The following table shows the range of interest rates paid and weighted-average interest rate paid on our variable-rate debt obligations during 2004.
The following table shows scheduled maturities of the principal amounts of our debt obligations for the next 5 years and in total thereafter.
In addition, the long-term portion of our debt obligations at December 31, 2004 reflects our refinancing of the $350 million in principal amount Senior Notes A (due March 2005) with proceeds from the Operating Partnership's March 2005 issuance of $250 million in principal amount Senior Notes I (due March 2015) and the Operating Partnership's $250 million in principal amount Senior Notes J (due March 2035). In accordance with SFAS No. 6, the principal amount due under Senior Notes A has been reclassified to amounts due after 2009 to match the scheduled maturities of Senior Notes I and J.
We have ownership interests in four joint ventures having long-term debt obligations. The following table shows (i) our ownership interest in each entity at December 31, 2004, (ii) total long-term debt obligations (including current maturities) of each unconsolidated affiliate at December 31, 2004, on a 100% basis to the joint venture and (iii) the corresponding scheduled maturities of such long-term debt.
The following is a summary of the significant aspects of the debt obligations of our unconsolidated affiliates.
The construction loan bears interest at a variable rate. Once the Cameron Highway oil pipeline has commenced operations and transported a certain level of volumes (as specified in the credit agreement), the construction loan will convert to a term loan maturing in July 2008, subject to the terms of the loan agreement. At the end of the first quarter following the first anniversary of the conversion into a term loan, Cameron Highway will be required to make quarterly principal payments of $8.1 million, with the remaining unpaid principal amount payable on the maturity date. If the construction loan fails to convert into a term loan by January 2006, the construction loan and senior secured notes become fully due and payable. At December 31, 2004, Cameron Highway had $197 million outstanding under its construction loan at an average interest rate of 5.48%.
The interest rate on Cameron Highway's senior secured notes is 3.25% over the rate on 10-year U.S. Treasury securities. Principal payments of $4 million are due quarterly from September 2008 through December 2011, $6 million each from March 2012 through December 2012, and $5 million each from March 2013 through the principal maturity date of December 2013. At December 31, 2004, Cameron Highway had $100 million outstanding under its senior secured notes at an average interest rate of 7.36%.
The project loan facility as a whole is secured by (1) substantially all of Cameron Highway's assets, including, upon conversion to a term loan, a debt service reserve capital account, and (2) all of the equity interest in Cameron Highway. Other than the pledge of our equity interest and our construction obligations under the relevant producer agreements, the debt is non-recourse to us. The construction loan and senior secured notes prohibit Cameron Highway from making distributions to us until the construction loan is converted into a term loan and Cameron Highway meets certain financial requirements.
substantially all of Deepwater Gateway’s assets. Deepwater Gateway is required to maintain a debt service reserve of not less than the projected principal, interest and fees due on the term loan for the immediately succeeding six month period. If Deepwater Gateway defaults on its payment obligations under the term loan, we would be required to pay the lenders all distributions we or any of our subsidiaries had received from Deepwater Gateway up to $22.5 million. As of December 31, 2004, the average interest rate charged under this term loan was 4.42%.
Poseidon. Poseidon is party to a $170 million revolving credit facility which matures in January 2008. The interest rates Poseidon is charged on balances outstanding under its revolving credit facility are variable and depend on its ratio of total debt to earnings before interest, taxes, depreciation and amortization. This credit agreement is secured by substantially all of Poseidon’s assets. As of December 31, 2004, the average interest rate charged under Poseidon’s revolving credit facility was 4.58%.
Evangeline. At December 31, 2004, long-term debt for Evangeline consisted of (i) $28.2 million in principal amount of 9.9% fixed-rate Series B senior secured notes that are due in December 2010 and (ii) a $7.5 million subordinated note payable. The Series B senior secured notes are collateralized by Evangeline’s property, plant and equipment; proceeds from a gas sales contract; and by a debt service requirement. Scheduled principal repayments on the Series B notes are $5 million annually through 2009 with a final repayment in 2010 of approximately $3.2 million. The trust indenture governing the Series B notes contains covenants such as requirements to maintain certain financial ratios. Evangeline incurred the subordinated note payable in connection with its acquisition of a contract-based intangible asset in the early 1990s. This note is subject to a subordination agreement which prevents the repayment of principal and accrued interest on the note until such time as the Series B note holders are either fully cash secured through debt service accounts or have been completely repaid. In general, interest accrues on the subordinated note at a variable-rate based on LIBOR plus ½%. The variable interest rate paid on this debt at December 31, 2004 was 1.73%.
10. MINORITY INTEREST
Minority interest represents third-party and related party ownership interests in the net assets of certain of our subsidiaries. The following table shows the components of minority interest at December 31, 2004:
EPD’s limited partners: | |
Non-affiliates of EPGP Members | $ 3,992,153 |
Affiliates of EPGP Members | 802,505 |
Joint venture partners | 71,040 |
| $ 4,865,698 |
The minority interest attributable to EPD's limited partners consists of EPD common units held by the public, Shell and affiliates of the Company, which primarily includes EPCO, and is net of unamortized deferred compensation of $10.9 million which represents the value of EPD common units issued to key employees of EPCO. The minority interest attributable to joint venture partners is primarily attributable to our partners in Tri-States, Seminole, Wilprise, Independence Hub and the Mid-America pipeline system. For financial reporting purposes, the assets and liabilities of our majority owned subsidiaries are consolidated with those of our own, with any third-party investor's ownership in our consolidated balance sheet amounts shown as minority interest.
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11. CAPITAL STRUCTURE
At December 31, 2004, our members’ equity account balances and ownership interests were as follows:
| | Membership | |
| | Percentage | |
DFI | | 85.595% | $ 46,106 |
DDC | 4.505% | 3,378 |
El Paso | | 9.900% | 90,845 |
| Subtotal | | 140,329 |
Accumulated Other Comprehensive Income | 24,554 |
| Total | | $ 164,883 |
Earnings and cash distributions are allocated to Member capital accounts in accordance with their respective membership percentages. DFI acquired Shell’s 30% member interest in us on September 12, 2003. On September 30, 2004, El Paso was granted a 9.9% membership interest in the Company in connection with our acquisition of El Paso’s 50% membership interest in GulfTerra GP (see Note 4). In January 2005, Enterprise GP Holdings, L.P., a subsidiary of EPCO, purchased El Paso’s 9.9% membership interest in us (see Note 17). See Note 14 for information regarding our Accumulated Other Comprehensive Income.
