (ii) termination by the lessee, for any reason, of its operations on the leased premises as permitted under the ground lease. We received $13 thousand from EPO in connection with this lease during the eleven months ended December 31, 2007.
NGL transportation services. In conjunction with our initial public offering in February 2007, South Texas NGL entered into a ten-year contract with EPO for the transportation of NGLs from South Texas to Mont Belvieu, Texas. Under this contract, EPO pays us a dedication fee of no less than $0.02 per gallon for all NGLs it produces at its Shoup and Armstrong NGL fractionation plants, whether or not any volumes are actually shipped on the pipelines owned by South Texas NGL. South Texas NGL does not take title to products transported on its pipeline system. EPO retains title and associated commodity risk with such products. South Texas NGL recorded $20.2 million in NGL transportation revenues from EPO during the eleven months ending December 31, 2007 under these new agreements.
Petrochemical pipeline services. Historically, EPO was the shipper of record on our Lou-Tex Propylene and Sabine Propylene Pipelines, and we charged it the maximum tariff rate for using these assets. EPO then contracted with third parties to ship volumes on these pipelines under product exchange agreements. In general, the revenues recognized by EPO in connection with these exchange agreements were lower than the maximum tariff rate it paid us. In connection with our initial public offering, EPO assigned its third party product exchange agreements to us. Accordingly, the transportation fees we receive from these third parties for use of our Lou-Tex Propylene and Sabine Propylene Pipelines are less than the fees we received from EPO prior to February 2007. Although EPO has assigned these agreements to us, it remains jointly and severally liable to the Partnership for performance of these agreements.
Omnibus Agreement. On February 5, 2007, we and EPO entered into an Omnibus Agreement that governs 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 South Texas NGL and Mont Belvieu Caverns;
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a right of first refusal to EPO in our 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 our subsidiaries, other than as consideration in an acquisition or in connection with a loan or debt financing.
EPO has indemnified us against certain pre-February 2007 environmental and related liabilities associated with the assets it contributed to us at the time of our 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, we are not entitled to indemnification until the aggregate amount of claims we incur 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 us 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 us in connection with our initial public offering are located and failure to obtain certain consents and permits necessary to conduct our business that arise through February 5, 2010; and
•
certain income tax liabilities attributable to the operation of the assets contributed to us in connection with our 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 our general partner, adversely affect holders of the Partnership’s common units.
Neither EPO nor any of its affiliates are restricted under the Omnibus Agreement from competing with us. 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 us 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 the Partnership in accordance with the existing sharing ratio of 66% funded by the Partnership and 34% funded by EPO. Under the Omnibus Agreement, EPO agreed to make additional contributions to us as reimbursement for our 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 our initial public offering. In December 2007, EPO made cash contributions totaling $9.9 million to our 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 the Partnership is not a participant. This contribution was in accordance with provisions of the Mont Belvieu Caverns’ limited liability company agreement, which states that when the Partnership 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, the Partnership may elect to reacquire for consideration a 66% share of these projects at a later date.
Mont Belvieu Caverns distributed to us the $48.0 million in cash contributions it received from EPO with respect to the foregoing contributions made under the Omnibus Agreement ($9.9 million) and
Mont Belvieu Caverns’ limited liability company agreement ($38.1 million). We, in turn, used such proceeds to reduce amounts outstanding under our revolving credit facility.
We expect additional contributions from EPO under the Omnibus Agreement and Mont Belvieu Caverns limited liability company agreement in 2008.
Other Transactions. The following information summarizes various other related party transactions and arrangements between us and EPO during the year ended December 31, 2007:
•
In September 2007, Enterprise Texas Pipeline LLC, a wholly owned subsidiary of EPO, purchased certain parcels of land and regulatory permits from Mont Belvieu Caverns for $3.2 million. Due to common control considerations, the excess of the proceeds received from EPO over the carrying value of the assets sold was recorded as an equity contribution to Mont Belvieu Caverns. We used our $2.1 million share of the proceeds from this transaction to temporarily reduce principal outstanding under our revolving credit facility.
•
At the time of our initial public offering, we used $260.6 million of net proceeds from our initial public offering and $198.9 million in borrowings under our revolving credit facility to make a $459.5 million distribution to EPO as partial consideration for assets contributed to us and reimbursements for capital expenditures related to these assets. The remainder of such consideration consisted of our issuing EPO a final amount of 5,351,571 of our common units. EPO received $31.4 million of cash distributions from us during the eleven months ended December 31, 2007 based on its ownership of our limited partner units.
•
Duncan Energy Partners Predecessor participated in the EPO’s cash management program for all periods presented prior to the closing of our initial public offering. For purposes of presentation in our Statements of Consolidated/Combined Cash Flows, cash flows from financing activities represent transfers of excess cash from us to EPO equal to cash flows provided by operating activities less cash used in investing activities. Such transfers of excess cash are shown as permanent distributions to owners in the Statements of Consolidated/Combined Partners’ Equity/Owners’ Net Investment. As a result, the financial statements do not present cash balances for the periods prior to our initial public offering.
Since our initial public offering, our operating subsidiaries distribute 34% of their operating cash flows to EPO. These distributions totaled $31.4 million for the eleven months ended December 31, 2007.
Relationship with Evangeline
Acadian Gas, through a wholly owned subsidiary, owns a collective 49.51% equity interest in Evangeline. Acadian Gas does not have a controlling interest in Evangeline, but does exercise significant influence over its operating policies. Evangeline’s most significant contract is a natural gas sales agreement with Entergy Louisiana (“Entergy”) that expires in January 2013. Under this contract, Evangeline is obligated to make available-for-sale and deliver to Entergy certain specified minimum contract quantities of natural gas on an hourly, daily, monthly and annual basis. The sales contract provides for minimum annual quantities of 36.75 BBtus.
