ITEM 3. LEGAL PROCEEDINGS.
On occasion, we are named as a defendant in litigation relating to our normal business operations. Although we are insured against various business risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings as a result of our ordinary business activity. EPCO has indemnified us against any litigation that was pending at the date of our formation in April 1998.
We are a party to litigation instituted in January 2001 in connection with air emission control regulations in the Houston-Galveston area (see "General impact of the Clean Air Act on our operations" on page 22 for additional information on this subject). Other than this litigation, we are aware of no significant litigation, pending or threatened, that may have a significant adverse effect on our financial position or results of operations.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
There were no matters submitted to a vote of our Limited and General Partner during the fourth quarter of 2001.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED PARTNERSHIP MATTERS.
We do not have any publicly-traded partnership interests; therefore, the information requested under Item 5 is not applicable. Our securities consist of $854 million in public debt: $350 million under Senior Notes A, $450 million under Senior Notes B and $54 million under the MBFC loan. For additional information regarding our long-term debt, see Note 6 of the Notes to Consolidated Financial Statements.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
The following table sets forth for the periods and at the dates indicated, our selected historical financial data. The selected historical financial data have been derived from our audited financial statements for the periods indicated. The selected historical income statement data for each of the three years ended December 31, 2001, 2000 and 1999 and the selected balance sheet data as of December 31, 2001 and 2000 should be read in conjunction with the audited financial statements for such periods included elsewhere in this report. In addition, information regarding results of operations and capital resources and liquidity can be found under Item 7
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION.
The following discussion and analysis should be read in conjunction with our audited consolidated financial statements and notes thereto included elsewhere herein as well as the other portions of this report on Form 10-K. In addition, the reader should review "Cautionary Statement regarding Forward-Looking Information and Risk Factors" beginning on page 1 of this report for information regarding forward-looking statements made in this discussion and certain risks inherent in our business. Other risks involved in our business are discussed under Item 7A
Item 7A on page 46.
Additional information regarding the significant accounting policies underlying preparation of our financial statements (including revenue recognition) can be found in Note 1 of the Notes to Consolidated Financial Statements on page.
OUR RESULTS OF OPERATIONS
We have five reportable operating segments: Fractionation, Pipelines, Processing, Octane Enhancement and Other. Fractionation primarily includes NGL fractionation, isomerization and propylene fractionation. Pipelines consists of liquids and natural gas pipeline systems, storage and import/export terminal services. Processing includes our natural gas processing business and related merchant activities. Octane Enhancement represents our interest in a facility that produces motor gasoline additives to enhance octane (currently producing MTBE). The Other operating segment primarily consists of fee-based marketing services.
Our management evaluates segment performance based on gross operating margin ("gross operating margin" or "margin"). Gross operating margin for each segment represents operating income before depreciation and amortization, lease expense obligations retained by EPCO, gains and losses on the sale of assets and selling, general
and administrative expenses. Segment gross operating margin is exclusive of interest expense, interest income amounts, dividend income, minority interest, extraordinary charges and other income and expense transactions.
We include equity earnings from unconsolidated affiliates in segment gross operating margin and as a component of revenues. Our equity investments with industry partners are a vital component of our business strategy and a means by which we conduct our operations to align our interests with a supplier of raw materials to a facility or a consumer of finished products from a facility. 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. For example, we use the Promix NGL fractionator to process NGLs extracted by our gas plants. The NGLs received from Promix then can be sold by our merchant businesses. Another example would be our relationship with the BEF MTBE facility. Our isomerization facilities process normal butane for this plant and our HSC pipeline transports MTBE for delivery to BEF's storage facility on the Houston Ship Channel.
Our gross operating margin by segment (in thousands of dollars) along with a reconciliation to consolidated operating income for the past three years were as follows:
Our significant plant production and other volumetric data for the last three years were as follows:
Year ended December 31, 2001 compared to year ended December 31, 2000
Revenues, costs and expenses and operating income. Fiscal 2001 was our best year ever as measured in terms of revenues, gross operating margin and operating income. Our revenues were a record $3.2 billion in 2001 compared to $3.1 billion in 2000. Operating costs and expenses increased to $2.9 billion in 2001 from $2.8 billion in 2000. Gross operating margin increased to $376.8 million in 2001 from $320.6 million in 2000. Operating income also
posted a record $287.2 million in 2001 versus $243.7 million in 2000. The increases in revenues and costs and expenses are primarily due to our natural gas pipeline acquisitions completed in 2001 (Acadian Gas and the Gulf of Mexico lines) offset by lower product prices in 2001 relative to 2000. The increase in gross operating margin and operating income is primarily attributable to acquisitions and new construction, plus a rise in income relating to commodity hedging activities offset by generally lower product prices.
Fractionation. Gross operating margin from our Fractionation segment decreased to $118.6 million in 2001 from $129.4 million in 2000. NGL fractionation margin for 2001 declined $21.0 million from 2000, primarily as the result of a $19.3 million decrease in "in-kind" fractionation fees at our Norco facility. An in- kind arrangement allows us to receive NGL volumes in lieu of cash fractionation fees (Norco being our only facility with this type of contract). The decline in NGL fractionation margin is related to the NGL volumes received during 2000 having a higher value than those received during 2001. Net volumes at the NGL fractionation facilities decreased to 204 MBPD in 2001 compared to 213 MBPD in 2000. The decrease in throughput is due to lower NGL extraction rates at gas processing facilities in early 2001 (due to the abnormally high cost of natural gas) versus 2000 when the industry was maximizing NGL production. The isomerization business posted an $8.4 million increase in margin for 2001 over 2000 on volumes of 80 MBPD. Isomerization margins were bolstered by increased demand during the second quarter of 2001 for services linked to refinery activities, primarily gasoline blending. Gross operating margin from propylene fractionation increased $0.3 million in 2001 over 2000 due to additional margins from BRPC which did not commence operations until July 2000. Net volumes at our propylene fractionation facilities declined slightly to 31 MBPD in 2001 from 33 MBPD in 2000.
Pipelines. Our Pipelines segment posted a record gross operating margin of $96.6 million in 2001, compared to $56.1 million in 2000. Of the $40.5 million increase in margin, $20.0 million is attributable to natural gas pipelines acquired in 2001 (i.e., Acadian Gas and the Gulf of Mexico systems). Acadian Gas added $11.8 million in margin with the Gulf of Mexico systems contributing $8.2 million. On a net basis, these pipeline systems transported an average of 1,349 BBtu/d of natural gas.
Net liquid transportation volumes increased to 454 MBPD in 2001 from 367 MBPD in 2000. The majority of this increase is attributable to a rise in commercial butane imports related to seasonal demand for isobutane production. This activity contributed to a $5.2 million combined increase in margin from our import terminal and HSC pipeline system. Additionally, margin from the Louisiana Pipeline System increased $1.1 million in 2001 due to increased demand for transportation services (with volumes increasing by 23 MBPD in 2001, a 20% increase year-to-year). Also, our recently completed Lou-Tex NGL pipeline added $12.2 million to margin during 2001 (construction of this system being completed in the fourth quarter of 2000). This pipeline benefited from the movement of mixed NGLs out of Louisiana to our Mont Belvieu processing facility during 2001.
Processing. Earnings from our Processing segment were a record $155.0 million in 2001, up 27% from $122.2 million in 2000. This segment is comprised of our natural gas processing business and related merchant activities. The increase in margin is primarily due to the positive impact of our commodity hedging activities.
2001 was a very challenging year for gas processors industry wide. The volatility of natural gas prices and the depressed nature of NGL prices throughout 2001 created an environment requiring processors to be proactive in meeting the needs of the marketplace. The unusually poor processing economics of the first quarter of 2001 (due to the abnormally high cost of energy relative to the value of our NGL production during that time) yielded to improved market conditions during the second half of 2001 as energy costs moderated. In general, prices received for our NGL production approximated a weighted-average of 43 cents per gallon in 2001 compared to 57 cents per gallon in 2000. In contrast, the cost of natural gas averaged $4.20 per MMBtu in 2001 (peaking at near $10 per MMBtu during the first quarter of 2001) versus $3.84 per MMBtu in 2000.
Equity NGL production averaged 63 MBPD in 2001 compared to 72 MBPD in 2000. The decline in volume is related to the 2000 period reflecting near maximized NGL recoveries supported by strong NGL economics. The 2001 equity NGL production rate reflects less favorable extraction economics (as described above) but is greatly improved relative to the first quarter of 2001's 46 MBPD when energy costs peaked. With the improvement in processing margins in late 2001, we posted a record equity NGL production of 80 MBPD during the fourth quarter of 2001.
We employ various hedging strategies to mitigate the effects of fluctuating commodity prices (primarily NGL and natural gas prices) on our gas processing business and related merchant activities. Margin for 2001 includes $101.3 million of income from commodity hedging activities, an increase of $74.5 million over such income in 2000. The loss in value of our NGL production has been mitigated (or in some cases, exceeded) by such income during 2001. Without this income, margin from gas processing would have declined $54.7 million year- to-year.
A large number of our commodity financial instruments are currently based on the historical relationship between natural gas prices and NGL prices. This type of hedging strategy utilizes the forward sale of natural gas at a fixed-price with the expected margin on the settlement of the position offsetting or mitigating changes in the anticipated margins on NGL merchant activities and the value of our equity NGL production. During 2001, we benefited from the general decline in natural gas prices relative to our fixed positions. The decline in natural gas prices allowed us to realize net cash gains on the settlement and closeout of certain positions of approximately $95.7 million. The $5.6 million difference between the realized amount and the $101.3 million in income from these financial instruments represents the non-cash mark-to-market income on positions open at December 31, 2001 (based on market prices at that date).
If natural gas prices had not declined to the degree seen during the year, we would have recognized less income (or potentially even a loss) on hedging activities offset somewhat by correlative higher NGL prices which would have increased the value of our NGL production. A variety of factors influence whether or not our hedging strategies are successful. For additional information regarding our commodity financial instruments, see Item 7A "Quantitative and Qualitative Disclosures about Market Risk" beginning on page 46.
We are exposed to settlement risk (a form of credit risk) with our counterparties to these financial instruments. On all transactions where we are exposed to settlement risk, management analyzes the counterparty's financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of these limits on an ongoing basis. In December 2001, Enron North America (the counterparty to some of our commodity financial instruments) filed for protection under Chapter 11 of the U.S. Bankruptcy Code. As a result, we recognized a charge to earnings of $10.6 million for all amounts owed to us by Enron. The Enron amounts were unsecured and the amount that we may ultimately recover, if any, is not presently determinable.
Our merchant activities benefited from (i) strong propane demand in the first quarter of 2001 for heating and (ii) isobutane in the second quarter of 2001 for refining. Overall, margin from merchant activities improved $9.9 million year- to-year. Processing margin also benefited from the reversal of $9.4 million in excess reserves associated with the gas processing plants.