12. RELATED PARTY TRANSACTIONS
We have an extensive and ongoing relationship with EPCO. EPCO is controlled by Dan L. Duncan, who is one of our directors and Chairman. In addition, our executive and other officers are employees of EPCO, including Robert G. Phillips who is our Chief Executive Officer and one of our directors.
On September 30, 2004, we borrowed $370 million from DDC, which owns a 4.5% membership interest in the Company (see Note 9). DDC is wholly owned by Dan L. Duncan. We used the proceeds from this borrowing to fund the cash portion of the consideration paid to El Paso for a 50% membership interest in GulfTerra GP (see Note 4).
Mr. Duncan owns 50.4% of the voting stock of EPCO. The remaining shares of EPCO capital stock are held primarily by trusts for the benefit of members of Mr. Duncan’s family. In addition, at December 31, 2004, EPCO and DDC, together, owned 90.1% of our membership interests. In January 2005, an affiliate of EPCO, Enterprise GP Holdings L.P., acquired El Paso’s 9.9% membership interest in us (see Note 17). As a result of this transaction, EPCO and its affiliates own 100% of our membership interests.
Our agreements with EPCO are not the result of arm’s-length transactions, and there can be no assurance that any of the transactions provided for therein are effected on terms at least as favorable to the parties to such agreement as could have been obtained from unaffiliated third parties.
Administrative Services Agreement. We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to the Administrative Services Agreement. Under the current terms of the Administrative Services Agreement, EPCO agrees to:
• | employ the personnel necessary to manage our business and affairs; |
• | employ the operating personnel involved in our business; |
• | allow us to participate as named insureds in EPCO’s current insurance program with the costs being allocated among the parties on the basis set forth in the agreement; |
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• | sublease to the Operating Partnership certain equipment which it holds pursuant to operating leases for one dollar per year and to assign to us its purchase option under such leases (the “retained leases”). EPCO remains liable for the cash lease payments associated with these assets. |
The Operating Partnership records the lease payment made by EPCO as a non-cash operating expense offset by a corresponding increase in its partners' equity. As of December 31, 2004, the remaining retained leases were for a cogeneration unit and approximately 100 railcars. During 2004, the Operating Partnership exercised their options to purchase an isomerization unit and related equipment at a cost of $17.8 million. Should the Operating Partnership decide to exercise the purchase options associated with the remaining retained leases (which are also at fair value), an additional $2.3 million would be payable in 2008 and $3.1 million in 2016. In addition to retained lease expenses, operating costs and expenses include compensation charges for EPCO’s employees who operate our facilities.
Prior to January 1, 2004, our payments to EPCO and related non-cash expenses for administrative support were based on the following:
• | We reimbursed EPCO for their share of the costs of certain of its employees in administrative positions that were active at the time of EPD's initial public offering in July 1998 (the “pre-expansion” administrative personnel). Our obligation for reimbursing these costs was covered by the EPCO Administrative Service Fee. |
• | To the extent that EPCO’s actual cost of providing the pre-expansion administrative personnel exceeded the Administrative Service Fee charged to us during a given year, we recorded a non-cash expense equal to the difference between EPCO's actual cost and the Administrative Service Fee charged. The offset was recorded in partners' equity as a general contribution to the Operating Partnership. |
• | We also reimbursed EPCO for all costs it incurs related to administrative personnel it hires in response to our expansion activities. |
Effective January 1, 2004, the Administrative Services Agreement was amended to eliminate the fixed Administrative Services Fee and to provide that the Operating Partnership reimburse EPCO for all costs related to administrative support regardless of whether the costs are related to pre-expansion or expansion personnel who work on our behalf.
On October 22, 2004, the Administrative Services Agreement was amended further to evidence our separateness from other persons and entities, to reflect a five-year license we granted for EPCO’s use of service marks owned by us and to provide for reimbursement of EPCO’s costs of discontinuing the use of those service marks over the term of the license. This amendment also provides that if EPCO and its affiliates are offered by a third party, or discover an opportunity to acquire from a third party, a business or assets that is or are in the same or similar line of business then being conducted by the Operating Partnership or in a line of business that would be a natural extension of any business then being conducted by the Operating Partnership (a “Business Opportunity”), EPCO shall promptly advise our Board of Directors of such Business Opportunity and offer such Business Opportunity to the Operating Partnership. If our Board of Directors does not advise EPCO within 10 days following the receipt of such notice that we wish to pursue such Business Opportunity, EPCO shall then be permitted to pursue such Business Opportunity. If our Board of Directors advises EPCO within such 10 day period that we want to pursue such Business Opportunity, EPCO shall not be permitted to pursue such Business Opportunity unless our Board of Directors subsequently advises EPCO that it has abandoned its pursuit of such Business Opportunity.
Other related party transactions with EPCO. The following is a summary of other significant related party transactions between EPCO and us, including those between EPCO and our unconsolidated affiliates.
• | Prior to January 1, 2004, EPCO was the operator of our MTBE facility and Houston Ship Channel NGL import facility. |
• | We have entered into an agreement with EPCO to provide trucking services to us for the transportation of NGLs and other products. |
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| |
• | In the normal course of business, we also buy from and sell to EPCO’s Canadian affiliate certain NGL products. |
We and EPD are separate legal entities from EPCO and its other affiliates, with assets and liabilities that are separate from EPCO and its other affiliates. EPCO primarily depends on the cash distributions it receives as an equity owner in EPD to fund its other operations and to meet its debt obligations.