In connection with the Entergy sales contract, Evangeline has entered into a natural gas purchase contract with Acadian Gas that contains annual purchase provisions that correspond to Evangeline’s sales commitments to Entergy. The pricing terms of the sales agreement with Entergy and Evangeline’s purchase agreement with Acadian Gas are based on a monthly weighted-average market price of natural gas (subject to certain market index price ceilings and incentive margins) plus a predetermined margin. Acadian Gas sold $248.8 million of natural gas to Evangeline during the year ended December 31, 2007.
EPO has furnished letters of credit on behalf of Evangeline’s debt service requirements. The outstanding letters of credit totaled $1.1 million, at both December 2007 and 2006.
Relationship with EPCO
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, Enterprise Products Partners, Enterprise GP Holdings, TEPPCO and our respective general partners are parties to the ASA. The significant terms of the ASA are as follows:
•
In accordance with prudent industry practices, EPCO provides administrative, management, engineering and operating services as may be necessary to manage and operate our businesses, properties and assets. EPCO employs or otherwise retains the services of personnel providing these 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 EPCO expenses reasonably allocated to us). In addition, we have agreed to pay all sales, use, excise, value added or similar taxes, if any, which may be applicable to the services provided by EPCO.
•
We participate as named insureds in EPCO’s insurance program, with the associated premiums and related costs being allocated to us. We reimbursed EPCO $1.6 million for insurance costs during the year ended December 31, 2007.
•
Our operating costs and expenses include reimbursement payments to EPCO for the costs it incurs to operate our facilities, including the compensation of employees. We reimburse EPCO for actual direct and indirect expenses it incurs related to the operation of our assets. Our reimbursements to EPCO for operating costs and expenses were $16.9 million for the year ended December 31, 2007.
•
Our general and administrative expenses include reimbursement payments to EPCO for the costs it incurs for providing administrative services to us, including the compensation of employees. Such reimbursements are either (i) on an actual basis for direct expenses EPCO incurs on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to the ASA, which, in-turn, is based on the estimated usage 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 businesses and affairs). Our reimbursements to EPCO for general and administrative costs were $2.4 million for the year ended December 31, 2007.
A small number of key employees of EPCO that devote a portion of their time to our operations and affairs participate in long-term incentive compensation plans managed by EPCO. These plans include the issuance of unit options and restricted common units of Enterprise Products Partners and profits interests in the Employee Partnerships. The amount of equity-based compensation allocated to us was $0.2 million for the year ended December 31, 2007. Such amounts are immaterial to our consolidated financial position, results of operations and cash flows.
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:
•
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 desire 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 desire 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. Enterprise Products Partners will be presumed to desire to 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. Enterprise GP Holdings will be presumed to desire 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.
Note 16. Earnings Per Unit
Basic and diluted earnings per unit is computed by dividing net income or loss allocated to limited partner interests by the weighted-average number of common units outstanding during a period. The following calculation is based on common units outstanding since the completion of our initial public offering in February 2007. We have no dilutive 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 DEP GP for the period indicated:
The following table presents our calculation of basic and diluted earnings per unit for the period indicated:
Note 17. Commitments and Contingencies
Litigation
On occasion, we are named as a defendant in litigation relating to our normal business operations, including regulatory and environmental matters. Although we insure 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 activity.
In 1997, Acadian Gas and numerous other energy companies were named as defendants in actions brought by Jack Grynberg on behalf of the U.S. Government under the False Claims Act. Generally, these complaints allege an industry-wide conspiracy to under report the heating value, as well as the volumes, of natural gas produced from federal and Native American lands. The complaint alleges that the U.S. Government was deprived of royalties as a result of this conspiracy. The plaintiff in this case seeks royalties that he contends the U.S. government should have received had the heating value and volume been differently measured, analyzed, calculated and reported, together with interest, treble damages, civil penalties, expenses and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. These matters have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming, filed June 1997). On October 20, 2006, the U.S. District Court dismissed all of Grynberg’s claims against many of the energy companies, including Acadian, with prejudice. Grynberg has appealed the dismissal.
We are not aware of any other significant litigation, pending or threatened, that may have a significant adverse effect on our financial position or results of operations.
Redelivery Commitments
We transport and store natural gas and NGLs and store petrochemical products for third parties under various contracts. These volumes are (i) accrued as product payables on our Consolidated Balance Sheets, (ii) 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 NGL and petrochemical product storage agreements, we are generally required to redeliver volumes to the owner on demand. At December 31, 2007, NGL and petrochemical products aggregating 18.1 million barrels were due to be redelivered to their owners along with 711 BBtus of natural gas. See Note 2 for more information regarding accrued product payables.
Contractual Obligations
The following table summarizes our significant contractual obligations at December 31, 2007. A description of each type of contractual obligation follows:
(1)
See Note 11 for information regarding our revolving credit facility.
(2)
Capital expenditure commitments are reflected on a 100% basis before contributions from the Parent in connection with the Omnibus Agreement and Mont Belvieu Caverns’ limited liability company agreement (see Note 15).
Operating lease obligations. We lease certain property, plant and equipment under non-cancelable and cancelable operating leases. Amounts shown in the preceding table represent our minimum cash lease payment obligations under operating leases with terms in excess of one year for the periods indicated.
Acadian Gas leases an underground natural gas storage cavern that is integral to its operations. The primary use of this cavern is to store natural gas held-for-sale on a demand basis by Acadian Gas. The current term of the cavern lease expires in December 2012. The term of this contract does not provide for an additional renewal period, but it requires the lessor to enter into negotiations with us under similar terms and conditions if we wish to extend the lease agreement beyond December 2012.
In addition, our pipeline operations have entered into leases for land held pursuant to right-of-way agreements. Our significant right-of-way agreements have original terms that range from five to 50 years and include renewal options that could extend the agreements for up to an additional 25 years. Our rental payments are generally at fixed rates, as specified in the individual contracts, and may be subject to escalation provisions for inflation and other market-determined factors.
Lease expense is charged to operating costs and expenses on a straight line basis over the period of expected economic benefit. Contingent rental payments, if any, are expensed as incurred. In general, we are 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 attributable to our operations are charged to expense as incurred. We have not made any significant leasehold improvements during the periods presented. Lease expense included in operating income was $1.3 million for the eleven months ended December 31, 2007 and $1.3 million and $1.2 million for the years ended December 31, 2006 and 2005, respectively.