Octane Enhancement. Equity earnings from our BEF investment declined $4.7 million year-to-year on stable net volumes of 5 MBPD in both periods. The decrease in earnings is primarily attributable to lower MTBE and by-product prices.
Other. Gross operating margin from our Other segment was $0.9 million in 2001 compared to $2.5 million in 2000. The decrease is primarily due to a rise in operating costs of plant support functions.
Selling, general and administrative expenses. These expenses increased to $30.8 million in 2001 from $28.3 million in 2000. The increase is primarily due to expenses related to the additional staff and resources deemed necessary to support our expansion activities resulting from acquisitions and other business development.
Interest expense. Interest expense for 2001 increased by $19.1 million over that for 2000 . The increase is primarily due to the issuance of our $450 million of public debt in January 2001 (the Senior Notes B, see page 41). The proceeds from this debt were used to acquire the Gulf of Mexico pipelines from El Paso, Acadian Gas from Shell and to finance internal growth and other general partnership purposes.
Interest expense for both 2001 and 2000 benefited from income attributable to interest rate hedging activity. During the last two years, we used interest rate swaps in order to effectively convert a portion of our fixed-rate debt into variable-rate debt. With the decline in variable interest rates over the last two years, our swaps provided income to offset fixed-rate-based interest expense. For 2001, we recognized a $13.2 million benefit related to these swaps compared with a $10.0 million benefit recorded in 2000.
During 2001, two of our three swaps that were outstanding at January 1, 2001 were terminated (closing instruments having a notional value of $100 million). One swap was terminated by a counterparty exercising its early termination option while the other counterparty negotiated an early closeout of its position. This left us with one swap outstanding at December 31, 2001 having a notional amount of $54 million. This swap has an early termination option that is exercisable in March 2003. For additional information regarding our exposure to interest rate risk, see page 49.
Year ended December 31, 2000 compared to year ended December 31, 1999
Revenues, costs and expenses and operating income. Our revenues increased to $3.1 billion in 2000 compared to $1.3 billion in 1999 while operating costs and expenses increased to $2.8 billion in 2000 versus $1.2 billion in 1999. Gross operating margin increased to $320.6 million in 2000 compared to $179.2 million in 1999 resulting in a year-to-year increase in operating income of $111.4 million to $243.7 million in 2000 from $132.3 million in 1999. The year-to-year increase in revenues, operating costs and expenses, gross operating margin and operating income is primarily attributable to the TNGL acquisition. The 1999 period includes five months of margins associated with TNGL operations (August through December) whereas the 2000 period includes twelve months.
Fractionation. The gross operating margin of our Fractionation segment increased to $129.4 million in 2000 from $110.4 million in 1999. The additional margin from the NGL fractionators acquired from Shell in the TNGL acquisition was the primary reason for a $29.7 million increase in NGL fractionation margin in 2000 over 1999. As noted previously, 1999 includes five months of margin from the TNGL assets whereas the 2000 period includes twelve months. Net NGL fractionation volume increased to 213 MBPD in 2000 from 184 MBPD in 1999. The increase in net NGL fractionation volume is attributable to higher production rates at our Mont Belvieu NGL fractionator. Our ownership in this facility increased to 62.5% from 37.5% as a result of the July 1999 MBA acquisition.
For 2000, gross operating margin from our isomerization business decreased $7.8 million compared to 1999 primarily due to higher fuel and other operating costs, plus the expenses related to the refurbishment of an isomerization unit. Isomerization volumes were 74 MBPD in both 2000 and 1999. Gross operating margin from propylene fractionation decreased $1.4 million in 2000 from 1999 levels primarily due to higher energy costs. Net volumes at these facilities improved to 33 MBPD in 2000 from 28 MBPD in 1999 due to the startup of the BRPC propylene concentrator in July 2000.
Pipelines. Gross operating margin from our Pipelines segment was $56.1 million in 2000 compared to $31.2 million in 1999. Overall liquids volumes increased to 367 MBPD in 2000 from 264 MBPD in 1999. Generally, the $24.9 million increase in margin is attributable to the additional volumes and margins contributed by the TNGL pipeline and storage assets, higher margins from the HSC pipeline system and EPIK due to an increase in export volumes, the margins from the Lou-Tex propylene pipeline that was purchased in March 2000 and margins from the Lou-Tex NGL pipeline which commenced operations in late November 2000. The growth in export volumes is attributable to the installation of EPIK's new chiller unit that began operations in the fourth quarter of 1999.
On February 25, 2000, the purchase of the Lou-Tex propylene pipeline and related assets from Shell was completed at a cost of approximately $99.5 million. Construction of the Lou-Tex NGL pipeline was completed during the fourth quarter of 2000 at a cost of approximately $87.9 million.
Processing. Our Processing segment generated $122.2 million in gross operating margin during 2000 compared to $28.5 million in 1999. The $93.7 million increase is primarily due to 2000 including twelve months of gas processing (and related merchant activity) margins from the TNGL businesses; whereas 1999 includes only five months. This segment benefited from a stronger NGL pricing environment in 2000 versus 1999 and a rise in equity NGL production from 67 MBPD in 1999 to 72 MBPD in 2000.
Octane Enhancement. Gross operating margin from our Octane Enhancement segment increased to $10.4 million in 2000 from $8.2 million in 1999. This segment consists entirely of our investment in BEF, a joint venture facility that currently produces MTBE. Equity earnings for 2000 improved over 1999 levels primarily due to higher than normal MTBE market prices during the second and third quarters of 2000 and lower debt service costs (BEF made its final note payment in May 2000 and, as a result, now owns the facility debt-free). In addition, the 1999 period
reflects a $1.5 million non-cash charge related to the write-off of certain start-up expenses. MTBE production, on a net basis, was 5 MBPD in both 2000 and 1999.
Other. Gross operating margin from our Other segment was $2.5 million in 2000 compared to $0.9 million in 1999. The increase is primarily due to fee-based marketing services added in the fourth quarter of 1999.
Selling, general and administrative expenses. These expenses increased to $28.3 million in 2000 from $12.5 million in 1999. The increase is primarily due to expenses related to the additional staff and resources deemed necessary to support our expansion activities resulting from acquisitions and other business development.
Interest expense. Interest expense increased to $33.3 million in 2000 from $16.4 million in 1999. The increase is attributable to a rise in average debt levels from $213 million in 1999 to $408 million in 2000. Debt levels have increased over the previous year primarily due to capital expenditures for assets such as the Lou-Tex propylene and Lou-Tex NGL pipelines and the issuance of $404 million in debt instruments (the Senior Notes A and MBFC Loan) in March 2001. Interest expense for 2000 includes a $10.0 million benefit related to interest rate swaps.
OUR LIQUIDITY AND CAPITAL RESOURCES
General. Our primary cash requirements, in addition to normal operating expenses and debt service, are for capital expenditures (both sustaining and expansion- related), business acquisitions and distributions to partners. We expect to fund our short-term needs for such items as operating expenses, sustaining capital expenditures and quarterly distributions to partners with operating cash flows. Capital expenditures for long-term needs resulting from internal growth projects and business acquisitions are expected to be funded by a variety of sources including (either separately or in combination) cash flows from operating activities, borrowings under bank credit facilities, the issuance of additional public debt and/or cash contributions from the Limited Partner in connection with sales of its equity securities. Our debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements.
Operating cash flows primarily reflect the effects of net income adjusted for depreciation and amortization, equity income and cash distributions from unconsolidated affiliates, fluctuations in fair values of financial instruments and changes in operating accounts. The net effect of changes in operating accounts is generally the result of timing of sales and purchases near the end of each period. Cash flows from operations are directly linked to earnings from our business activities. Like our results of operations, these cash flows are exposed to certain risks including fluctuations in NGL and energy prices, competitive practices in the midstream energy industry and the impact of operational and systems risks. The products that we process, sell or transport are principally used as feedstocks in petrochemical manufacturing and in the production of motor gasoline and as fuel for residential and commercial heating. Reduced demand for our products or services by industrial customers, whether because of general economic conditions, reduced demand for the end products made with NGL products, increased competition from petroleum-based products due to pricing differences or other reasons, could have a negative impact on earnings and thus the availability of cash from operating activities. For a more complete discussion of these and other risk factors pertinent to our businesses, see page 1.
As noted above, certain of our liquidity and capital resource requirements are met using borrowings under bank credit facilities, the issuance of additional public debt and cash contributions from our Limited Partner in connection with sales of its equity securities (separately or in combination). As of December 31, 2001, availability under our revolving credit facilities was $400 million (which may be increased by an additional $100 million under certain conditions). We issued $450 million of public debt in January 2001 (the "Senior Notes B") using the remaining availability under the December 1999 $800 million universal shelf registration. The proceeds of this offering were used to acquire Acadian Gas and the Gulf of Mexico natural gas pipeline systems, to finance the cost to construct certain NGL pipelines and related projects and for working capital and other general partnership purposes. On February 23, 2001, we filed a $500 million universal shelf registration (the "February 2001 Shelf") covering the issuance of an unspecified amount of equity securities of the Limited Partner and public debt of the Company or a combination thereof. For additional information regarding our debt, see the section below labeled "Long-term debt."
In June 2000, our Limited Partner received approval from its equity security holders to increase by 25.0 million the number of common equity interests (or "Common Units") available and unreserved for general partnership purposes during its Subordination Period. The Subordination Period (as defined in the Limited Partner's partnership agreement) is forecasted to extend through the second quarter of 2003, provided that certain financial tests continue to be met. The 25.0 million increase has improved the financial flexibility of the Limited Partner to contribute cash and/or other assets to us in connection with any potential expansion project or business acquisition. After taking into account the Common Units issued in connection with TNGL acquisition, approximately 27.3 million Common Units are available (and unreserved) on a pre-split basis (see "Two-for-one split of Limited Partner Units" below) for general partnership purposes during the Subordination Period. After this period expires, the Limited Partner may prudently issue an unlimited number of Common Units for general partnership purposes.
If deemed necessary, we believe that additional financing arrangements can be obtained at reasonable terms. Furthermore, we believe that maintenance of our investment grade credit ratings combined with a continued ready access to debt capital at reasonable rates (including our Limited Partner's access to equity capital) plus sufficient trade credit to operate our businesses efficiently provide a solid foundation to meet our long and short-term liquidity and capital resource requirements.
Credit ratings. Our current investment grade credit ratings of Baa2 by Moody's Investor Service and BBB by Standard and Poors highlight our financial flexibility. The outlook for both of the ratings is stable. We maintain regular communications with these rating agencies which independently judge our creditworthiness based on a variety of quantitative and qualitative factors. In May 2001, Moody's upgraded their rating of us from Baa3 to Baa2. They cited that our operating capabilities and growth opportunities had been significantly enhanced by the acquisition of Acadian Gas and the purchase of equity interests in four Gulf of Mexico natural gas pipeline systems. We believe that the maintenance of an investment grade credit rating is important in managing our liquidity and capital resource requirements.