We have a significant commercial relationship with Shell as a partner, customer and vendor. At March 15, 2005, Shell owned approximately 9.5% of EPD's common units. In March 2005, EPD registered for resale Shell's 36,572,122 common units under a registration rights agreement EPD executed with Shell in connection with EPD's acquisition of certain of Shell's Gulf Coast midstream energy businesses in September 1999. For additional information regarding this subsequent event, see Note 17. Shell sold its 30.0% interest in us to a subsidiary of EPCO in September 2003.
Shell is one of our largest customers. For the year ended December 31, 2004, Shell accounted for 6.5% of our consolidated revenues. Our revenues from Shell primarily reflect the sale of NGL and petrochemical products to Shell and the fees we charge Shell for natural gas processing, pipeline transportation and NGL fractionation services. Our operating costs and expenses with Shell primarily reflect the payment of energy-related expenses related to the Shell natural gas processing agreement and the purchase of NGL products from Shell. We also lease from Shell its 45.4% interest in one of our propylene fractionation facilities located in Mont Belvieu, Texas.
The most significant contract affecting our natural gas processing business is the Shell margin-band/keepwhole processing agreement, which grants us the right to process Shell's current and future production within state and federal waters of the Gulf of Mexico. The Shell processing agreement includes a life of lease dedication, which may extend the agreement well beyond its initial 20-year term ending in 2019.
We have also completed a number of business acquisitions and asset purchases involving Shell since 1999, including the acquisition of midstream energy assets located along the Gulf Coast for approximately $528.8 million in 1999; the purchase of the Lou-Tex Propylene pipeline for $100 million in 2000; and the acquisition of the Acadian Gas pipeline system in 2001 for $243.7 million.
Relationships with unconsolidated affiliates |
Our investment in unconsolidated affiliates with industry partners is a vital component of our business strategy. These investments are a means by which we conduct our operations to align our interests with a supplier of raw materials or a consumer of finished products. This method of operation also enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what we could accomplish on a stand-alone basis. Many of these businesses perform supporting or complementary roles to our other business operations. The following summarizes significant related party transactions we have with our current unconsolidated affiliates:
• | We sell natural gas to Evangeline, which, in turn, uses the natural gas to satisfy supply commitments it has with a major Louisiana utility. In addition, we have also furnished $11.1 million in letters of credit on behalf of Evangeline. |
• | We pay transportation fees to Dixie for propane movements on their system initiated by our NGL marketing activities. |
• | We pay Promix for the transportation, storage and fractionation of certain of our mixed NGL volumes. In addition, we sell natural gas to Promix for their fuel requirements. |
We enter into management agreements with some of our unconsolidated affiliates under which our unconsolidated affiliates pay us management fees for the operation and management of their assets. Additionally, on occasion we pay for construction costs on behalf of our unconsolidated affiliates during the initial construction
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phase of their assets, and these amounts are settled by direct reimbursements for the amounts we are owed from our unconsolidated affiliates.
13. COMMITMENTS AND CONTINGENCIES
Redelivery Commitments
We store and transport NGL, petrochemical and natural gas volumes for third parties under various processing, storage, transportation and similar agreements. Under the terms of these agreements, we are generally required to redeliver volumes to the owner on demand. We are insured for any physical loss of such volumes due to catastrophic events. At December 31, 2004, NGL and petrochemical volumes aggregating 13.5 million barrels were due to be redelivered to their owners along with 18,038 BBtus of natural gas.
Commitments under equity compensation plans of EPCO |
In accordance with our agreements with EPCO, we reimburse EPCO for our share of its compensation expense associated with certain employees who perform management, administrative and operating functions for EPD (see Note 12). This includes the costs associated with equity-based awards granted to these employees. At December 31, 2004, there were 2,463,000 options outstanding to purchase common units under EPCO’s 1998 Plan that had been granted to employees for which we are responsible for reimbursing EPCO for the costs of such awards. The weighted-average strike price of the unit option awards granted was $18.84 per common unit. At December 31, 2004, 1,154,000 of these unit options were exercisable. An additional 374,000, 25,000 and 910,000 of these unit options will be exercisable in 2005, 2006 and 2008, respectively. As these options are exercised, we will reimburse EPCO in the form of a special cash distribution for the difference between the strike price paid by the employee and the actual purchase price paid for the units awarded to the employee.
Other commitments
The following table summarizes our various contractual obligations at December 31, 2004. A description of each type of contractual obligation follows.
| Payment or Settlement due by Period
|
|---|
Contractual Obligations
| Total
| 2005
| 2006
| 2007
| 2008
| 2009
| Thereafter
|
|---|
| Scheduled maturities of long-term debt | | | $ | 4,655,131 | | $ | 18,450 | | $ | 3,802 | | $ | 504,045 | | $ | 4,242 | | $ | 825,576 | | $ | 3,299,016 | |
| |
| Operating lease obligations | | | $ | 88,899 | | $ | 15,012 | | $ | 13,328 | | $ | 12,294 | | $ | 9,496 | | $ | 5,418 | | $ | 33,351 | |
| |
| Purchase obligations: | | |
| Product purchase commitments: | | |
| Estimated payment obligations: | | |
| Natural gas | | | $ | 1,160,829 | | $ | 165,120 | | $ | 142,133 | | $ | 142,133 | | $ | 142,522 | | $ | 142,133 | | $ | 426,788 | |
| NGLs | | | $ | 174,281 | | $ | 42,664 | | $ | 10,968 | | $ | 10,968 | | $ | 10,968 | | $ | 10,968 | | $ | 87,745 | |
| Petrochemicals | | | $ | 1,791,983 | | $ | 1,010,907 | | $ | 667,288 | | $ | 107,540 | | $ | 6,248 | |
| Other | | | $ | 166,706 | | $ | 41,706 | | $ | 32,179 | | $ | 30,092 | | $ | 28,690 | | $ | 18,155 | | $ | 15,884 | |
| Underlying major volume commitments: | | |
| Natural gas (in BBtus) | | | | 149,705 | | | 21,855 | | | 18,250 | | | 18,250 | | | 18,300 | | | 18,250 | | | 54,800 | |
| NGLs (in MBbls) | | | | 5,657 | | | 1,267 | | | 366 | | | 366 | | | 366 | | | 366 | | | 2,926 | |
| Petrochemicals (in MBbls) | | | | 27,294 | | | 15,559 | | | 10,126 | | | 1,520 | | | 89 | |
| |
| Service payment commitments | | | $ | 7,580 | | $ | 4,906 | | $ | 2,038 | | $ | 636 | |
| Capital expenditure commitments | | | $ | 69,288 | | $ | 69,288 | |
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Long-term debt-related commitments. We have long and short-term payment obligations under credit agreements such as our Senior Notes and revolving credit facilities. The preceding table shows our scheduled future maturities of long-term debt principal (including current maturities) for the periods indicated. See Note 9 for a description of these debt obligations and classification used for accounting purposes.