Purchase Obligations. We define purchase obligations as agreements to purchase goods or services that are enforceable and legally binding (unconditional) on us that specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions.
Acadian Gas has a product purchase commitment for the purchase of natural gas in Louisiana from the co-venture party in Evangeline (see Note 9). This purchase agreement expires in January 2013. Our purchase price under this contract approximates the market price of natural gas at the time we take delivery of the volumes. The preceding table shows the volume we are committed to purchase and an estimate of our future payment obligations for the periods indicated. Our estimated future payment obligations are based on the contractual price 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 having remaining terms in excess of one year.
We also have short-term payment obligations relating to capital projects we have initiated. These commitments represent unconditional payment obligations that we have agreed to pay vendors for services to be rendered or products to be delivered in connection with our capital spending programs. The preceding table shows these capital project commitments for the periods indicated.
At December 31, 2007, we had approximately $20.7 million in outstanding capital expenditure commitments. These commitments primarily relate to our announced expansions of the DEP South Texas NGL Pipeline System and Mont Belvieu Caverns’ well utilization projects, which are expected to be completed by the end of the first quarter of 2008. Of our total capital expenditure commitments, we expect EPO to reimburse us for $17.7 million attributable to (i) EPO 34% direct interest in our subsidiaries, (ii) EPO’s obligations under the Omnibus Agreement, and (iii) projects for which we are not obligated to participate in.
Note 18. Significant Risks and Uncertainties
Nature of Operations
Our consolidated results of operations, cash flows and financial position may be adversely affected by a variety of factors affecting our industry and specific businesses, including:
•
a reduction in demand for NGL and petrochemical storage services provided by Mont Belvieu Caverns caused by fluctuations in NGL and petrochemical prices and production due to weather and other natural and economic forces;
•
a reduction in demand for natural gas transportation services and natural gas consumption in the areas served by Acadian Gas; or
•
a reduction in propylene transportation volumes by shippers on the petrochemical pipelines owned by Lou-Tex Propylene and Sabine Propylene.
In general, a reduction in demand for NGL and petrochemical products and natural gas by the petrochemical, refining or heating industries could result from (i) a general downturn in economic conditions, (ii) reduced demand by consumers for the end products made with products we handle, (iii) increased governmental regulations or (iv) other reasons.
Credit Risk Due to Industry Concentration
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.
Counterparty Risk with Respect to Financial Instruments
In those situations 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. Generally, we do not require collateral nor do we anticipate nonperformance by our counterparties.
Weather-Related Risks
Our assets are located along the U.S. Gulf Coast in Texas and Louisiana, which are areas prone to suffer tropical weather events such as hurricanes. If we were to experience a significant weather-related loss for which we were not fully insured, it could have a material impact on our consolidated financial position, results of operations and cash flows. Likewise, if any of our significant customer or supplier groups experience losses related to storm events, it could have a material impact on our consolidated financial position, results of operations and cash flows.
Note 19. Supplemental Cash Flow Information
The net effect of changes in operating assets and liabilities is as follows for the periods indicated:
On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures based on activities initiated by the party. The majority of such arrangements are associated with projects related to pipeline construction and well tie-ins. We received $0.6 million, $0.3 million and $0.8 million as contributions in aid of our construction costs during the eleven months ended December 31, 2007, the month of January 2007 and the year ended December 31, 2006, respectively.
Accounts payable related to our capital spending projects totaled $16.3 million, $16.2 million, and $12.5 million at December 31, 2007, January 31, 2007, and December 31, 2006, respectively.
Note 20. Quarterly Financial Information (Unaudited)
The following table presents selected quarterly financial data for the eleven months ended December 31, 2007, one month ended January 31, 2007 and years ended December 31, 2006 and 2005:
Note 21. Subsequent Events
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 Enterprise Products Partners’ common units and other rights to its non-employee directors and to consultants and employees of EPCO and its affiliates providing services to Enterprise Products Partners, including us. 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 Enterprise Products Partners’ 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 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. We will recognize our share of the cost of such awards when granted.
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 Partnership, 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 Enterprise Products Partners’ 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 Enterprise Products Partners or Enterprise GP Holdings. Enterprise LP has the following material terms regarding its quarterly cash distribution to partners:.
•
Distributions of cash flow - Each quarter, 100% of the cash distributions received by Enterprise LP from Enterprise GP Holdings and Enterprise Products Partners 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).
•
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.
•
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 Duncan Energy 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 Duncan Energy Partners L.P. and its consolidated subsidiaries, including its chief executive officer and the 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 Duncan Energy 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 Duncan Energy 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, Duncan Energy 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 DEP GP. 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 Duncan Energy 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 Duncan Energy 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.
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.
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 our general partner. 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 DEP GP, 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 DEP GP were Messers. Duncan, Bachmann, Creel, Fowler, Radtke and Cunningham. Mr. Cunningham was appointed a director of DEP GP effective August 1, 2007.
Seven of the directors attended the five meetings of the Board during 2007, one member attended four meetings of the Board and one member attended the two Board meetings which took place after election to the Board in August 2007. The Board has one committee, the Audit, Conflicts and Governance Committee, which we refer to in this annual report as the ACG Committee. The ACG Committee met eight times during 2007.
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, DEP GP 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 DEP GP. Whenever possible, DEP GP 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 DEP GP or us (either directly or as a partner, unitholder or officer of an organization that has a material relationship with DEP GP or us). Based on the foregoing, the Board has affirmatively determined that William A. Bruckmann, III, Larry J. Casey and Joe D. Havens 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 DEP GP 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
DEP GP 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 violations of the code.
Governance guidelines, together with committee charters, provide the framework for effective governance. The Board has adopted the Governance Guidelines of Duncan Energy 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.deplp.com to current information relating to governance, including the Code of Conduct, the Governance Guidelines of Duncan Energy 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. Bruckmann, Casey and Havens. The Board has affirmatively determined that Mr. Bruckmann 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:
§
monitoring the integrity of our financial reporting process and related systems of internal control;
§
ensuring our legal and regulatory compliance and that of DEP GP;
§
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 DEP GP 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.deplp.com. You may also contact our investor relations department at (866) 230-0745 for a printed copy of this document free of charge.