Two-for-one split of Limited Partner Units. On February 27, 2002, the Limited Partners announced that the Board of Directors of the General Partner had approved a two-for-one split for each class of its Units. The partnership Unit split will be accomplished by distributing one additional partnership Unit for each partnership Unit outstanding to holders of record on April 30, 2002. The Units will be distributed on May 15, 2002. All references to the number of Limited Partner Units contained in this document relate to the pre-split Units, except if indicated otherwise.
Consolidated cash flows for year ended December 31, 2001 compared to year ended December 31, 2000
Operating cash flows. Cash flows from operating activities were $286.1 million in 2001 versus $358.9 million in 2000. After adjusting for changes in operating accounts which are generally the result of timing of sales and purchases near the end of each period, adjusted cash flow from operating activities would be $320.8 million in 2001 as compared to $290.3 million in 2000. Cash flow from operating activities before changes in operating accounts is an important measure of our liquidity. It provides an indication of our success in generating core cash flows from the assets and investments that we own. The $30.5 million increase for 2001 is attributable to our strong earnings as discussed earlier under "Our results of operations - Year ended December 31, 2001 compared to year ended December 31, 2000."
Investing cash flows. During 2001, we used $491.2 million of cash to finance investing activities compared to $268.8 million in 2000. Over the last two years, we have funded $384.3 million in internal growth projects. Of this amount, $336.2 million in capital expenditures has been devoted to various pipeline projects including $99.5 million spent to purchase the Lou-Tex Propylene pipeline (2000), $90.5 million to construct the Lou-Tex NGL pipeline ($83.7 million spent in 2000 with the remainder spent in 2001) and $64.1 million in expansion activities related to our Louisiana Pipeline System (2001). We spent $9.5 million on sustaining capital expenditures during the last two years with $6.0 million in such charges recorded during 2001.
Our investing cash outflows for 2001 include the $225.7 million paid to acquire Acadian Gas from Shell. This amount is subject to certain post-closing adjustments expected to be completed during the first half of 2002. In addition, our investments in and advances to unconsolidated affiliates increased $84.7 million in 2001 due to the $112.0 million paid to purchase equity interests in several Gulf of Mexico natural gas pipeline systems from El Paso.
Financing cash flows. Our financing activities generated $278.7 million of cash receipts during 2001 compared to cash payments of $36.8 million in 2000. Cash flows from financing activities are primarily affected by repayments of debt, borrowings under debt agreements and distributions to partners. Cash flow from financing activities in 2001 includes proceeds from the $450 million Senior Notes B issued in January 2001 whereas the 2000 period includes proceeds from the $350 million Senior Notes A and $54 million MBFC loan and the associated repayments on various bank credit facilities.
Cash distributions to partners and the minority interest increased to $167.1 million in 2001 from $141.6 million in 2000. We distribute cash to our Limited and General Partner to fund their subsequent distributions, with the Limited Partner's requirements primarily dictating the amount of our distributions. The Limited Partner's distribution requirements increased during 2001 as a result of (i) increases in their quarterly cash distribution rate per eligible Unit and (ii) an increase in the number of Common Units eligible for distributions. The increase in number of the Limited Partner's Common Units eligible for distributions is due to the conversion of 5.0 million of Shell's Special Units into Common Units in August 2001. Of the 14.5 million Special Units remaining at December 31, 2001 (on a pre-split basis), 9.5 million are scheduled to convert into Common Units in August 2002 with the balance of 5.0 million converting into Common Units in August 2003 (all on a one-for-one basis).
Our cash distribution policy (as managed by the General Partner at its sole discretion) has allowed us to retain a significant amount of cash flow for reinvestment in the growth of the business. Over the last two years, we have retained approximately $275.0 million to fund expansions and business acquisitions. We believe that our cash distribution policy provides the partnership with financial flexibility in executing its growth strategy.
In July 2000, the General Partner instituted a two-year buy-back program (the "Buy Back Program") that would allow Enterprise Products Partners L.P. ("EPPLP", on a stand-alone basis) to repurchase and retire up to 1.0 million of its publicly-owned Common Units. EPPLP's intent under the Buy Back Program is to reacquire Common Units during periods of temporary market weakness at price levels that would be accretive to its remaining Unitholders. Under this original program, EPPLP repurchased and retired 28,400 Common Units during 2000 at a cost of $0.8 million.
During the first quarter of 1999, we established a revocable grantor trust, EPOLP 1999 Grantor Trust or the "1999 Trust", to fund potential future obligations under the EPCO Agreement with respect to EPCO's long-term incentive plan (through the exercise of options granted to EPCO employees or directors of the General Partner). At December 31, 2001, the 1999 Trust owned 163,600 Common Units (the "Trust Units") which are accounted for in a manner similar to treasury stock under the cost method of accounting. The Trust Units are considered outstanding and receive distributions.
In September 2001, the General Partner modified the Buy Back Program to allow both EPPLP and the 1999 Trust to repurchase Common Units. Under the modified terms of the program, purchases made by EPPLP will be retired whereas the Units purchased by the 1999 Trust will remain outstanding and not be retired. At December 31, 2001, 575,200 additional publicly-owned Common Units (on a pre- split basis) could be repurchased under the Buy Back Program by EPPLP and/or the 1999 Trust.
Purchases made under this program by EPPLP will be funded by special cash distributions from us whereas purchases made by the 1999 Trust will be funded by our operating cash flows or borrowings or a combination thereof. These purchases are to be balanced with our plans to grow the Company through investments in internally-developed projects and acquisitions, while maintaining an investment grade debt rating. The 1999 Trust purchased 396,400 Common Units under this program during 2001 at a cost of $18.0 million. The 1999 Trust subsequently reissued 500,000 treasury units for proceeds of $22.6 million. For additional information regarding the 1999 Trust, see Note 7 of the Notes to Consolidated Financial Statements.
At December 31, 2001, we had $5.8 million in restricted cash required by the NYMEX commodity exchange to facilitate financial instrument and physical purchase transactions. This amount can fluctuate over time depending on the physical volumes underlying the contracts, market price of the commodity and type of transactions executed. During 2001, our restricted cash balance required by the exchange varied, reaching a peak of $13.4 million in July.
Consolidated cash flows for year ended December 31, 2000 compared to year ended December 31, 1999
Operating cash flows. Cash flows from operating activities were $358.9 million in 2000 compared to $178.0 million in 1999. After adjusting for changes in operating accounts which are generally the result of timing of sales and purchases near the end of each period, adjusted cash flow from operating activities increased $139.8 million to $290.3 million in 2000 compared to $150.5 million in 1999. The $139.8 million increase in adjusted cash flow from operating activities between periods is primarily due to the impact of the TNGL acquisition as discussed earlier under "Our results of operations - Year ended December 31, 2000 compared to year ended December 31, 1999."
Investing cash flows. We invested $268.8 million during 2000 (primarily in internal growth projects) compared to $271.2 million spent during 1999 (primarily for acquisitions). Fiscal 1999 reflects $208.1 million in net cash payments resulting from the TNGL and MBA acquisitions. Our capital expenditures increased substantially in 2000 over 1999 primarily due to the purchase of the Lou-Tex Propylene pipeline ($99.5 million) and construction costs related to the Lou-Tex NGL pipeline ($83.7 million).
Investments in and advances to unconsolidated affiliates during 1999 include our share of costs ($38.2 million) to complete construction and commence operations of the BRF facility and Wilprise and Tri-States pipelines. Our 2000 expenditures include $19.4 million paid to purchase an additional 8.4% interest in Dixie. The 1999 and 2000 amounts also include a combined $26.2 million in costs to construct the BRPC facility, which was completed in July 2000.
Financing cash flows. Our financing activities resulted in net cash payments of $36.8 million in 2000 versus net cash receipts of $74.2 million in 1999. Fiscal 2000 includes proceeds from the issuance of Senior Notes A and the MBFC Loan and the associated repayments on various bank credit facilities. Financing activities in 1999 include the borrowings under bank credit facilities to finance the TNGL and MBA acquisitions and $4.7 million paid by the Trust to repurchase (and treat as Treasury Units) 267,200 of our Limited Partner's publicly-traded Common Units. Distributions to partners and the minority interest increased to $141.6 million in 2000 compared to $113.0 million in 1999 primarily due to increases in the quarterly distribution rate. Lastly, EPPLP repurchased and retired 28,400 Common Units during 2000 under its Buy-Back Program at a cost of $0.8 million.
Cash requirements for future growth
We are committed to the long-term growth and viability of the Company. Our strategy involves expansion through business acquisitions and internal growth projects. In recent years, major oil and gas companies have sold non-strategic assets in the midstream natural gas industry in which we operate. We forecast that this trend will continue, and expect independent oil and natural gas companies to consider similar disposal options. Management continues to analyze potential acquisitions, joint venture or similar transactions with businesses that operate in complementary markets and geographic regions. We believe that the Company is well positioned to continue to grow through acquisitions that will expand its platform of assets and through internal growth projects. Our goal for fiscal 2002 is to invest at least $400 million in such opportunities that will be accretive to our investors.
The funds needed to achieve this goal can be attained through a combination of operating cash flows, debt or equity. During January and February 2002, we spent approximately $367.5 million to acquire hydrocarbon storage and propylene fractionation facilities and related assets from D-K. Of this amount, approximately $238.5 million was funded by a drawdown on our Multi-Year and 364- Day credit facilities leaving $161.5 million of unused commitments available under these credit agreements. The increase in outstanding debt will translate into additional debt service costs during 2002.
Another stated goal of management is to increase our cash distributions. As noted earlier, we distribute cash to our Limited and General Partner to fund their subsequent distributions, with the Limited Partner's requirements primarily dictating the amount of our distributions. Our Limited Partner has a goal of increasing the distribution rate to its limited partners by at least 10% annually. At the end of 2001, their annual rate was $2.50 per Common Unit. We forecast that operating cash flows will be sufficient in 2002 to increase distributions sufficiently to allow the Limited Partner to achieve a rate of at least $2.75 per Common Unit (on a pre-split basis). On February 27, 2002, the Limited Partner announced an increase in the quarterly distribution from $0.625 per Common Unit to $0.67 per Common Unit on a pre-split basis. Based on the number of Limited Partner distribution-bearing Units projected to
be outstanding during 2002, we project that this goal will translate into cash distributions increasing by approximately $50 million over the amounts paid to partners and the minority interest during 2001.
The number of Limited Partner distribution-bearing Units will increase by 9.5 million in August 2002 and 5.0 million in August 2003 as a result of its agreements with Shell. The 2002 increase will affect our distributions to the Limited Partner beginning in third quarter of 2002.
Future capital expenditures. During 2002, we forecast that approximately $79.3 million will be spent on expansion capital projects, of which $64.5 million is related to our Pipelines segment. In addition, we expect to spend $6.0 million on sustaining capital expenditures. We generally classify improvements and major renewals of existing assets as sustaining capital expenditures and all other capital spending on existing and new assets referred to as expansion capital expenditures. Both expansion and sustaining capital expenditures are recorded as cash outlays for property, plant and equipment. Maintenance, repairs and minor renewals are charged to operations as incurred. Our unconsolidated affiliates forecast a combined $62.2 million in capital expenditures during 2002 of which we will fund approximately $20.8 million.