Operating lease commitments. We lease certain property, plant and equipment under noncancelable and cancelable operating leases. The preceding table shows the minimum lease payment obligations under our third-party operating leases with terms in excess of one year for the periods indicated.
Our material agreements consist of operating leases, with original terms ranging from 5 to 24 years, for natural gas and NGL underground storage facilities. We generally have the option to renew these leases, under the terms of the agreements, for one or more renewal terms ranging from 2 to 10 years. In general, rent is determined by multiplying a storage quantity (typically in barrels) by a contractually stated price. Rental payments under our storage leases are escalated, as specified in the lease, to reflect increases in the market value of the storage capacity or to adjust for inflation. In general, contingent rental payments are assessed when our storage volumes exceed our storage allotment and are equal to the product of (i) a contractually stated price and (ii) the volume which exceeds our storage allotment.
Lease expense is charged to operating costs and expenses on a straight line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred. Under certain of our natural gas and NGL storage lease agreements, we are required to perform routine maintenance on the storage facility. In addition, certain leases give us the option to increase storage capacity or fund major leasehold improvements. Maintenance, repairs and minor renewals are charged to operations as incurred. We have not made any major leasehold improvements with regards to our natural gas and NGL underground storage facilities during the year ended December 31, 2004.
The operating lease commitments shown in the preceding table exclude the non-cash related party expense associated with various equipment leases contributed to us by EPCO at our formation for which EPCO has retained the liability (the “retained leases”). The retained leases are accounted for as operating leases by EPCO. EPCO’s minimum future rental payments under these leases are $2.1 million for each of the years 2005 through 2008, $0.7 million for each of the years 2009 through 2015 and $0.3 million for 2016.
EPCO has assigned to the Operating Partnership the purchase options associated with the retained leases. During 2004 we purchased an isomerization unit and related equipment for $17.8 million pursuant to their purchase options, which prices approximated fair value. Should we decide to exercise all of the remaining purchase options associated with the retained leases (which are also at fair value), up to an additional $2.3 million would be payable in 2008 and $3.1 million in 2016.
Purchase obligations. We define purchase obligations as agreements to purchase goods or services that are enforceable and legally binding (unconditional) and 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. We have classified our unconditional purchase obligations into the following categories:
• | Product purchase commitments. We have long and short-term product purchase obligations for NGLs, petrochemicals and natural gas with several third-party suppliers. The purchase prices that we are generally obligated to pay under these contracts approximate market prices at the time we take delivery of the volumes. The preceding table shows our volume commitments and estimated payment obligations under these contracts for the periods indicated. At December 31, 2004, we do not have any product purchase commitments with fixed or minimum pricing provisions having remaining terms in excess of one year. To the extent that variable price provisions exist in these contracts, our estimated future payment obligations are based on the contractual price under each contract for purchases made at December 31, 2004 applied to future volume commitments. |
• | Service contract commitments. We have long and short-term commitments to pay third-party service providers for services such as maintenance agreements. Our contractual payment obligations vary by contract. The preceding table shows our future payment obligations under these service contracts. |
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| |
• | Capital expenditure commitments. We have short-term payment obligations relating to capital projects we have initiated and are also responsible for our share of such obligations associated with capital projects of our unconsolidated affiliates. These commitments represent unconditional payment obligations that we or our unconsolidated affiliates have agreed to pay vendors for services rendered or products purchased. The preceding table shows these combined amounts for the periods indicated. |
Litigation
We are sometimes named as a defendant in litigation relating to our normal business operations, including litigation related to various federal, state and local regulatory and environmental matters. Although we insure against various business risks, to the extent management believes 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 ordinary business activity. Management is not aware of any significant litigation, pending or threatened, that would have a significant adverse effect on our financial position or results of operations.
We own a facility that historically produced MTBE, a motor gasoline additive that enhances octane and is used in reformulated motor gasoline. We operated the facility, which is located within our Mont Belvieu complex. The production of MTBE was primarily driven by oxygenated fuel programs enacted under the federal Clean Air Act Amendments of 1990. In recent years, MTBE has been detected in water supplies. The major source of ground water contamination appears to be leaks from underground storage tanks. As a result of environmental concerns, several states enacted legislation to ban or significantly limit the use of MTBE in motor gasoline within their jurisdictions. In addition, federal legislation has been drafted to ban MTBE and replace the oxygenate with renewable fuels such as ethanol.
A number of lawsuits have been filed by municipalities and other water suppliers against a number of manufacturers of reformulated gasoline containing MTBE, although generally such suits have not named manufacturers of MTBE as defendants, and there have been no such lawsuits filed against our subsidiary which owns the facility. It is possible, however, that MTBE manufacturers such as our subsidiary could ultimately be added as defendants in such lawsuits or in new lawsuits.
Performance Guaranty
In December 2004, our Independence Hub, LLC subsidiary entered into the Independence Hub Agreement (the "Agreement") with six oil and natural gas producers. The Agreement obligates Independence Hub, LLC (i) to construct an offshore platform production facility to process 850 MMcf/d of natural gas and condensate and (ii) to process certain natural gas and condensate production of the six producers following construction of the platform facility.