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. Bruckmann.
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 DEP GP
The following table sets forth the name, age and position of each of the directors and executive officers of our general partner at February 15, 2008.
(1)
Executive Officer
(2)
Member of ACG Committee
(3)
Chairman of ACG Committee
Dan L. Duncan. Mr. Duncan was elected Chairman and a Director of DEP GP in October 2006, Chairman and a Director of EPE Holdings in August 2005 and Chairman and a Director of EPGP in April 1998.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. He also serves as a Honorary Trustee of the Board of Trustees of the Texas Heart Institute at Saint Luke’s Episcopal Hospital.
Richard H. Bachmann. Mr. Bachmann was elected President, Chief Executive Officer and a Director of DEP GP in October 2006 and a Director of EPE Holdings and EPGP in February 2006. Mr. Bachmann previously served as a Director of EPGP from June 2000 to January 2004. Mr. Bachmann was elected Executive Vice President, Chief Legal Officer and Secretary of EPGP and of EPCO, and a Director of EPCO, in January 1999. In December 2007, Mr. Bachmann was also elected as a Co-Group Vice Chairman of EPCO. In November 2006, Mr. Bachmann was appointed as 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.
W. Randall Fowler. Mr. Fowler was elected Executive Vice President and Chief Financial Officer of DEP GP and EPGP in August 2007. Mr. Fowler has served as a Director of DEP GP since October 2006 and EPE Holdings and EPGP since February 2006. Prior to his promotion to Executive Vice President and Chief Financial Officer of DEP GP in August 2007, Mr. Fowler served as a Senior Vice President and treasurer of DEP GP since October 2006. Mr. Fowler served as Senior Vice President and Treasurer of EPGP from February 2005 to August 2007. Mr. Fowler was elected President and Chief Executive Officer of EPCO in December 2007. Mr. Fowler, a certified public accountant (inactive), joined Enterprise Products Partners as Director of Investor Relations in January 1999 and held senior management positions within the EPCO group of companies from August 2000 to February 2005.
Gil H. Radtke. Mr. Radtke was elected Senior Vice President, Chief Operating Officer and a Director of DEP GP in October 2006 and Senior Vice President of EPGP in February 2002. Mr. Radtke joined Enterprise Products Partners in connection with its purchase of Diamond-Koch’s storage and propylene fractionation assets in 2002. Before joining Enterprise Products Partners, 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.
Michael A. Creel. Mr. Creel was elected a Director of DEP GP in October 2006. From October 2006 to August 2007, Mr. Creel served as the Chief Financial Officer and an Executive Vice President of DEP GP. In August 2007, Mr. Creel resigned these positions with DEP GP and was appointed President and Chief Executive Officer of EPGP.
Mr. Creel, a certified public accountant, has held various senior and executive management positions within the EPCO group of companies since November 1999. Apart from his current position as President and Chief Executive Officer of EPGP and a Director of DEP GP, Mr. Creel also serves as Chief Financial Officer of EPCO (since December 2007) and a Director of EPGP (since February 2006). Mr. Creel served as President, Chief Executive Officer and a Director of EPE Holdings from August 2005 through August 2007. Mr. Creel was elected a Director of Edge Petroleum Corporation (a publicly traded oil and natural gas exploration and production company) in October 2005.
Dr. Ralph S. Cunningham. Dr. Cunningham was elected a Director of DEP GP in August 2007. In addition to these duties, Dr. Cunningham has served as the President and Chief Executive Officer and a Director of EPE Holdings since August 2007 and a Director of EPGP since February 2006. He served as group Executive Vice President and Chief Operating Officer of EPGP from December 2005 to August 2007. Dr. Cunningham also served as a Director of EPGP from 1998 to March 2005 and as Chairman and a Director of TEPPCO GP from March 2005 to November 2005. Dr. Cunningham retired in 1997 from CITGO Petroleum Corporation, where he had served as President and Chief Executive Officer since 1995.
Dr. Cunningham 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). He was a Director of EPCO from 1987 to 1997.
Larry J. Casey. Mr. Casey was elected a Director of DEP GP in October 2006. Mr. Casey has been a private investor managing real estate and personal investments since he retired in 1982 from a career in the energy industry. In 1974, Mr. Casey founded Xcel Products Company, a NGL and petrochemical trading company. Also in 1974, he founded Xral Underground Storage, the first privately-owned underground merchant storage facility for NGLs and specialty chemicals at Mont Belvieu, Texas. Mr. Casey sold these companies in 1982. Mr. Casey serves on our ACG Committee.
Joe D. Havens. Mr. Havens was elected a Director of DEP GP in October 2006. Mr. Havens has been an entrepreneur engaged in the energy, banking and real estate industries. Mr. Havens founded Enterprise Petroleum Company, Inc., the predecessor to EPCO, in 1968, and sold his interest in the successor entity and related businesses to Mr. Duncan in 1990. Mr. Havens has also served on the board of Directors of the First Commerce Bank of Corpus Christi, a private bank, since 1991, and currently serves as that board’s Chairman. Mr. Havens serves on our ACG Committee.
William A. Bruckmann, III. Mr. Bruckmann was elected a Director of DEP GP in October 2006. Mr. Bruckmann has been self-employed as a consultant and private investor since April 2004. From September 2002 to April 2004, Mr. Bruckmann served as a financial advisor with UBS Securities, Inc. He is a former managing Director at Chase Securities, Inc. and has more than 25 years of banking experience, starting with Manufacturers Hanover Trust Company, where he became a senior officer in 1985. Mr. Bruckmann later served as managing Director, sector head of Manufacturers Hanover’s gas pipeline and midstream energy practices through the acquisition of Manufacturers Hanover by Chemical Bank and the acquisition of Chemical Bank by Chase Bank. Mr. Bruckmann also served as a Director of Williams Energy Partners L.P. from May 2001 to June 2003. Mr. Bruckmann serves on our ACG Committee as its Chairman.