The following table shows our projected capital spending by operating segment for 2002 (in thousands of dollars):
At December 31, 2001, we had $5.3 million in outstanding purchase commitments attributable to capital projects. Of this amount, $5.0 million is related to the construction of assets that will be recorded as property, plant and equipment and $0.3 million is associated with capital projects of our unconsolidated affiliates which will be recorded as additional investments.
New environmental regulations in the state of Texas may necessitate extensive redesign and modification of the our Mont Belvieu facilities to achieve the air emissions reductions needed for federal Clean Air Act compliance in the Houston- Galveston, Texas area. The technical practicality and economic reasonableness of these regulations have been challenged under state law in litigation filed on January 19, 2001, against the Texas Natural Resource Conservation Commission and its principal officials in the District Court of Travis County, Texas, by a coalition of major Houston-Galveston area industries including the Company. Until this litigation is resolved, the precise level of technology to be employed and the cost for modifying the facilities to achieve the required amount of reductions cannot be determined. Currently, the litigation has been stayed by agreement of the parties pending the outcome of expanded, cooperative scientific research to more precisely define sources and mechanisms of air pollution in the Houston-Galveston area. Completion of this research and formulation of the regulatory response are anticipated in mid-2002. Regardless of the results of this research and the outcome of the litigation, expenditures for air emissions reduction projects will be spread over several years, and we believe that adequate liquidity and capital resources will exist for us to undertake them. We have budgeted capital funds in 2002 to begin making modifications to certain Mont Belvieu facilities that will result in air emission reductions. The methods employed to achieve these reductions will be compatible with whatever regulatory requirements are eventually put in place. For additional information regarding the impact of the Clean Air Act on our operations, see page 22 of this report on Form 10-K.
Long-term debt
Our long-term debt consisted of the following at:
Long-term debt does not reflect the $250 million Multi-Year Credit Facility or the $150 million 364-Day Credit Facility. No amount was outstanding under either of these two revolving credit facilities at December 31, 2001. See below for a complete description of these facilities.
At December 31, 2001, we had a total of $75 million of standby letters of credit capacity under our Multi-Year Credit Facility of which $2.4 million was outstanding.
EPPLP, on a stand-alone basis, acts as guarantor of certain of our debt obligations. This parent-subsidiary guaranty provision exists under our Senior Notes, MBFC Loan and two current revolving credit facilities.
Senior Notes A. On March 13, 2000, we completed a public offering of $350 million in principal amount of 8.25% fixed-rate Senior Notes due March 15, 2005 at a price to the public of 99.948% per Senior Note (the "Senior Notes A"). These notes were issued to retire certain revolving credit loan balances that were created as a result of the TNGL acquisition and other general partnership activities.
The Senior Notes A are subject to a make-whole redemption right. The notes are an unsecured obligation and rank equally with existing and future unsecured and unsubordinated indebtedness and senior to any future subordinated indebtedness. The notes are guaranteed by EPPLP through an unsecured and unsubordinated guarantee and were issued under an indenture containing certain restrictive covenants. These covenants restrict our ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions. We were in compliance with these restrictive covenants at December 31, 2001.
Senior Notes B. On January 24, 2001, we completed a public offering of $450 million in principal amount of 7.50% fixed-rate Senior Notes due February 1, 2011 at a price to the public of 99.937% per Senior Note (the "Senior Notes B"). These notes were issued to finance the acquisition of Acadian Gas, Neptune, Nemo and Starfish; to cover construction costs of certain NGL pipelines and related projects; and to fund other general partnership activities.
The Senior Notes B were issued under the same indenture as Senior Notes A and therefore are subject to similar terms and restrictive covenants. The Senior Notes B are guaranteed by EPPLP through an unsecured and unsubordinated guarantee. We were in compliance with the restrictive covenants at December 31, 2001.
MBFC Loan. On March 27, 2000, we executed a $54 million loan agreement with the Mississippi Business Finance Corporation ("MBFC") having a 8.70% fixed-rate and a maturity date of March 1, 2010. In general, the
proceeds from this loan were used to retire certain revolving credit loan balances attributable to acquiring and constructing the Pascagoula, Mississippi natural gas processing facility.
The MBFC Loan is subject to a make-whole redemption right and is guaranteed by EPPLP through an unsecured and unsubordinated guarantee. The indenture agreement contains an acceleration clause whereby the outstanding principal and interest on the loan may become due and payable if our credit ratings decline below a Baa3 rating by Moody's (currently Baa2) and below a BBB- rating by Standard and Poors (currently BBB). Under these circumstances, the trustee (as defined in the indenture agreement) may, and if requested to do so by holders of at least 25% in aggregate of the principal amount of the outstanding underlying bonds, shall accelerate the maturity of the MBFC Loan, whereby the principal and all accrued interest would become immediately due and payable. If such an event occurred, we would have the option (a) to redeem the MBFC loan or (b) to provide an alternate credit agreement (as defined in the indenture agreement) to support our obligation under the MBFC loan, with both options exercisable within 120 days of receiving notice of the decline in our credit ratings from the ratings agencies.
The loan agreement contains certain covenants including maintaining appropriate levels of insurance on the Pascagoula facility and restrictions regarding mergers. We were in compliance with the restrictive covenants at December 31, 2001.
Multi-Year Credit Facility. On November 17, 2000, we entered into a $250 million five-year revolving credit facility that includes a sublimit of $75 million for letters of credit. The November 17, 2005 maturity date may be extended for one year at our option with the consent of the lenders, subject to the extension provisions in the agreement. We can increase the amount borrowed under this facility, with the consent of the Administrative Agent (whose consent may not be unreasonably withheld), up to an amount not exceeding $350 million by adding to the facility one or more new lenders and/or increasing the commitments of existing lenders, so long as the aggregate amount of the funds borrowed under this credit facility and the 364-Day Credit Facility (described below) does not exceed $500 million. No lender will be required to increase its original commitment, unless it agrees to do so at its sole discretion. This credit facility is guaranteed by EPPLP through an unsecured guarantee.
Proceeds from this credit facility will be used for working capital, acquisitions and other general partnership purposes. No borrowing was outstanding for this credit facility at December 31, 2001. In February 2002, we borrowed $200 million under this facility to complete our purchase of D-K's Mont Belvieu, Texas propylene fractionation assets.
Our obligations under this bank credit facility are unsecured general obligations and are non-recourse to the General Partner. As defined within the agreement, borrowings under this bank credit facility will generally bear interest at either (i) the greater of the Prime Rate or the Federal Funds Effective Rate plus one-half percent or (ii) a Eurodollar Rate plus an applicable margin or (iii) a Competitive Bid Rate. We elect the basis for the interest rate at the time of each borrowing.
Our credit agreement contains various affirmative and negative covenants to, among other things, (i) incur certain indebtedness, (ii) grant certain liens, (iii) enter into certain merger or consolidation transactions and (iv) make certain investments. In addition, we may not directly or indirectly make any distribution in respect of our partnership interests, except those payments in connection with the Buy-Back Program (not to exceed $30 million in the aggregate, see Note 7) and distributions from Available Cash from Operating Surplus, both as defined within the agreement.
The credit agreement also requires that we satisfy certain financial covenants at the end of each fiscal quarter. As defined within the agreement, we (i) must maintain Consolidated Net Worth of $750 million and (ii) not permit our ratio of Consolidated Indebtedness to Consolidated EBITDA, including pro forma adjustments (as defined within the agreement), for the previous four quarter period to exceed 4.0 to 1.0. If we fail to maintain these financial covenants, either the unused commitments under this facility will terminate or the outstanding principal balance (in whole or part at the discretion of the lenders) will be immediately payable or both. Since these ratios are dependent to a varying degree upon earnings, any sustained decline in our profitability would have a negative impact on these calculations. The Company was in compliance with the restrictive covenants at December 31, 2001.
364-Day Credit Facility. In conjunction with the Multi-Year Credit Agreement, we entered into a 364-day $150 million revolving bank credit facility. In November 2001, we and our lenders amended the revolving credit agreement to extend the maturity date to November 15, 2002 with an option to convert any revolving credit balance outstanding at November 15, 2002 to a one-year term loan.
We can increase the amount borrowed under this facility, with the consent of the Administrative Agent (whose consent may not be unreasonably withheld), up to an amount not exceeding $250 million by adding to the facility one or more new lenders and/or increasing the commitments of existing lenders, so long as the aggregate amount of the funds borrowed under this credit facility and the Multi- Year Credit Facility do not exceed $500 million. No lender will be required to increase its original commitment, unless it agrees to do so at its sole discretion. This credit facility is guaranteed by EPPLP through an unsecured guarantee. No borrowing was outstanding for this credit facility at December 31, 2001. In February 2002, we borrowed approximately $38.5 million under this facility to complete our purchase of D-K's Mont Belvieu, Texas propylene fractionation assets.
Our obligations under this bank credit facility are unsecured general obligations and are non-recourse to the General Partner. As defined within the agreement, borrowings under this bank credit facility will generally bear interest at either (i) the greater of the Prime Rate or the Federal Funds Effective Rate plus one-half percent or (ii) a Eurodollar Rate plus an applicable margin or (iii) a Competitive Bid Rate. We elect the basis for the interest rate at the time of each borrowing.
Proceeds from this credit facility will be used for working capital, acquisitions and other general partnership purposes. No amount was outstanding for this credit facility at December 31, 2001.
Limitations on certain actions by the Company and financial condition covenants of this bank credit facility are substantially consistent with those existing for the Multi-Year Credit Facility as described previously. We were in compliance with the restrictive covenants at December 31, 2001.
February 2001 Shelf
On February 23, 2001, we filed a $500 million universal shelf registration (the "February 2001 Shelf") covering the issuance of an unspecified amount of equity securities of the Limited Partner and public debt of the Company or a combination thereof. We expect to use the net proceeds from any sale of securities for future business acquisitions and other general corporate purposes, such as working capital, investments in subsidiaries, the retirement of existing debt and/or the repurchase of Common Units or other securities. The exact amounts to be used and when the net proceeds will be applied to partnership purposes will depend on a number of factors, including our funding requirements and the availability of alternative funding sources. We routinely review acquisition opportunities.
For additional information regarding our debt, see Note 6 of the Notes to Consolidated Financial Statements beginning on page of this report on Form 10-K.
SUMMARY OF CONTRACTUAL OBLIGATIONS AND MATERIAL COMMERCIAL COMMITMENTS
The following table summarizes our contractual obligations and material purchase and other commitments for the periods shown (as of December 31, 2001):
Long-term debt. Long-term debt includes our obligations under Senior Notes A and B and the MBFC Loan.