In conjunction with the Agreement, the Operating Partnership guaranteed the performance of its Independence Hub, LLC subsidiary under the Hub Agreement up to $397.5 million. In December 2004, 20% of this guaranteed amount was assumed by Cal Dive, our joint venture partner in the Independence Hub project. The remaining $318 million represents our share of the anticipated cost of the platform facility. This amount represents the cap on the Operating Partnership's potential obligation to the six producers for our share of the cost of constructing the platform in the very unlikely scenario where the six producers take over the construction of the platform facility. The Operating Partnership's performance guarantee continues until the earlier to occur of (i) all of the guaranteed obligations of Independence Hub, LLC shall have been terminated or expired, or shall have been indefeasibly paid or otherwise performed or discharged in full, (ii) upon mutual written consent of the Operating Partnership and the producers or (iii) mechanical completion of the production facility. We expect that mechanical completion will occur on or about November 1, 2006; therefore, we anticipate that the performance guaranty will exist until at least this forecast date.
In accordance with FIN 45, we recorded the fair value of the performance guaranty using an expected present value approach. Given the remote probability that the Operating Partnership would be required to perform under the guaranty, we have estimated the fair value of the performance guaranty at approximately $1.2 million, which is a component of current and other long-term liabilities on our Consolidated Balance Sheet at December 31, 2004.
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14. 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. In general, the type of risks we attempt to hedge are those related to the variability of future earnings, fair values of certain debt instruments and cash flows resulting from changes in applicable interest rates or commodity prices. As a matter of policy, we do not use financial instruments for speculative (or “trading”) purposes.
We recognize financial instruments as assets and liabilities on our Consolidated Balance Sheets based on fair value. Fair value is generally defined as the amount at which a financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. The estimated fair values of our financial instruments have been determined using available market information and appropriate valuation techniques. We must use considerable judgment, however, in interpreting market data and developing these estimates. Accordingly, our fair value estimates are not necessarily indicative of the amounts that we could realize upon disposition of these instruments. The use of different market assumptions and/or estimation techniques could have a material effect on our estimates of fair value.
Changes in the fair value of financial instrument contracts are recognized currently in earnings unless specific hedge accounting criteria are met. If the financial instruments meet those criteria, the instrument’s gains and losses offset the related results of the hedged item in earnings for a fair value hedge and are deferred in other comprehensive income for a cash flow hedge. Gains and losses related to a cash flow hedge are reclassified into earnings when the forecasted transaction affects earnings.
To qualify as a hedge, the item to be hedged must be exposed to commodity or interest rate risk and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (as amended and interpreted). We must formally designate the financial instrument as a hedge and document and assess the effectiveness of the hedge at inception and on a quarterly basis. Any ineffectiveness of the hedge is recorded in current earnings.
Due to the complexity of SFAS No. 133 (as amended and interpreted), the FASB is continuing to provide guidance regarding the implementation of this accounting standard. Since this guidance is still continuing, our conclusions about the application of SFAS No. 133 may be altered, which may result in adjustments being recorded in future periods as we adopt new FASB interpretations of this standard.
Interest rate risk hedging program
Our interest rate exposure results from variable and fixed rate borrowings under debt agreements. We assess the cash flow risk related to interest rates by identifying and measuring changes in our interest rate exposures that may impact future cash flows and evaluating hedging opportunities to manage these risks. We use analytical techniques to measure our exposure to fluctuations in interest rates, including cash flow sensitivity analysis models to forecast the expected impact of changes in interest rates on our future cash flows. Management oversees the strategies associated with these financial risks and approves instruments that are appropriate for our requirements.
We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar arrangements, which allow us to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt. We believe that it is prudent to maintain an appropriate balance of variable rate and fixed rate debt in the current business climate.
Fair value hedges – Interest rate swaps. In January 2004, we entered into three interest rate swap agreements with an aggregate notional amount of $250 million in which we exchanged the payment of fixed rate interest on a portion of the principal outstanding under Senior Notes B and C for variable rate interest. During the fourth quarter of 2004, we entered into six additional interest rate swap agreements with an aggregate notional amount of $600 million related to a portion of the principal outstanding under Senior Notes G issued on October 4, 2004.
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| Number | Period Covered | Termination | Fixed to | Notional | |
Hedged Fixed Rate Debt | Of Swaps | by Swap | Date of Swap | Variable Rate(1) | Amount | |
Senior Notes B, 7.50% fixed rate, due Feb. 2011 | 1 | Jan. 2004 to Feb. 2011 | Feb. 2011 | 7.50% to 6.3% | $50 million | |
Senior Notes C, 6.375% fixed rate, due Feb. 2013 | 2 | Jan. 2004 to Feb. 2013 | Feb. 2013 | 6.375% to 4.9% | $200 million | |
Senior Notes G, 5.6% fixed rate, due Oct. 2014 | 6 | 4th Qtr. 2004 to Oct. 2014 | Oct. 2014 | 5.6% to 3.4% | $600 million | |
| |
| (1) The variable rate indicated is the all-in variable rate for the current settlement period. |
| | | | | | | |
We have designated these nine interest rate swaps as fair value hedges under SFAS No. 133 since they mitigate changes in the fair value of the underlying fixed rate debt. As effective fair value hedges, an increase in the fair value of these interest rate swaps is equally offset by an increase in fair value of the underlying hedged debt. The offsetting changes in fair value have no effect on current period interest expense.
These nine agreements have a combined notional amount of $850 million and match the maturity dates of the underlying debt being hedged. Under each swap agreement, we pay the counterparty a variable interest rate based on six-month LIBOR rates (plus an applicable margin as defined in each swap agreement) and receive back from the counterparty a fixed interest rate payment based on the stated interest rate of the debt being hedged, with both payments calculated using the notional amounts stated in each swap agreement. We settle amounts receivable from or payable to the counterparties every six months (the “settlement period”). The settlement amount is amortized ratably to earnings as either an increase or a decrease in interest expense over the settlement period.
Total fair value of the interest rate swaps in effect at December 31, 2004 was a receivable of approximately $0.5 million with an offsetting increase in fair value of the underlying debt.