William Ordemann. Mr. Ordemann was elected a Director of DEP GP in August 2007. He was elected Chief Operating Officer and Executive Vice President of EPGP in August 2007. He served as a Senior Vice President of EPGP from September 2001 to August 2007 and one of its vice Presidents from October 1999 to September 2001. Prior to joining Enterprise Products Partners, Mr. Ordemann held senior
management positions at Shell Midstream Enterprises, LLC and Tejas Natural Gas Liquids, LLC, both of which were affiliates of Shell Oil Company.
Michael J. Knesek. Mr. Knesek, a certified public accountant, was elected Senior Vice President, Principal Accounting Officer and Controller of DEP GP in October 2006. Mr. Knesek has been the Principal Accounting Officer and Controller of EPGP since August 2000 and of EPE Holdings since August 2005. He also serves as a Senior Vice President of EPGP (since February 2005) and EPE Holdings (since August 2005). He previously served as Vice President of EPGP from August 2000 to February 2005. Mr. Knesek has been the Controller and a Vice President of EPCO since 1990.
Section 16(a) Beneficial Ownership Reporting Compliance
Under the federal securities laws, DEP GP, directors of DEP GP, executives (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 that ownership to us and the SEC. Specific due dates for these reports have been established by regulation, and we are required to disclose in this report any failure to file by these dates during 2007. All such reporting was done in a timely manner in 2007, except that on February 15, 2008, Mr. Joe Havens filed a late Form 4 reporting eleven purchase transactions that he inadvertently failed to timely report during 2007.
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 year ended December 31, 2007 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. Collectively, these five 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.
Our Named Executive Officers did not allocate any of their time to our predecessor’s specific operations during the year ended December 31, 2006 and one month ended January 31, 2007. Our Named Executive Officers allocated their time to Enterprise Products Partners (as a whole) and/or other affiliates of EPCO. As a result, we cannot indicate the historical salaries or other elements of compensation that would have been allocated to us pursuant to the EPCO administrative services agreement. Each of the Named Executive Officers continues to perform services for Enterprise Products Partners and/or other affiliates of EPCO.
Our Named Executive Officers devote substantially less than a majority of their time and compensation to us. Michael A. Creel served as our Chief Financial Officer until August 1, 2007. Mr. Creel and Mr. Ordemann devoted a minimal amount of their time to our business activities and instead indirectly supervised the activities of other personnel who were more directly involved in our affairs. As a result, Mr. Creel did not allocate any of his compensation to us during the year ended December 31, 2007. Mr. Ordemann allocated $2 thousand of his compensation to us. We expect that Mr. Ordemann will devote more time and compensation expense to our affairs in the future.
(1)
Amounts represent discretionary annual cash awards accrued for the year ended December 31, 2007. Payment of these amounts was made in February 2008.
(2)
Amounts represent expense recognized in accordance with SFAS 123(R) with respect to an equity-based long-term incentive plan of EPCO whereby the recipient is awarded restricted units of Enterprise Products Partners L.P. and profits interests in the Employee Partnerships. We may incur allocated costs of additional types of unit-based awards in the future.
(3)
Amounts primarily represent (i) matching contributions under funded, qualified, defined contribution retirement plans, (ii) quarterly distributions paid an equity incentive plan awards and (iii) the imputed value of life insurance premiums paid on behalf of the officer.
Compensation Discussion and Analysis
With respect to our Named Executive Officers, compensation paid or awarded by us in 2007 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. In 2007, 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 year ended December 31, 2007, 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, the Chief Executive Officer of EPGP and the Senior Vice President of Human Resources for EPCO, and were approved by the ACG Committee of EPGP. Incentive awards issued under the EPCO 1998 Plan involving securities of Enterprise Products Partners are also approved by the ACG Committee of EPGP. 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 Note 2 of the Notes to 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
Richard H. Bachmann
W. Randall Fowler
Gil H. Radtke
Dr. Ralph S. Cunningham
William A. Bruckmann, III
Larry J. Casey
Joe D. Havens
William Ordemann
Nothwithstanding 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 for which we will be allocated our pro rata share under the EPCO administrative services agreement. See “Summary of Long-Term Incentive Arrangements Underlying 2007 Award Grants” within this Item 11 for additional information regarding the long-term incentive plans under which these awards were granted. The fair value amounts presented in the table are based on certain assumptions and considerations made by management.
(1)
Represents that portion of the grant date fair value allocable to us based on the percentage of time each officer expects to spend on our affairs effective January 1, 2008. Based on current allocations, we estimate that the consolidated compensation expense we record for each Named Executive Officer with respect to these awards will approximate these amounts over the vesting 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 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%.
Summary of Long-Term Incentive Arrangements Underlying 2007 Award Grants
The following information summarizes the types of awards granted to our Named Executive Officers for which we expect to be allocated our pro rata share of the cost under the EPCO administrative services agreement. The costs of additional types of awards may be allocated to us in the future.
Restricted unit awards. Under the Enterprise Products 1998 Long-Term Incentive Plan (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) of Enterprise Products Partners once a defined vesting period expires, subject to certain forfeiture provisions. The restrictions on such 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 from Enterprise Products Partners equal to the product of the number of restricted units outstanding for the participant and the cash distribution per unit paid by Enterprise Products Partners to its unitholders.
As used in the context of the EPCO plan, the term “restricted unit” represents a time-vested unit under SFAS 123(R). Such awards are non-vested until the required service period expires.
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 (e.g. EPE Unit I and EPE Unit III). Our Named Executive Officers have been granted profits interest awards in EPE Unit I (formed in August 2005) 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 gross value of the profits interests to Mr. Bachmann, Mr. Fowler and Mr. Knesek.
See Note 21 of the Notes to 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 table presents information concerning each Named Executive Officer’s restricted units and profits interest awards as of December 31, 2007. We expect to be allocated our pro rata share of the cost of such awards under the EPCO administrative services agreement. The gross amounts listed in the table do not represent the amount of expense we will record in connection with unit-based awards to the Named Executive Officers.