Operating leases. We lease certain equipment and processing facilities under noncancelable and cancelable operating leases. The amounts shown in the table represent minimum future rental payments due on such leases with terms in excess of one year.
The operating lease commitments shown above exclude the expense associated with various equipment leases contributed to us by EPCO at our formation for which EPCO has retained the liability. During 2001, 2000 and 1999, our non-cash lease expense associated with these EPCO "retained" leases was $10.4 million, $10.6 million and $10.6 million, respectively. Lease and rental expense (including Retained Leases) included in operating income for the years ended December 31, 2001, 2000 and 1999 was approximately $23.4 million, $21.2 million and $20.6 million. EPCO has assigned us the purchase options associated with the retained leases. Should we decide to exercise our purchase options under the retained leases, up to $26.0 million will be payable in 2004, $3.4 million in 2008 and $3.1 million in 2016.
Capital spending. We have capital spending commitments attributable to various capital projects. Of this amount, $5.0 million is related to the construction of assets that will be recorded as property, plant and equipment and $0.3 million is associated with capital projects of our unconsolidated affiliates which will be recorded as additional investments.
NGL and natural gas purchase commitments. In addition, we have long-term purchase commitments for NGL products and related-streams (including natural gas) with several suppliers. The purchase prices contained within these contracts approximate market value at the time of delivery. Our purchase commitments for NGLs are stated in thousands of barrels and for natural gas in BBtus.
For additional information regarding our commitments, please see Note 9 of the Notes to Consolidated Financial Statements.
IMPACT OF RECENT ACCOUNTING DEVELOPMENTS
In June 2001, the FASB issued two new pronouncements: SFAS No. 141, "Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS No. 141 prohibits the use of the pooling-of-interest method for business combinations initiated after June 30, 2001 and also applies to all business combinations accounted for by the purchase method that are completed after June 30, 2001. There are also transition provisions that apply to business combinations completed before July 1, 2001, that were accounted for by the purchase method. SFAS No. 142 became effective January 1, 2002 for all goodwill and other intangible assets recognized in our consolidated balance sheet at that date, regardless of when those assets were initially recognized. We adopted SFAS No. 141 on January 1, 2002.
Within six months of our adoption of SFAS No. 142 (by June 30, 2002), we will have completed a transitional impairment review to identify if there is an impairment to the December 31, 2001 recorded goodwill or intangible assets of indefinite life using a fair value methodology. Professionals in the business valuation industry will be consulted to validate the assumptions used in such methodologies. Any impairment loss resulting from the transitional impairment test will be recorded as a cumulative effect of a change in accounting principle for the quarter ended June 30, 2002. Subsequent impairment losses will be reflected in operating income in the Statements of Consolidated Operations.
At January 1, 2002, our intangible assets included the values assigned to the 20-year Shell natural gas processing agreement (the "Shell agreement") and the excess cost of the purchase price over the fair market value of the assets acquired from Mont Belvieu Associates (the "MBA excess cost"), both of which were initially recorded in 1999. The value of the Shell agreement ($194.4 million net book value at December 31, 2001) is being amortized on a straight- line basis over its contract term. Likewise, the MBA excess cost ($7.9 million net book value at December 31, 2001) was being amortized on a straight-line basis over 20 years. Based upon initial interpretations of the new accounting standards, we anticipate that the intangible asset related to the Shell agreement will continue to be amortized over its contract term ($11.1 million annually for 2002 through July 2019); however, the MBA excess cost will be reclassified to goodwill in accordance with the new standard and its amortization will cease (currently, $0.5 million annually). This goodwill would then be subject to impairment testing as prescribed in SFAS No. 142. We are continuing to evaluate the comprehensive provisions of SFAS No. 142 and will fully adopt the standard during 2002 within the prescribed time periods.
In addition to SFAS No. 141 and No. 142, the FASB also issued SFAS No. 143, "Accounting for Asset Retirement Obligations", in June 2001. This statement establishes accounting standards for the recognition and measurement of a liability for an asset retirement obligation and the associated asset retirement cost. This statement is effective for our fiscal year beginning January 1, 2003. We are continuing to evaluate the provisions of this statement. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets". This statement addresses financial accounting and reporting for the impairment and/or disposal of long-lived assets. We adopted this statement effective January 1, 2002 and determined that it will have no material impact on our financial statements as of that date.
UNCERTAINTIES REGARDING OUR INVESTMENT IN BEF
We have a 33.3% ownership interest in BEF, which owns a facility currently producing MTBE. The production of MTBE is driven by oxygenated fuels programs enacted under the federal Clean Air Act Amendments of 1990 and other legislation. Any change to these programs that enable localities to elect to not participate in these programs, lessen the requirements for oxygenates or favor the use of non-isobutane based oxygenated fuels would reduce the demand for MTBE. In 1999, the Governor of California ordered the phase-out of MTBE in California by the end of
2002 due to allegations by several public advocacy and protest groups that MTBE contaminates water supplies, causes health problems and has not been as beneficial in reducing air pollution as originally contemplated. Subsequently, the EPA denied California's request for a waiver of the oxygenate requirement and the state is now reconsidering the timing of its MTBE ban.
Legislation introduced in the U.S. Senate would eliminate the Clean Air Act's oxygenate requirement in order to foster the elimination of MTBE in fuel by individual states such as California. Legislation introduced in the U.S. House to prevent states from banning MTBE was defeated in 2001. No assurance can be given as to whether the federal government or individual states will ultimately adopt legislation banning or promoting the use of MTBE as part of their clean air programs.
In light of these regulatory developments, the owners of BEF have been formulating a contingency plan for use of the BEF facility if MTBE were banned or significantly curtailed. Management is exploring a possible conversion of the BEF facility from MTBE production to alkylate production. We believe that if MTBE usage is banned or significantly curtailed, the motor gasoline industry would need a substitute additive to maintain octane levels in motor gasoline and that alkylate would be an attractive substitute. Depending upon the type of alkylate process chosen and the level of alkylate production desired, the cost to convert the facility from MTBE production to alkylate production would range from $20 million to $90 million, with our share of these costs ranging from $6.7 million to $30 million.
AMORTIZATION OF SHELL PROCESSING AGREEMENT TO INCREASE
On or about June 30, 2001, Shell met certain year 2001 performance criteria for the issuance of the last installment of 3.0 million non-distribution bearing, convertible contingency Units of the Limited Partner (referred to as Special Units when issued). Under a contingent unit agreement with Shell executed as part of the 1999 TNGL acquisition, the Limited Partner issued these Special Units on August 2, 2001. The value of these Special Units was determined to be $117.1 million using present value techniques. The value of these Special Units increased the purchase price of the TNGL acquisition by $117.1 million to a final amount of approximately $529 million, with the increase allocated to the Shell Processing Agreement (an intangible asset).
The $117 million value of the Special Units was recorded as an equity contribution to us by the Limited Partner. As a result, the General Partner contributed $1.2 million to maintain its relative ownership percentage. The increase in value of the Shell Processing Agreement will be amortized over the remaining life of the contract. As a result, amortization expense will increase by approximately $6.5 million annually.
RESPONSE TO SEPTEMBER 11, 2001 TERRORIST ATTACKS
Following the recent terrorist attacks in the United States, we instituted a review of security measures and practices and emergency response capabilities for all facilities and sensitive infrastructure. In connection with this activity, we participated in security coordination efforts with law enforcement and public safety authorities, industry mutual-aid groups and regulatory agencies. As a result of these steps, we believe that security measures, techniques and equipment have been enhanced as appropriate on a location-by- location basis. Further evaluation will be ongoing, with additional measures to be taken as specific governmental alerts, additional information about improving security and new facts come to our attention.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
We are exposed to financial market risks, including changes in commodity prices in our natural gas and NGL businesses and in interest rates with respect to a portion of our debt obligations. 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, primarily in our Processing segment. In general, the types of risks hedged are those relating to the variability of future earnings and cash flows caused by changes in commodity prices and interest rates. As a matter of policy, we do not use financial instruments for speculative (or trading) purposes.
Apart from the disclosures below, additional information regarding our financial instruments (financial assets and liabilities) can be found under Note 1 in the Notes to Consolidated Financial Statements.
COMMODITY FINANCIAL INSTRUMENTS. Our Processing and Octane Enhancement segments are directly exposed to commodity price risk through their respective business operations. The prices of natural gas, NGLs and MTBE are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. These factors include the level of domestic oil, natural gas and NGL production and development, the availability of imported oil and natural gas, actions taken by foreign oil and natural gas producing nations, the availability of transportation systems with adequate capacity, the availability of alternative fuels and products, seasonal demand for oil, natural gas and NGLs, conservation, the extent of governmental regulation of production and the overall economic environment.
In order to manage the risks associated with our Processing segment, we may enter into swaps, forwards, commodity futures, options and other commodity financial instruments with similar characteristics that are permitted by contract or business custom to be settled in cash or with another financial instrument. The primary purpose of these risk management activities is to hedge exposure to price risks associated with natural gas, NGL production and inventories, firm commitments and certain anticipated transactions. We do not hedge our exposure to the MTBE markets. Also, in our Pipelines segment, we may utilize a limited number of commodity financial instruments to manage the price Acadian Gas charges certain of its customers for natural gas and/or the price Acadian Gas pays for the natural gas it purchases.
We have adopted a commercial policy to manage our exposure to 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 levels established by the General Partner. We 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 18 months). At December 31, 2001, we had open commodity financial instruments that settle at different dates through December 2002. The General Partner oversees our strategies associated with physical and financial risks, approves specific activities subject to the commercial policy (including authorized products, instruments and markets) and establishes specific guidelines and procedures for implementing and ensuring compliance with the policy.
We assess the risk of our commodity financial instruments portfolio using a sensitivity analysis model. The sensitivity analysis performed on this portfolio measures the potential income or loss (i.e., the change in fair value of the portfolio) based on a hypothetical 10% movement in the underlying quoted market prices of the commodity financial instruments outstanding at the dates noted within the table. In general, we derive the quoted market prices used in the model from those actively quoted on commodity exchanges (ex. NYMEX) for instruments of similar duration. In those rare instances where prices are not actively quoted, we employ regression analysis techniques possessing strong correlation factors.
The sensitivity analysis model takes into account the following primary factors and assumptions:
. the current quoted market price of natural gas; . the current quoted market price of NGLs; . changes in the composition of commodities hedged (i.e., the mix between natural gas and related NGLs ); . fluctuations in the overall volume of commodities hedged (for both natural gas and related NGL hedges outstanding); . market interest rates, which are used in determining the present value; and . a liquid market for such financial instruments.
An increase in fair value of the commodity financial instruments (based upon the factors and assumptions noted above) approximates the income that would be recognized if all of the commodity financial instruments were settled at the dates noted within the table. Conversely, a decrease in fair value of the commodity financial instruments would result in the recording of a loss.