Cash flow hedges – Forward starting interest rate swaps. During the first nine months of 2004, we entered into eight forward starting interest rate swap transactions having an aggregate notional amount of $2 billion in anticipation of our financing activities associated with closing the GulfTerra Merger. Our purpose in entering into these transactions was to effectively hedge the underlying U.S. treasury rate related to our anticipated issuance of $2 billion in principal amount of fixed rate debt. On October 4, 2004, our Operating Partnership issued $2 billion of private debt securities under Senior Notes E, F, G and H. Each of the forward starting swaps was designated as a cash flow hedge under SFAS No. 133.
In April 2004, we elected to terminate the initial four forward starting swaps in order to manage and maximize the value of the swaps and to reduce future debt service costs. As a result, we received $104.5 million in cash from the counterparties. In September 2004, we settled the remaining four swaps resulting in an $85.1 million payment to the counterparties. The net gain of $19.4 million from these settlements will be reclassified from Accumulated Other Comprehensive Income to reduce interest expense over the life of the associated debt.
The following table shows the notional amount covered by each forward starting swap and the cash gain (loss) associated with each swap upon settlement (dollars in thousands):
| Notional | Net Cash |
| Amount of | Received upon |
| Debt covered by | Settlement of |
Term of Anticipated Debt Offering | Forward | Forward |
(or Forecasted Transaction) | Starting Swaps | Starting Swaps |
3-year, fixed rate debt instrument | $ 500,000 | $ 4,613 |
5-year, fixed rate debt instrument | 500,000 | 7,213 |
10-year, fixed rate debt instrument | 650,000 | 10,677 |
30-year, fixed rate debt instrument | 350,000 | (3,098) |
Total | $ 2,000,000 | $ 19,405 |
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Commodity risk hedging program |
The prices of natural gas, NGLs and petrochemical products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. In order to manage the risks associated with natural gas and NGLs, we may enter into commodity financial instruments. The primary purpose of our commodity risk management activities is to hedge our exposure to price risks associated with (i) natural gas purchases, (ii) NGL production and inventories, (iii) related firm commitments, (iv) fluctuations in transportation revenues where the underlying fees are based on natural gas index prices and (v) certain anticipated transactions involving either natural gas or NGLs. The commodity financial instruments we utilize may be settled in cash or with another financial instrument. Historically, we have not hedged our exposure to risks associated with petrochemical products, including MTBE.
We have adopted a policy to govern our use of commodity financial instruments to manage the risks of our natural gas and NGL businesses. The objective of this policy is to assist us in achieving our profitability goals while maintaining a portfolio with an acceptable level of risk, defined as remaining within the position limits established by the Company. We may enter into risk management transactions to manage price risk, basis risk, physical risk or other risks related to our commodity positions on both a short-term (less than 30 days) and long-term basis, not to exceed 24 months. Management oversees our strategies associated with physical and financial risks (such as those mentioned previously), 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.
At December 31, 2004, we had a limited number of commodity financial instruments in our portfolio, which primarily consisted of natural gas cash flow and fair value hedges. We routinely review our outstanding financial instruments in light of current market conditions. If market conditions warrant, some financial instruments may be closed out in advance of their contractual settlement dates thus realizing income or loss depending on the specific exposure. When this occurs, we may enter into a new commodity financial instrument to reestablish the economic hedge to which the closed instrument relates.
We had a limited number of commodity financial instruments open at December 31, 2004. The fair value of these open positions at December 31, 2004 was an asset of $219 thousand, which amount is based on market prices on that date.
Effect of financial instruments on Accumulated Other Comprehensive Income (Loss)
The following table summarizes the effect of our cash flow hedging financial instruments on accumulated other comprehensive income (loss) since January 1, 2004.
| | Interest Rate Fin. Instrs. | Accumulated |
| | | Forward- | Other |
| Commodity | | Starting | Comprehensive |
| Financial | Treasury | Interest | Income (Loss) |
| Instruments | Locks | Rate Swaps | Balance |
Balance, January 1, 2004 | | $ 4,990 | | $ 4,990 |
Gain on settlement of forward-starting interest rate swaps | | | $ 104,531 | 104,531 |
Loss on settlement of forward-starting interest rate swaps | | | (85,126) | (85,126) |
Change in fair value of commodity financial instrument | $ 1,434 | | | 1,434 |
Reclassification of gain on settlement of treasury locks to interest expense | | (418) | | (418) |
Reclassification of gain on settlement of forward-starting swaps to interest expense | (857) | (857) |
Balance, December 31, 2004 | $ 1,434 | $ 4,572 | $ 18,548 | $ 24,554 |
During 2005, we will reclassify $0.4 million and $3.6 million from Accumulated Other Comprehensive Income as a reduction in interest expense from our treasury locks and forward-starting interest rate swaps, respectively. In addition, in the first quarter of 2005, we will record an approximate $1.6 million gain into income from Accumulated Other Comprehensive Income related to a commodity cash flow hedge acquired in the GulfTerra
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Merger. This gain is primarily due to an increase in fair value from that recorded for the commodity cash flow hedge at December 31, 2004.
Fair value information
Cash and cash equivalents, accounts receivable, accounts payable and accrued expenses are carried at amounts which reasonably approximate their fair value due to their short-term nature. The estimated fair value of our fixed rate debt is estimated based on quoted market prices for such debt or debt of similar terms and maturities. The carrying amounts of our variable rate debt obligations reasonably approximate their fair values due to their variable interest rates. The fair values associated with our commodity and interest rate hedging financial instruments were developed using available market information and appropriate valuation techniques. The following table summarizes the estimated fair values of our various financial instruments at December 31, 2004:
| | Carrying | Fair |
Financial Instruments | Value | Value |
Financial assets: | | |
| Cash and cash equivalents | $ 51,163 | $ 51,163 |
| Accounts receivable | 1,083,526 | 1,083,526 |
| Commodity financial instruments(1) | 3,904 | 3,904 |
| Interest rate hedging financial instruments(2) | 505 | 505 |
Financial liabilities: | | |
| Accounts payable and accrued expenses | 1,468,933 | 1,468,933 |
| Fixed-rate debt (principal amount) | 4,091,902 | 4,289,084 |
| Variable-rate debt | 563,229 | 563,229 |
| Commodity financial instruments(1) | 3,685 | 3,685 |
| | | |
(1) Represent commodity financial instrument transactions that either have not settled or have settled and not been invoiced. Settled and invoiced transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction. (2) Represent interest rate hedging financial instrument transactions that had not settled. Settled transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction. |
Counterparty risk
From time to time, we have credit risk with our counterparties in terms of settlement risk associated with financial instruments. On all transactions where we are exposed to credit risk, 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 and we do not anticipate nonperformance by our counterparties.