Option Exercises and Stock Vested
The Named Executive Officers did not vest in or exercise any equity-based awards during the year for which we were responsible for a share of the related cost.
Director Compensation
The following table presents information regarding compensation to the independent directors of our general partner during the year ended December 31, 2007.
Neither we nor DEP GP provide any additional compensation to employees of EPCO who serve as directors of DEP GP. The employees of EPCO who served as directors of DEP GP during 2007 were Messrs. Duncan, Bachmann, Fowler, Creel, Radtke and Cunningham.
DEP GP’s three independent directors, Messrs. Casey, Havens and Bruckmann, 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 DEP GP 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 DEP GP. 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 February 2007, Messrs. Bruckmann, Casey and Havens were issued 30,000 UARs each under the letter agreement format. The grant date price of these rights was $36.68 per unit. These awards vest in February 2012 or the date of certain qualifying events (as set forth in the form of grant). These awards are accounted for as liability awards under SFAS 123(R) by DEP GP. At December 31, 2007, the total fair value of these 90,000 UARs was $243 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%; (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 14, 2008, regarding each person known by our general partner to beneficially own more than 5% of our common units.
(1)
These common units were issued to EPO in connection with its contribution of assets to us at the time of our initial public offering in February 2007. These securities are controlled by Dan L. Duncan.
(2)
Based on the Schedule 13D filed by Swank Capital, LLC (“Swank Capital”) with the SEC on February 14, 2008, Swank Energy Income Advisors, LP (“Swank Advisors”) and Mr. Jerry V. Swank. Mr. Swank is the principal of Swank Capital and Swank Advisors. Swank Capital and Mr. Swank have sole voting and dispositive power with respect to these common units, and Swank Advisors has shared voting and dispositive power with respect to these common units.
Security Ownership of Management
The following table sets forth certain information regarding the beneficial ownership of our common units and the common units of Enterprise Products Partners L.P. as of February 1, 2008 by (i) our Named Executive Officers, (ii) the current directors of DEP GP and (iii) the current directors and executive officers of DEP GP as a group. Enterprise Products Partners L.P. owns 100% of the partnership interests of EPO, which in turn owns DEP GP (our 2% general partner) and 26.4% of our common units. EPO also retains 34% of the ownership interests of our principal subsidiaries: Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene, Sabine Propylene and South Texas NGL.
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 common units of Enterprise Products Partners L.P. 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 the common units of Enterprise Products Partners L.P. 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)
Mr. Duncan is deemed beneficial owner of the securities held by certain family trusts, the beneficiaries of which are shareholders of EPCO.
(2)
These individuals are Named Executive Officers.
(3)
The number of Enterprise Products Partners’ common units presented for Mr. Radtke includes 100,000 unit options that are exercisable within 60 days of the filing date of this report.
(4)
Cumulatively, this group’s beneficial ownership amount includes 100,000 options to acquire common units of Enterprise Products Partners that were issued under the 1998 Plan. These options are exercisable within 60 days of the filing date of this report.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
We have business relationships with EPO, Evangeline, EPCO and certain other affiliates that give rise to various related party transactions. The purpose of this Item 13 is to present summary information regarding our related party transactions for the year ended December 31, 2007. For information regarding our related party transactions in prior periods, see Note 15 of the Notes to Financial Statements included under Item 8 of this annual report. The following table summarizes our significant transactions with related parties during 2007.
Relationship with EPO
We have an extensive and ongoing relationship with EPO, which is our Parent company. The following information describes the significant ongoing and historical transactions that affected us and Duncan Energy Partners Predecessor.
Natural gas sales and purchases. We buy natural gas from and sell natural gas to EPO. We use the natural gas purchased from EPO to meet our fuel and other requirements. We recorded $20.6 million in revenues and $22.2 million in operating costs and expenses related to these transactions during the year ended December 31, 2007.
NGL and petrochemical storage services. Mont Belvieu Caverns provides underground storage services to EPO. Prior to our initial public offering, the intercompany storage fees charged EPO by Mont Belvieu Caverns were below market. As a result of contracts executed in connection with our initial public offering, Mont Belvieu Caverns increased the storage fees it charges EPO to market-based rates. The terms of these new agreements commenced February 1, 2007 and will end on December 31, 2016. We recorded
$27.3 million in storage revenues from EPO during the eleven months ending December 31, 2007 under these new agreements.
Also effective with our initial public offering, EPO agreed to retain all storage well measurement gains and losses and to be allocated all operational measurement gains and losses relating to Mont Belvieu Caverns’ underground storage activities. Storage well measurement gains and losses occur when product movements into a storage well are different than those redelivered to customers. In connection with storage agreements entered into between EPO and Mont Belvieu Caverns effective concurrently with the closing of our initial public offering, EPO agreed to assume all storage well measurement gains and losses.
Operational measurement gains and losses are created when product is moved between storage wells and are attributable to pipeline and well connection measurement variances. Beginning February 2007, the Mont Belvieu Caverns’ limited liability company agreement allocates to EPO any items of income or loss relating to net operational measurement gains and losses, including amounts that Mont Belvieu Caverns may retain as handling losses. As such, EPO is required each period to contribute cash to Mont Belvieu Caverns for net operational measurement losses and is entitled to receive distributions from Mont Belvieu Caverns for net operational measurement gains. We continue to record operational measurement gains and losses associated with our Mont Belvieu storage facility. However, these operational measurement gains and losses should not affect our net income or have a significant impact on us with respect to the timing of our net cash flows provided by operating activities and, accordingly, we have not established a reserve for operational measurement losses on our balance sheet. We allocated EPO operational measurement gains totaling $4.5 million during the eleven months ended December 31, 2007. For additional information regarding our historical storage well and operational measurement gains and losses, see Note 2 of the Notes to Financial Statements included under Item 8 of this annual report.