The sensitivity analysis model does not include the impact that the same hypothetical price movement would have on the hedged commodity positions to which they relate. Therefore, the impact on the fair value of the commodity financial instruments of a change in commodity prices would be offset by a corresponding gain or loss on the hedged commodity positions, assuming:
. the commodity financial instruments function effectively as hedges of the underlying risk; . the commodity financial instruments are not closed out in advance of their expected term; and . as applicable, anticipated underlying transactions settle as expected.
We routinely review our open commodity financial instruments in light of current market conditions. If market conditions warrant, some 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 new commodity financial instruments to reestablish the hedge of the commodity position to which the closed instrument relates.
These commodity financial instruments may not qualify for hedge accounting treatment under the specific guidelines of SFAS No. 133 because of ineffectiveness. A hedge is normally regarded as effective if, among other things, at inception and throughout the term of the financial instrument, we could expect changes in the fair value of the hedged item to be almost fully offset by the changes in the fair value of the financial instrument. Currently, the majority of our commodity financial instruments do not qualify as effective accounting hedges under the guidelines of SFAS No. 133, with the result being that changes in the fair value of these positions are recorded on the balance sheet and in earnings through mark-to-market accounting. The use of mark-to- market accounting for these commodity financial instruments results in a degree of non-cash earnings fluctuation that is dependent upon changes in the underlying commodity prices. Even though these instruments do not qualify for hedge accounting treatment under the specific guidelines of SFAS No. 133, we continue to view these financial instruments as economically hedging our commodity price risk exposure as this was the business intent when such contracts were executed. This characterization is consistent with the actual economic performance of the contracts to date and we expect these financial instruments to continue to mitigate (or offset) commodity price risk in the future. The specific accounting for these contracts, however, is consistent with the requirements of SFAS No. 133. For additional information regarding our commodity financial instruments, see Note 11 of the Notes to Consolidated Financial Statements.
At December 31, 2000, the fair value of the commodity financial instruments portfolio was a $38.6 million liability. At this date, our portfolio was primarily comprised of natural gas-based hedging instruments that were negatively affected by the unusually high natural gas prices that occurred at the end of 2000 and beginning of 2001. By December 31, 2001, the value of the portfolio reflected a $5.6 million asset primarily due to the moderation of natural gas prices. The portfolio value was also affected, to a lesser degree, by periodic changes in the composition of commodities hedged and settlements of certain open positions. At March 7, 2002, the portfolio value was a $5.5 million liability primarily due to an increase in natural gas prices.
Historical income or loss resulting from commodity hedging activities are a component of our operating costs and expenses as reflected in the Statements of Consolidated Operations. We recognized income of $101.3 million of such income during fiscal 2001, of which $95.7 million was realized through cash settlement of the commodity hedges.
INTEREST RATE SWAPS. Our interest rate exposure results from variable-rate borrowings from commercial banks and fixed-rate borrowings pursuant to the Senior Notes and MBFC Loan. We manage our exposure to changes in interest rates by utilizing interest rate swaps. The objective of holding interest rate swaps is to manage debt service costs by converting a portion of fixed-rate debt into variable-rate debt or a portion of variable-rate debt into fixed-rate debt. An interest rate swap, in general, requires one party to pay a fixed-rate on the notional amount while the other party pays a floating-rate based on the notional amount. We believe it is prudent to maintain an appropriate mixture of variable- rate and fixed-rate debt.
We assess interest rate cash flow risk by identifying and measuring changes in interest rate exposure that impact future cash flows and evaluating hedging opportunities. We use analytical techniques to measure our exposure to fluctuations in interest rates, including cash flow sensitivity analysis to estimate the expected changes in interest rates on future cash flows. The General Partner oversees the strategies associated with financial risks and approves instruments that are appropriate for our requirements.
Our interest rate swap agreements were dedesignated as hedging instruments after the adoption of SFAS No. 133; therefore, the swaps are accounted for on a mark- to-market basis. However, these financial instruments continue to be effective in achieving the risk management activities for which they were intended. As a result, the change in fair value of these instruments will be reflected on the balance sheet and in earnings (as a component of interest expense) using mark-to-market accounting.
At December 31, 2000, we had three interest rate swaps outstanding having a combined notional value of $154 million (attributable to fixed-rate debt) with an estimated fair value of $2.0 million (an asset). Due to the early termination of two of the swaps, the notional amount and fair value of the remaining swap was $54 million and $3.5 million (an asset), respectively, at December 31, 2001.
We recorded $13.2 million of income from our interest rates swaps during 2001 and $10.0 million during 2000. The income recognized in 2001 from these swaps includes the $2.3 million in non-cash mark-to-market income at December 31, 2001 (attributable to the sole remaining swap). The remaining $10.9 has been realized. No mark-to-market income was recorded prior to the implementation of SFAS No. 133.
The fair value of the remaining swap at December 31, 2001 would increase to $2.5 million if quoted market interest rates were to decline by 10%; conversely, the fair value would decline to $2.1 million if rates were to rise by 10%. For additional information regarding our interest rate swaps, see Note 11 of the Notes to Consolidated Financial Statements.
At December 31, 2001, our fixed-rate debt obligations aggregated $854.0 million principal amount and had a fair value of $894.0 million. Since these instruments are fixed interest rates, they do not expose us to risk of loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase to approximately $920.6 million if the respective yields to maturity for these debt obligations were to decline by 10% from their levels at December 31, 2001. In general, such an increase in fair value would impact earnings and cash flows only if we elected to reacquire all or a portion of these instruments in the open market prior to their maturity.
Counterparty settlement risk issues
We are exposed to credit risk with our counterparties in terms of settlement risk associated with the financial instruments. On all transactions where we are exposed to settlement 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.
On December 2, 2001, Enron Corp., or Enron, (NYSE, symbol "ENE") announced that it and certain of its subsidiaries were filing voluntary petitions for Chapter 11 reorganization with the U.S. Bankruptcy Court for the
Southern District of New York. At the time of its bankruptcy filing, Enron North America, a subsidiary of Enron, was the counterparty to a number of our commodity financial instruments. As a result, we established a $10.6 million reserve for all amounts owed to us by Enron. The Enron amounts were unsecured and the amount that we may ultimately recover, if any, is not presently determinable. Of the reserve amount established, $4.3 million was attributable to various unbilled commodity financial instrument positions that terminate during the first quarter of 2002. Currently, we do not anticipate any material change in this estimate.
At December 31, 2001, receivables and other current assets associated with our counterparties totaled $9.9 million, net of the Enron reserve. Of the $9.9 million, $9.6 million is with counterparties rated as investment grade by prominent rating agencies.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The information required hereunder is included in this report as set forth in the "Index to Financial Statements" on page.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
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 the EPCO Agreement, see page 57) under the direction of the Board of Directors and executive officers of the General Partner.
Notwithstanding any limitation on its obligations or duties, our General Partner 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 the General Partner. Whenever possible, the General Partner intends to make any such indebtedness or other obligations non-recourse to it.
Audit and Conflicts Committee
In accordance with NYSE rules, the Board of Directors of the General Partner has named three of its members to serve on its Audit and Conflicts Committee. The members of the Audit and Conflicts Committee are financially literate and independent nonexecutive directors, free from any relationship that would interfere with the exercise of independent judgment. The Audit and Conflicts Committee has the authority to review specific matters as to which the Board of Directors believes there may be a conflict of interests in order to determine if the resolution of such conflict proposed by the General Partner is fair and reasonable to the Company. Any matters approved by the Audit and Conflicts Committee are conclusively deemed to be fair and reasonable to our business, approved by all of our partners and not a breach by the General Partner or its Board of Directors of any duties they may owe us or our Unitholders.
The members of the Audit and Conflicts 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 committee shall have accounting or related financial management expertise. In addition to ruling in cases involving conflicts of interest, the primary responsibilities of the Audit and Conflicts Committee include:
. monitoring the integrity of the financial reporting process and its related systems of internal control; . ensuring legal and regulatory compliance of the General Partner and the Company; . overseeing the independence and performance of our independent public accountants; . providing for an avenue of communication among the independent public accountants, management, internal audit function and the Board of Directors; . 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 increases in the administrative service fee payable under the EPCO Agreement.
Pursuant to its formal written charter adopted in June 2000, the Audit and Conflicts committee has the authority to conduct any investigation appropriate to fulfilling its responsibilities, and it has direct access to the independent public accountants as well as EPCO personnel. The Audit and Conflicts 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.
Directors, Executive Officers of the General Partner
Set forth below is the name, age and position of each of the directors and executive officers of the General Partner. Each member of the Board of Directors serves until such member's death, resignation or removal. The executive officers are elected for one-year terms and may be removed, with or without cause, only by the Board of Directors.
(1) Member of the Executive Committee (2) Member of the Audit and Conflicts Committee (3) Executive Officer
Dan L. Duncan was elected Chairman of the Board and a Director of the General Partner in April 1998. Mr. Duncan has served as Chairman of the Board of our predecessor, EPCO, since 1979.
O.S. Andras was elected President, Chief Executive Officer and a Director of the General Partner in April 1998. Mr. Andras served as President and Chief Executive Officer of EPCO from 1996 to February 2001.
Randa Duncan Williams was elected a Director of the General Partner in April 1998. In February 2001, she was promoted to President and Chief Executive Officer of EPCO from her previous position of Group Executive Vice President of EPCO, a position she had held since 1994. Ms. Williams is the daughter of Dan L. Duncan.
J. R. (Jeri) Eagan was elected a Director of the General Partner in October 2000. Since 1999, Ms. Eagan has served in various executive-level positions with Shell and currently holds the office of Chief Financial Officer of Shell Oil Company in addition to that of Vice President Finance & Commercial Operations of a Shell subsidiary. From 1994 to 1999, she worked on several assignments in Shell's London office.
J.A. (Jorn) Berget was elected a Director of the General Partner in November 2000. Since 1995, Mr. Berget has served in various managerial positions with Shell, including Vice President and General Manager for one of its subsidiaries since 2000. Mr. Berget also serves as a director of Enventure Global Technologies (a joint venture between Shell and Halliburton Company).
Dr. Ralph S. Cunningham was elected a Director of the General Partner in April 1998. 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 chemicals company) and Agrium, Inc. (a Canadian publicly-traded agricultural chemicals company) and was a former director of EPCO from 1987 to 1997. Mr. Cunningham serves as Chairman of our Audit and Conflicts Committee.
Curtis R. Frasier was elected a Director of the General Partner in November 1999. Mr. Frasier has held various executive-level positions with Shell including President of its midstream enterprise business.
Lee W. Marshall, Sr. was elected a Director of the General Partner in April 1998. Mr. Marshall has been the Chief Executive Officer and principal owner of Bison Resources, LLC since 1991. He has also served in senior management positions with Union Pacific Resource and Tenneco Oil. Mr. Marshall is a member of our Audit and Conflicts Committee.