15. SEGMENT INFORMATION
Business segments are components of a business about which separate financial information is available. The components are regularly evaluated by our CEO in deciding how to allocate resources and in assessing performance. Generally, financial information is required to be reported on the basis that it is used internally for evaluating segment performance and deciding how to allocate resources to segments.
As a result of the GulfTerra Merger (see Note 4), we have reorganized our business activities into four reportable business segments, as discussed below. Our business segments are generally organized and managed according to the type of services rendered and products produced and/or sold. We have revised our prior segment information in order to conform to the current business segment operations and presentation.
We have segregated our business activities into four reportable business segments: Offshore Pipelines & Services, Onshore Natural Gas Pipelines & Services, NGL Pipelines & Services, and Petrochemical Services. Our
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business segments are generally organized and managed according to the type of services rendered (or technology or process employed) and products produced and/or sold, as applicable.
The Offshore Pipelines & Services business segment consists of (i) approximately 1,150 miles of offshore natural gas pipelines strategically located to serve production areas in some of the most active drilling and development regions in the Gulf of Mexico, (ii) approximately 800 miles of Gulf of Mexico offshore crude oil pipeline systems and (iii) seven multi-purpose offshore hub platforms located in the Gulf of Mexico, which are included in our Offshore Pipelines & Services business segment.
The Onshore Natural Gas Pipelines & Services business segment consists of approximately 17,200 miles of onshore natural gas pipeline systems that provide for the gathering and transmission of natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas. In addition, this segment includes two salt dome natural gas storage facilities located in Mississippi, which are strategically located to serve the Northeast, Mid-Atlantic and Southeast domestic natural gas markets. This segment also includes leased natural gas storage facilities located in Texas and Louisiana.
The NGL Pipelines & Services business segment includes our (i) natural gas processing business and related NGL marketing activities, (ii) NGL pipelines aggregating approximately 12,775 miles and related storage facilities, which include our strategic Mid-America and Seminole NGL pipeline systems and (iii) NGL fractionation facilities located in Texas and Louisiana. This segment also includes our import and export terminaling operations.
The Petrochemical Services business segment includes four propylene fractionation facilities, an isomerization complex, and an octane additive production facility. This segment also includes various petrochemical pipeline systems.
The Other non-segment category is presented for financial reporting purposes only to reflect the historical equity earnings we received from GulfTerra GP and our underlying investment in this entity at December 31, 2003. We acquired a 50% membership interest in GulfTerra GP on December 15, 2003 in connection with Step One of the GulfTerra Merger. Our investment in GulfTerra GP was accounted for using the equity method until the GulfTerra Merger was completed on September 30, 2004. On that date, GulfTerra GP became a wholly owned consolidated subsidiary of ours.
Most of our plant-based operations are located either along the western Gulf Coast in Texas, Louisiana and Mississippi or in New Mexico. Our natural gas, NGL and oil pipelines and related operations are in a number of regions of the United States including the Gulf of Mexico offshore Texas and Louisiana; the south and southeastern United States (primarily in Texas, Louisiana, Mississippi and Alabama); and certain regions of the central and western United States. Our marketing activities are headquartered in Houston, Texas at our main office and service customers in a number of regions in the United States including the Gulf Coast, West Coast and Mid-Continent areas.
Consolidated property, plant and equipment and investments in and advances to unconsolidated affiliates are allocated to each segment on the basis of each asset's or investment's principal operations. The principal reconciling item between consolidated property, plant and equipment and segment assets is construction-in-progress. Segment assets represent those facilities and projects that contribute to gross operating margin and is net of accumulated depreciation on these assets. Since assets under construction generally do not contribute to segment gross operating margin, these assets are excluded from the business segment totals until they are deemed operational. Consolidated intangible assets and goodwill are allocated to each segment based on the classification of the assets to which they relate.
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Information by segment, together with reconciliations to the consolidated totals, is presented in the following table:
| Business Segments
| | | |
|---|
| Offshore
Pipeline
& Services
| Onshore
Nat. Gas
Pipelines
& Services
| NGL
Pipelines
& Services
| Petrochem.
Services
| Non-Segmt.
Other
| Adjustments
and
Eliminations
| Consolidated
Totals
|
|---|
| Segment assets: | | | | | | | | | | | | | | | | | | | | | | | |
| At December 31, 2004 | | | $ | 648,181 | | $ | 3,729,650 | | $ | 2,753,934 | | $ | 469,327 | | | | | $ | 230,375 | | $ | 7,831,467 | |
| Investments in and advances | | |
| to unconsolidated affiliates: | | |
| At December 31, 2004 | | | | 319,463 | | | 5,251 | | | 173,883 | | | 20,567 | | | | | | | | | 519,164 | |
| Intangible Assets: | | |
| At December 31, 2004 | | | | 200,047 | | | 425,806 | | | 303,459 | | | 51,289 | | | | | | | | | 980,601 | |
| Goodwill: | | |
| At December 31, 2004 | | | | 62,348 | | | 290,397 | | | 32,763 | | | 73,690 | | | | | | | | | 459,198 | |
In general, our historical financial position has been affected by numerous acquisitions since 2002. Our most significant transaction to date was the GulfTerra Merger, which was completed on September 30, 2004. The aggregate value of the total consideration we paid or issued to complete the GulfTerra Merger was approximately $4 billion. For information regarding our business combinations, see Note 4.
16. CONDENSED FINANCIAL INFORMATION OF OPERATING PARTNERSHIP
The Operating Partnership and its subsidiaries conduct substantially all of our business. Currently, neither we nor EPD have any independent operations or material assets outside of those of the Operating Partnership.