An affiliate of EPO assigned a ground lease to Mont Belvieu Caverns effective February 1, 2007. Under this ground lease, EPO, as lessee, is required to pay a monthly rental fee to Mont Belvieu Caverns, as lessor. The initial term of this ground lease commenced on January 17, 2002 and continues until the earlier to occur of (i) December 31, 2100 or (ii) termination by the lessee, for any reason, of its operations on the leased premises as permitted under the ground lease. We received $13 thousand from EPO in connection with this lease during the eleven months ended December 31, 2007.
NGL transportation services. In conjunction with our initial public offering in February 2007, South Texas NGL entered into a ten-year contract with EPO for the transportation of NGLs from South Texas to Mont Belvieu, Texas. Under this contract, EPO pays us a dedication fee of no less than $0.02 per gallon for all NGLs it produces at its Shoup and Armstrong NGL fractionation plants, whether or not any volumes are actually shipped on the pipelines owned by South Texas NGL. South Texas NGL does not take title to products transported on its pipeline system. EPO retains title and associated commodity risk with such products. South Texas NGL recorded $20.2 million in NGL transportation revenues from EPO during the eleven months ending December 31, 2007 under these new agreements.
Petrochemical pipeline services. Historically, EPO was the shipper of record on our Lou-Tex Propylene and Sabine Propylene Pipelines, and we charged it the maximum tariff rate for using these assets. EPO then contracted with third parties to ship volumes on these pipelines under product exchange agreements. In general, the revenues recognized by EPO in connection with these exchange agreements were lower than the maximum tariff rate it paid us. In connection with our initial public offering, EPO assigned its third party product exchange agreements to us. Accordingly, the transportation fees we receive from these third parties for use of our Lou-Tex Propylene and Sabine Propylene Pipelines are less than the fees we received from EPO prior to February 2007. Although EPO has assigned these agreements to us, it remains jointly and severally liable to the Partnership for performance of these agreements.
Omnibus Agreement. On February 5, 2007, we and EPO entered into an Omnibus Agreement that governs 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 South Texas NGL and Mont Belvieu Caverns;
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a right of first refusal to EPO in our 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 our subsidiaries, other than as consideration in an acquisition or in connection with a loan or debt financing.
EPO has indemnified us against certain pre-February 2007 environmental and related liabilities associated with the assets it contributed to us at the time of our 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, we are not entitled to indemnification until the aggregate amount of claims we incur 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 us 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 us in connection with our initial public offering are located and failure to obtain certain consents and permits necessary to conduct our 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 us in connection with our 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 our general partner, adversely affect holders of the Partnership’s common units.
Neither EPO nor any of its affiliates are restricted under the Omnibus Agreement from competing with us. 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 us 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 the Partnership in accordance with the existing sharing ratio of 66% funded by the Partnership and 34% funded by EPO. Under the Omnibus Agreement, EPO agreed to make additional contributions to us as reimbursement for our 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 our initial public offering. In December 2007, EPO made cash contributions totaling $9.9 million to our 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 the Partnership is not a participant. This contribution was in accordance with provisions of the Mont Belvieu Caverns’ limited liability company agreement, which states that when the Partnership 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, the Partnership may elect to reacquire for consideration a 66% share of these projects at a later date.
Mont Belvieu Caverns distributed to us the $48.0 million in cash contributions it received from EPO with respect to the foregoing contributions made under the Omnibus Agreement ($9.9 million) and Mont Belvieu Caverns’ limited liability company agreement ($38.1 million). We, in turn, used such proceeds to reduce amounts outstanding under our revolving credit facility.
We expect additional contributions from EPO under the Omnibus Agreement and Mont Belvieu Caverns limited liability company agreement in 2008.
Other Transactions. The following information summarizes various other related party transactions and arrangements between us and EPO during the year ended December 31, 2007:
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In September 2007, Enterprise Texas Pipeline LLC, a wholly owned subsidiary of EPO, purchased certain parcels of land and regulatory permits from Mont Belvieu Caverns for $3.2 million. Due to common control considerations, the excess of the proceeds received from EPO over the carrying value of the assets sold was recorded as an equity contribution to Mont Belvieu Caverns. We used our $2.1 million share of the proceeds from this transaction to temporarily reduce principal outstanding under our revolving credit facility.
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At the time of our initial public offering, we used $260.6 million of net proceeds from our initial public offering and $198.9 million in borrowings under our revolving credit facility to make a $459.5 million distribution to EPO as partial consideration for assets contributed to us and reimbursements for capital expenditures related to these assets. The remainder of such consideration consisted of our issuing EPO a final amount of 5,351,571 of our common units. EPO received $31.4 million of cash distributions from us during the eleven months ended December 31, 2007 based on its ownership of our limited partner units.
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Duncan Energy Partners Predecessor participated in the EPO’s cash management program for all periods presented prior to the closing of our initial public offering. For purposes of presentation in our Statements of Consolidated/Combined Cash Flows, cash flows from financing activities represent transfers of excess cash from us to EPO equal to cash flows provided by operating activities less cash used in investing activities. Such transfers of excess cash are shown as distributions to owners in the Statements of Consolidated/Combined Partners’ Equity/Owners’ Net Investment. As a result, the financial statements do not present cash balances for the periods prior to our initial public offering.
Since our initial public offering, our operating subsidiaries distribute 34% of their operating cash flows to EPO. These distributions totaled $31.4 million for the eleven months ended December 31, 2007.
Relationship with Evangeline
Acadian Gas, through a wholly owned subsidiary, owns a collective 49.51% equity interest in Evangeline. Acadian Gas does not have a controlling interest in Evangeline, but does exercise significant influence over its operating policies. Evangeline’s most significant contract is a natural gas sales agreement with Entergy Louisiana (“Entergy”) that expires in January 2013. Under this contract, Evangeline is obligated to make available-for-sale and deliver to Entergy certain specified minimum contract quantities of natural gas on an hourly, daily, monthly and annual basis. The sales contract provides for minimum annual quantities of 36.75 BBtus.