Richard S. Snell was elected a Director of the General Partner in June 2000. Mr. Snell was an attorney with Snell & Smith, P.C. for seven years after founding the firm in 1993. He is currently a partner with the law firm of Thompson & Knight LLP in Houston, Texas and is a certified public accountant. Mr. Snell is a member of our Audit and Conflicts Committee.
Richard H. Bachmann was elected a Director of the General Partner in June 2000. He has served as Executive Vice President and Chief Legal Officer of the General Partner and EPCO since January 1999. Previously, he was a partner with the legal firms of Snell & Smith P.C. and Butler & Binion.
Michael A. Creel was elected an Executive Vice President of the General Partner in February 2001, having served as a Senior Vice President of the General Partner since November 1999. In June 2000, Mr. Creel, a certified public accountant, assumed the role of Chief Financial Officer of the Company along with his other responsibilities. From 1997 to 1999 he held a series of positions with a Shell affiliate, including Senior Vice President, Chief Financial Officer and Treasurer. From 1995 to 1997, Mr. Creel was Vice President and Treasurer of NorAm Energy Corp.
A.J. ("Jim") Teague was elected an Executive Vice President of the General Partner in November 1999. From 1998 to 1999 he served as President of a Shell affiliate and from 1997 to 1998 was President of Marketing and Trading for Mapco, Inc.
William D. Ray was elected an Executive Vice President of the General Partner in April 1998. Mr. Ray has served as EPCO's Executive Vice President for Marketing and Supply since 1985.
Charles E. Crain was elected a Senior Vice President of the General Partner in April 1998. Mr. Crain has served as Senior Vice President of Operations for EPCO since 1991.
A. Monty Wells was elected a Senior Vice President of the General Partner in June 2000. Mr. Wells has served in a number of managerial positions with EPCO since 1980 including Vice President of Marketing and Supply.
W. ("Bill") Ordemann was elected a Senior Vice President of the General Partner in September 2001. Mr. Ordemann has served in executive-level positions in our NGL businesses since 1999. From 1996 to 1999, he served as a Vice President of two Shell affiliates, including TNGL.
Gil H. Radtke was elected a Senior Vice President of the General Partner in February 2002. Mr. Radtke joined the Company in connection with our purchase of Diamond-Koch's storage and propylene fractionation assets in January and February 2002. Before joining the Company, Mr. Radtke served as President of the Diamond-Koch joint venture where he was responsible for its storage, propylene fractionation, pipeline and NGL fractionation businesses. Mr. Radtke was employed by Valero Energy Corporation (a partner in the Diamond-Koch joint venture) for the last eighteen years in various commercial and analysis roles.
Michael J. Knesek was elected Principal Accounting Officer and a Vice President of the General Partner in August 2000. Since 1990, Mr. Knesek, a certified public accountant, has been the Controller and a Vice President of EPCO.
W. Randall Fowler was elected Treasurer and a Vice President of the General Partner in August 2000. Mr. Fowler joined the Company as director of investor relations in 1999. From 1995 to 1999, Mr. Fowler served in a number of corporate finance and accounting-related capacities at NorAm Energy Corp., including Director of Finance Wholesale Energy Marketing and Assistant Treasurer.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
We do not directly employ any of the persons responsible for managing or operating our businesses. Instead, our businesses are managed by the General Partner, the executive officers of which are employees of, and the compensation of whom is paid by, EPCO. In January 2000, we began reimbursing EPCO for our portion of the compensation EPCO pays individuals it employs as a result of our expansion activities (through the construction of new facilities, business acquisitions or the like). In addition, we pay EPCO an annual Administrative Services Fee to cover a portion of EPCO's total compensation costs for all other individuals it employs for the management and operation of our businesses. Currently, the Administrative Services Fee is $16.0 million annually (this amount is subject to a 10% escalation per year, if so approved by the Audit and Conflicts Committee). For a more complete discussion of the EPCO Agreement, including the Administrative Services Fee, see page 57.
The compensation of O.S. Andras, the General Partner's Chief Executive Officer, is paid solely by EPCO without any reimbursement by us. Of the EPCO employees serving our General Partner whose compensation is wholly or partially-reimbursed by us, the four most highly compensated (in terms of our reimbursement) at December 31, 2001 were A.J. ("Jim") Teague, W. ("Bill") Ordemann, William D. Ray and Charles E. Crain, collectively the "Named Executive Officers". The compensation of Mr. Ray and Mr. Crain is reimbursed to EPCO through our payment of the Administrative Services Fee. The compensation of Mr. Teague and Mr. Ordemann is wholly reimbursable by us apart from the Administrative Services Fee. The Named Executive Officers have also received certain equity-based awards as part of their compensation from EPCO, the expense of which awards are subject to reimbursement by us to the extent that an individual's compensation is not reimbursed as part of the Administrative Services Fee. As a result, we will be responsible for all of the costs associated with the awards granted to Mr. Teague and Mr. Ordemann. The cost of any awards granted to Mr. Ray and Mr. Crain will be covered by our payment of the Administrative Services Fee with EPCO solely bearing any shortfall in reimbursement.
The Administrative Services Fee paid to EPCO for the years ended December 31, 2001, 2000 and 1999 was $15.1 million, $13.8 million and $12.5 million. As noted above, this base amount partially reimbursed EPCO for the costs it incurred in managing and operating our businesses, including the compensation of Mr. Ray and Mr. Crain.
The following table sets forth certain compensation information for the reimbursable, expansion-related Named Executive Officers for the fiscal years ended December 31, 2001, 2000 and 1999. The information for Mr. Andras has been omitted since his compensation is wholly-paid by EPCO with no reimbursement by us. The information for Mr. Ray and Mr. Crain is not included since their compensation (along with other EPCO employees working on our behalf as discussed above) is fully reimbursed through the Administrative Services Fee.
Summary Compensation Table
(1) The information for Mr. Andras has been omitted since his compensation is wholly-paid by EPCO with no reimbursement by us. (2) The information for Mr. Ray and Mr. Crain is not included since their compensation is included in the Administrative Services Fee. (3) Prior to January 1, 2000, EPCO waived its right to reimbursement from us for the compensation paid to employees that it had hired in connection with the expansion of our business. EPCO elected to charge us only the Administrative Services Fee during 1999; therefore, we did not bear the expense of reimbursement for the compensation of these individuals. (4) Although EPCO waived its right to collect reimbursement for the base salaries, bonuses and other dollar compensation paid to the reimbursable, expansion-related Named Executive Officers in 1999 (see (3) above), these individuals received Common Unit Options of the Limited Partner that were not exercised/exercisable until after 1999. When the options are ultimately exercised, we will be responsible for reimbursing EPCO for expenditures associated with these awards. (5) 2001 and 2000 amounts represent contributions made by EPCO to the 401(K) plan of the Named Executive Officers. (6) Mr. Ordemann's 2001 bonuses include a $100,000 retention bonus agreed to when he joined us in connection with the TNGL acquisition.
Common Unit Option Grants During 2001
The following table provides certain information concerning individual grants of options to purchase Common Units of the Limited Partner during the fiscal year ended December 31, 2001 to each of the reimbursable, expansion-related Named Executive Officers.
(1) The amounts shown under these columns are the result of calculations at the 5% and 10% rates required by the SEC and are not intended to forecast future appreciation of the Limited Partner's Common Unit price.
Unit Options Exercised and Fiscal Year-End Values
The following table provides certain information concerning each exercise of options to purchase Common Units of the Limited Partner during the fiscal year ended December 31, 2001 by each of the reimbursable, expansion-related Named Executive Officers and the value of unexercised options as of December 31, 2001:
(1) The "Value Realized" represents the difference between the exercise price of the Common Unit options and the market (sale) price of the Common Units on the date of exercise without considering any taxes which may have been owed. (2) The value is based on $47.05 per Common Unit, which was the closing price reported on the NYSE on December 31, 2001.
Compensation of Directors
No additional compensation is paid to employees of EPCO or Shell who also serve as directors of the General Partner. During fiscal 2001, the three independent outside directors each received (i) an annual retainer of $18,000, (ii) $1,000 for each meeting of the Board of Directors that they attend and (iii) $500 for each meeting of the Audit and Conflicts Committee that they attend. In addition, an annual retainer of $500 is paid to each independent outside director who also serves as the chairman of a committee of the Board of Directors. These retainers and fees are an expense of the General Partner. The three independent outside directors have also been granted options to acquire Common Units of the Limited Partner. When these are exercised, the costs will be charged to the General Partner.
We have indemnified each director for his or her actions associated with being a director of the General Partner to the extent permitted under Delaware law.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The Limited Partner (EPPLP) owns 98.9899% of our partnership interests with the General Partner owning the remaining 1.0101%. The following table sets forth certain information as of March 1, 2002, regarding the beneficial ownership of the Limited Partner's Common, Subordinated and Special Units by (i) all persons known by the General Partner to beneficially own more than five percent of the Common Units, (ii) the directors and certain executive officers of the General Partner and (iii) all directors, executive and other officers of the General Partner as a group.
(1) EPCO holds its Units through a wholly-owned subsidiary, EPC Partners II, Inc. Mr. Duncan owns 50.4% of the voting stock of EPCO and, accordingly, exercises sole voting and dispositive power with respect to the Units held by EPCO. The remaining shares of EPCO capital stock are held primarily by trusts for the benefit of the members of Mr. Duncan's family, including Randa Duncan Williams, a director of the General Partner. The address of EPCO and Mr. Duncan is 2727 North Loop West, Houston, Texas 77008. (2) The Special Units were issued to Shell US Gas & Power LLC (an affiliate of Shell) as part of the TNGL acquisition. The address for this affiliate of Shell is 1301 McKinney, Ste. 700, Houston, Texas 77010. (3) In addition to the Units held by EPCO, Dan Duncan has beneficial ownership of an additional 1,625,118 Common Units held by the Enterprise Products 1998 Unit Option Plan Trust, Enterprise Products 2000 Rabbi Trust and the EPOLP 1999 Grantor Trust. (4) Dr. Cunningham's and Mr. Marshall's beneficial ownership amounts represent options (under an EPCO Unit option plan) to purchase 10,000 Common Units within 60 days of March 21, 2002. (5) Mr. Bachmann's beneficial ownership amount includes options (under an EPCO Unit option plan) to purchase 40,000 Common Units within 60 days of March 21, 2002. (6) Mr. Crain's beneficial ownership amount includes options (under an EPCO Unit option plan) to purchase 20,000 Common Units within 60 days of March 21, 2002. (7) Cumulatively, this group includes Common Unit options (under an EPCO Unit option plan) to purchase 129,061 Common Units within 60 days of March 21, 2002.