At December 31, 2004, the Operating Partnership had $3.7 billion in outstanding debt securities represented by its Senior Notes A through H. EPD acts as guarantor of all of the Operating Partnership’s consolidated debt obligations, with the exception of the Seminole Notes and the remaining amounts outstanding under GulfTerra’s senior and senior subordinated notes. If the Operating Partnership were to default on any debt EPD guarantees, EPD would be responsible for full repayment of that obligation. EPD's guarantee of these debt obligations is full and unconditional. These debt obligations are non-recourse to us. For additional information regarding our consolidated debt obligations, see Note 9.
The number and dollar amounts of reconciling items between EPD's consolidated financial statements and those of its Operating Partnership are insignificant. The primary reconciling items between the consolidated balance sheet of the Operating Partnership and EPD's consolidated balance sheet are treasury units EPD owns directly and minority interest.
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The following table shows condensed consolidated balance sheet data for the Operating Partnership at December 31, 2004:
ASSETS | |
Current assets | $ 1,425,574 |
Property, plant and equipment, net | 7,831,467 |
Investments in and advances to unconsolidated affiliates, net | 519,164 |
Intangible assets, net | 980,601 |
Goodwill | 459,198 |
Deferred tax asset | 6,467 |
Long-term receivables | 14,931 |
Other assets | 43,208 |
| Total | $ 11,280,610 |
LIABILITIES AND PARTNERS' EQUITY | |
Current liabilities | $ 1,582,911 |
Long-term debt | 4,266,236 |
Other long-term liabilities | 63,521 |
Minority interest | 73,858 |
Partners' equity | 5,294,084 |
| Total | $ 11,280,610 |
| | |
Total Operating Partnership debt obligations guaranteed by EPD | $ 4,267,229 |
17. SUBSEQUENT EVENTS
January 2005 acquisition of El Paso’s interests in EPD and EPGP by affiliates of EPCO
In January 2005, an affiliate of EPCO, acquired El Paso’s 9.9% membership interest in EPGP and 13,454,499 of EPD's common units from El Paso for approximately $425 million in cash. As a result of these transactions, EPCO and affiliates own 100% of the membership interests of EPGP and, at March 15, 2005, approximately 38.3% of EPD's total common units outstanding. El Paso no longer owns any interest in EPD or EPGP.
February 2005 EPD equity offering
In February 2005, EPD sold 17,250,000 common units (including the over-allotment amount of 2,250,000 common units which closed on March 11, 2005) to the public at an offering price of $27.05 per unit. Net proceeds from this offering, including EPGP’s proportionate net capital contribution of $9.1 million, were approximately $456.5 million after deducting applicable underwriting discounts, commissions and estimated offering expenses of $19.7 million. The net proceeds from this offering, including EPGP’s proportionate net capital contribution, were used to repay our 364-Day Acquisition Credit Facility, to temporarily reduce indebtedness outstanding under our Multi-Year Revolving Credit Facility and for general partnership purposes.
February 2005 EPD private senior notes offering |
On February 15, 2005, the Operating Partnership sold $500 million in principal amount of senior notes in a Rule 144A private placement offering, comprised of $250 million in principal amount of 10-year senior unsecured notes and $250 million in principal amount of 30-year senior unsecured notes. The 10-year notes ("Senior Notes I") were issued at 99.379% of their principal amount and have fixed-rate interest of 5.00% and a maturity date of March 1, 2015. The 30-year notes ("Senior Note J") were issued at 98.691% of their principal amount and have fixed-rate interest of 5.75% and a maturity date of March 1, 2035. The Operating Partnership used the net proceeds from the issuance of Senior Notes I and J to repay $350 million of indebtedness outstanding under Senior Notes A which was on March 15, 2005 and the remaining proceeds for general partnership purposes, including the temporary repayment of indebtedness outstanding under the Multi-Year Revolving Credit Facility.
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March 2005 EPD universal shelf registration statement |
In March 2005, EPD filed a universal shelf registration statement with the SEC registering the issuance of $4 billion of partnership equity and public debt obligations. In connection with this registration statement, EPD also registered for resale 36,572,122 common units currently owned by Shell and 4,427,878 common units that had been sold by Shell to Kayne Anderson MLP Investment Company in December 2004. EPD is obligated to register the resale of these common units under a registration rights agreement we executed with Shell in connection with our acquisition of certain of Shell's Gulf Coast midstream energy businesses in September 1999.
Non-Public Investigation by the Bureau of Competition of the Federal Trade Commission |
On February 24, 2005, an affiliate of EPCO, Enterprise GP Holdings, L.P., acquired TEPPCO GP from Duke Energy Field Services, LLC. TEPPCO GP owns a 2% general partner interest in and is the general partner of TEPPCO. On March 11, 2005, the Bureau of Competition of the Federal Trade Commission delivered written notice to Enterprise GP Holdings, L.P.'s legal advisor that it was conducting a non-public investigation to determine whether Enterprise GP Holdings' acquisition of TEPPCO GP may substantially lessen competition. No filings were required under the Hart-Scott-Rodino Act in connection with Enterprise GP Holdings' purchase of TEPPCO GP. EPCO and its affiliates may receive similar inquiries from other regulatory authorities. EPCO and its affiliates, including us, intend to cooperate fully with any such investigations and inquiries.
Item 9.01. | FINANCIAL STATEMENTS AND EXHIBITS. |
23.1 | Consent of Deloitte & Touche LLP. |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
ENTERPRISE PRODUCTS PARTNERS L.P. |
By: | Enterprise Products GP, LLC, as general partner |
Date: March 31, 2005 | By: | ___/s/ Michael J. Knesek________________ |
| Michael J. Knesek | |
| Senior Vice President, Controller, and | |
| Principal Accounting Officer of | |
| Enterprise Products GP, LLC | |
| | | | | | | |
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EXHIBIT INDEX
Exhibit No. | Exhibit |
23.1 | Consent of Deloitte & Touche LLP. |
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