In connection with the Entergy sales contract, Evangeline has entered into a natural gas purchase contract with Acadian Gas that contains annual purchase provisions that correspond to Evangeline’s sales commitments to Entergy. The pricing terms of the sales agreement with Entergy and Evangeline’s purchase agreement with Acadian Gas are based on a monthly weighted-average market price of natural
gas (subject to certain market index price ceilings and incentive margins) plus a predetermined margin. Acadian Gas sold $248.8 million of natural gas to Evangeline during the year ended December 31, 2007.
EPO has furnished letters of credit on behalf of Evangeline’s debt service requirements. The outstanding letters of credit totaled $1.1 million, at both December 2007 and 2006.
Relationship with EPCO
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, Enterprise Products 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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In accordance with prudent industry practices, EPCO provides administrative, management, engineering and operating services as may be necessary to manage and operate our businesses, properties and assets. EPCO employs or otherwise retains the services of personnel providing these 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 EPCO expenses reasonably allocated to us). In addition, we have agreed to pay all sales, use, excise, value added or similar taxes, if any, which may be applicable to the services provided by EPCO.
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We participate as named insureds in EPCO’s insurance program, with the associated premiums and related costs being allocated to us. We reimbursed EPCO $1.6 million for insurance costs during the year ended December 31, 2007.
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Our operating costs and expenses include reimbursement payments to EPCO for the costs it incurs to operate our facilities, including the compensation of employees. We reimburse EPCO for actual direct and indirect expenses it incurs related to the operation of our assets. Our reimbursements to EPCO for operating costs and expenses were $16.9 million for the year ended December 31, 2007.
§
Our general and administrative expenses include reimbursement payments to EPCO for the costs it incurs for providing administrative services to us, including the compensation of employees. Such reimbursements are either (i) on an actual basis for direct expenses EPCO incurs on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to the ASA, which, in-turn, is based on the estimated usage 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 businesses and affairs). Our reimbursements to EPCO for general and administrative costs were $2.4 million for the year ended December 31, 2007.
A small number of key employees of EPCO that devote a portion of their time to our operations and affairs participate in long-term incentive compensation plans managed by EPCO. These plans include the issuance of unit options and restricted common units of Enterprise Products Partners and profits interests in the Employee Partnerships. The amount of equity-based compensation allocated to us was $0.2 million for the year ended December 31, 2007. Such amounts are immaterial to our consolidated financial position, results of operations and cash flows.
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 desire 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 desire 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 EPCO Holdings or 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. Enterprise Products Partners will be presumed to desire to 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. Enterprise GP Holdings will be presumed to desire 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 EPCO Holdings or 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.
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 related party transactions. 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 DEP GP or its ACG Committee.
Under our partnership agreement, unless otherwise expressly provided therein or in the partnership agreement of EPO, 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, the partnership agreement of EPO or any agreement contemplated by such agreements, 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 (a “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.
In connection with its resolution of any conflict of interest, the ACG Committee (through its Special Approval process) is authorized to consider:
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the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest;
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the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us);
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any customary or accepted industry practices and any customary or historical dealings with a particular person;
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any applicable generally accepted accounting or engineering practices or principles;
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the relative cost of capital of the parties and the consequent rates of return to the equity holders of the parties; and
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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 our 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.
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 our management authorization policy (generally, for transactions involving amounts greater than $100 million), (ii) where an officer or director of our general partner or any of our subsidiaries is a party, (iii) when requested to do so by our management or the Board, or (iv) pursuant to our partnership agreement 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, drop-downs and business combinations and purchases and sales of product and services. As a matter of course, management reviews the terms and conditions of proposed transactions, performs appropriate levels of due diligence and assesses the impact of such transaction on our partnership.
The ACG Committee does not separately review individual transactions covered by the EPCO administrative services agreement, which was previously approved by the ACG Committee and the Board. For a description of the administrative services agreement, please read “Relationship with EPCO” within this Item 13.
The policies and procedures described above are applicable to related party transactions occurring after November 6, 2007, the date on which the ACG Committee charter was amended and restated. Transactions that occurred between February 5, 2007, which was the date we completed our initial public offering, and November 6, 2007 were governed by policies and procedures that were essentially the same as those described above, with the exception that after November 6, 2007, the ACG Committee charter requires that certain transactions be presented to the ACG Committee for approval. Transactions between Duncan Energy Partners Predecessor and related parties that occurred prior to the completion of our initial public offering were not governed by these policies and procedures.
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 principal accountant. The following table summarizes fees we and Duncan Energy Partners Predecessor 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, partnership tax planning and property tax assistance.
(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 years ended December 31, 2007 and 2006.
The ACG Committee of DEP GP 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 audited financial statements are included 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 already appears in our financial statements or notes thereto.
(a)(3) Exhibits.
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 DEP Holdings, LLC)
/s/ Dan L. Duncan
Dan L. Duncan
Director and Chairman
/s/ Richard H. Bachmann
Richard H. Bachmann
Director, President and Chief Executive Officer
/s/ W. Randall Fowler
W. Randall Fowler
Director, Executive Vice President and Chief Financial Officer
/s/ Gil H. Radtke
Gil H. Radtke
Director, Senior Vice President and Chief Operating Officer
/s/ Michael J. Knesek
Michael J. Knesek
Senior Vice President, Controller and Principal Accounting Officer
/s/ Dr. Ralph S. Cunningham
Dr. Ralph S. Cunningham
Director
/s/ William A. Bruckmann, III
William A. Bruckmann, III
Director
/s/ Larry J. Casey
Larry J. Casey
Director
/s/ Joe D. Havens
Joe D. Havens
Director
/s/ William Ordemann
William Ordemann
Director
EXHIBIT INDEX
*
With respect to exhibits incorporated by reference to Exchange Act filings, the Commission file number for Enterprise Products Partners L.P. is 1-14323; Enterprise GP Holdings L.P., 1-32610; and Duncan Energy Partners L.P., 1-33266.

Portions of this exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a confidential treatment request under Rule 406 of the Securities Act of 1933, as amended.
***
Identifies management contract and compensatory plan arrangements.
#
Filed with this report.