Subordinated Units and Special Units represent non-voting ownership interests in our Limited Partner until their conversion into Common Units on a one-for-one basis. The Subordinated Units are forecast to convert into
Common Units as follows: 5.3 million in May 2002, 5.3 million in May 2003 with the balance converting in August 2003. Of the 14.5 million Special Units, 9.5 million are scheduled to convert into Common Units in August 2002 and 5.0 million in August 2003.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Relationship with EPCO and its affiliates
We have an extensive and ongoing relationship with EPCO and its affiliates. EPCO is majority-owned and controlled by Dan L. Duncan, Chairman of the Board and a director of the General Partner. In addition, three other members of the Board of Directors (O.S. Andras, Randa Duncan Williams and Richard H. Bachmann) and the remaining executive and other officers (see Item 10 for a listing of these individuals) of the General Partner are employees of EPCO. The principal business activity of the General Partner is to act as our managing partner.
Mr. Duncan owns 50.4% of the voting stock of EPCO and, accordingly, exercises sole voting and dispositive power with respect to the Limited Partner Units held by EPCO. The remaining shares of EPCO capital stock are held primarily by trusts for the benefit of the members of Mr. Duncan's family, including Randa Duncan Williams, a director of the General Partner. In addition, EPCO and Dan Duncan, LLC collectively own 70% of the General Partner which in turn owns a combined 2% interest in us and our Limited Partner.
In addition, trust affiliates of EPCO (Enterprise Products 1998 Unit Option Plan Trust and the Enterprise Products 2000 Rabbi Trust) purchase Common Units of the Limited Partner for the purpose of granting options to certain directors of the General Partner, EPCO management and certain key employees. During 2001, these trusts purchased 211,518 Common Units on the open market or through privately negotiated transactions. At December 31, 2001, these trusts owned a total of 1,461,518 Common Units. In November 2001, EPCO directly purchased 500,000 Common Units at market prices for $22.6 million from our consolidated trust, EPOLP 1999 Grantor Trust, on behalf of a key executive and Director of the General Partner.
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.
EPCO Agreement
As stated previously, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to the EPCO Agreement (in effect since July 1998). Under the terms of the EPCO Agreement, EPCO agreed to:
. employ the personnel necessary to manage our business and affairs (through the General Partner); . employ the operating personnel involved in our business for which we reimburse EPCO at cost (based upon EPCO's actual salary costs and related fringe benefits); . allow us to participate as named insureds in EPCO's current insurance program with the costs being allocated among the parties on the basis of formulas set forth in the agreement; . grant an irrevocable, non-exclusive worldwide license to all of the EPCO trademarks and trade names used in our business; . indemnify us against any losses resulting from certain lawsuits; and . sublease all of the equipment which it holds pursuant to operating leases relating to an isomerization unit, a deisobutanizer tower, two cogeneration units and approximately 100 railcars to us for one dollar per year and to assign its purchase option under such leases to us. EPCO remains liable for the lease payments associated with these assets.
Operating costs and expenses (as shown in the audited Statements of Consolidated Operations) treat the full amount of lease payments being made by EPCO as a non- cash operating expense (with the offset to Partners' Equity on the Consolidated Balance Sheet). In addition, operating costs and expenses include compensation charges for EPCO's employees who operate the facilities.
Pursuant to the EPCO Agreement, we reimburse EPCO for our portion of the costs of certain of its employees who manage our business and affairs. In general, our reimbursement of EPCO's expense associated with administrative positions that were active at the time of our initial public offering in July 1998 is capped by the Administrative Services Fee that we pay (currently at $16 million annually). The General Partner, with the approval and consent of the Audit and Conflicts Committee, may agree to annual increases of such fee up to ten percent per year during the 10-year term of the EPCO Agreement. Any difference between the actual costs of this "pre-expansion" group (including those associated with equity- based awards granted to certain individuals within this group) and the Administrative Services Fee will be retained by EPCO (i.e., EPCO solely bears any shortfall in reimbursement for this group).
Beginning in January 2000, we began reimbursing EPCO for our share of the compensation of administrative personnel that it had hired in response to our expansion and business development activities (through the construction of new facilities, business acquisitions or the like). EPCO began hiring "expansion" administrative personnel after our initial public offering in connection with the TNGL acquisition and other development activities. In general, we reimburse EPCO for our share of its compensation expense associated with these "expansion" administrative positions, including those costs attributable to equity-based awards.
The following table summarizes of the Administrative Services Fee paid to EPCO during the last three years. In addition, the table shows the total compensation reimbursed to EPCO for operations personnel and "expansion" administrative positions.
FOR YEAR ENDED DECEMBER 31, -------------------------------------- 2001 2000 1999 --------------------------------------- (in millions of dollars) Administrative Services Fee paid to EPCO $15,125 $13,750 $12,500 Compensation reimbursed to EPCO 48,507 44,717 26,889 --------------------------------------- Total $63,632 $58,467 $39,389 =======================================
The Administrative Services Fee has increased each year from its initial $12.0 million per annum rate with the approval of the Audit and Conflicts Committee as prescribed in the EPCO Agreement. The increase in reimbursable compensation payments made to EPCO is primarily the result of the TNGL (1999) and Acadian Gas (2001) acquisitions. EPCO waived the reimbursement of "expansion" administrative personnel compensation through December 1999. As noted earlier, we began reimbursing EPCO for the employment costs of the "expansion" administrative employees beginning in January 2000, hence the significant increase for this line item in the table between 1999 and 2000.
We elected to prepay EPCO a discounted amount of $15.7 million for the 2002 Administrative Services Fee in December 2001 (the undiscounted amount was $16.0 million). We will owe EPCO for any undiscounted amount above the $16.0 million if the General Partner approves an increase in the fee during 2002.
Other related party transactions with EPCO or its affiliates
The following is a summary of the other ongoing significant relationships and transactions between us and EPCO and or its affiliates:
. EPCO is the operator of the plants and facilities owned by BEF and EPIK and is paid a management fee by these entities in lieu of reimbursement for the actual cost of providing management services. BEF and EPIK paid $0.8 million in management fees to EPCO during 2001. . We have entered into an agreement with EPCO to provide trucking services to us for the loading and transportation of NGL products. During 2001, we paid $9.0 million for these services. . In the normal course of business, we may, on occasion, engage in transactions with EPCO involving the buying and selling of NGL products. We did not record any such transactions with EPCO during 2001.
Relationships with Shell
We have an extensive and ongoing relationship with Shell as a partner, customer and vendor. Shell, through its subsidiary Shell US Gas & Power LLC, owns approximately 23.2% of our Limited Partner and 30.0% of the General Partner. Currently, three members of the Board of Directors of the General Partner (J.R. Eagan, J.A. Berget and Curtis R. Frasier) are employees of Shell.
Shell is a significant customer of our Processing segment (see page 14 for a discussion of the 20-year Shell Processing Agreement). Apart from operating expenses arising from the Shell Processing Agreement, the Company also sells NGL and petrochemical products to Shell. During 2001, revenues from Shell aggregated $333.3 million while purchases from Shell totaled $705.4 million.
Shell accounted for 10.5% of consolidated revenues in 2001 (up from 9.5% of consolidated revenues in 2000). Approximately 80% of our revenues from Shell during 2001 and 2000 are attributable to the sale of NGL products as recorded in our Processing segment. See Note 8 of the Notes to the Consolidated Financial Statements for additional information regarding related party transactions.
In April 2001, we acquired Acadian Gas from Shell from approximately $226 million in an arms-length negotiated transaction (through a bidding process) that was approved by the Board of Directors of the General Partner, with the three Shell representatives abstaining. See page 8 for a discussion of the assets involved in this acquisition.
In January 2001, we purchased equity interests in four Gulf of Mexico natural gas pipeline systems (Stingray, Manta Ray, Nautilus and Nemo) from El Paso. Shell also owns equity interests in and operates and/or administers each of these pipelines. During 2001, our portion of the management and operating fees for these pipeline systems paid to Shell was $0.8 million. See page 8 for a more detailed discussion of these pipeline systems.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a)(1) and (2) Financial Statements and Financial Statement Schedules
See "Index to Financial Statements" set forth on page.
(a)(3) Exhibits
2.1(a) Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P. dated as of September 22, 2000. (Exhibit 10.1 to Form 8-K filed on September 26, 2000).
2.2(a) Purchase and Sale Agreement dated as of January 16, 2002 by and between Diamond-Koch, L.P. and Diamond-Koch III, L.P. and Enterprise Products Texas Operating L.P. (Exhibit 10.1 to Form 8-K filed February 8, 2002).
2.3(a) Purchase and Sale Agreement dated as of January 31, 2002 by and between D-K Diamond-Koch, L.L.C., Diamond-Koch, L.P. and Diamond-Koch III, L.P. as Sellers, and Enterprise Products Operating L.P., as Buyer. (Exhibit 10.2 to Form 8-K filed February 8, 2002).
3.1(b) Form of Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P. (Exhibit 3.2 to Registration Statement of Form S-1/A, File No. 333-52537, filed on July 21, 1998).
3.2(c) Second Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P. dated September 17, 1999. (The Company incorporates by reference the above document included as Exhibit "D" to the Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
3.3(b) First Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC dated September 17, 1999. (Exhibit 99.8 on Form 8-K/A-1 filed October 27, 1999).
3.4(b) Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P. dated June 9, 2000. (Exhibit 3.6 to Form 10-Q filed August 11, 2000).
4.1(c) Unitholder Rights Agreement among Tejas Energy LLC, Tejas Midstream Enterprises, LLC, Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products Company, Enterprise Products GP, LLC and EPC Partners II, Inc. dated September 17, 1999. (The Company incorporates by reference the above document included as Exhibit "C" to the Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.2(c) Contribution Agreement by and among Tejas Energy LLC, Tejas Midstream Enterprises, LLC, Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products Company, Enterprise Products GP, LLC and EPC Partners II, Inc. dated September 17, 1999. (The Company incorporates by reference the above document included as Exhibit "B" to the Schedule 13 D filed September 27, 1999 by Tejas Energy, LLC).
4.3(b) Form of Indenture dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee. (Exhibit 4.1 on Form 8-K filed March 10, 2000).
4.4(b) Form of Global Note representing $350 million principal amount of 8.25% Senior Notes due 2005 (the "Senior Notes A"). (Exhibit 4.2 on Form 8-K filed March 10, 2000).
4.5(a) $250 million Multi-Year Revolving Credit Agreement (the "Multi-Year Credit Facility") among Enterprise Products Operating L.P., First Union National Bank, as administrative agent; Bank One, NA, as documentation agent; and The Chase Manhattan Bank, as syndication agent and the Several Banks from time to time parties thereto dated November 17, 2000. (Exhibit 4.2 on Form 8-K filed January 25, 2001).
4.6(a) $150 Million 364-Day Revolving Credit Agreement (the "364-Day Credit Facility") among Enterprise Products Operating L.P. and First Union National Bank, as administrative agent; Bank One, NA, as documentation agent; and The Chase Manhattan Bank, as syndication agent and the Several Banks from time to time parties thereto dated November 17, 2000. (Exhibit 4.3 on Form 8-K filed January 25, 2001).
4.7(a) Guaranty Agreement (relating to the Multi-Year Credit Facility) by Enterprise Products Partners L.P. in favor of First Union National Bank, as administrative agent dated November 17, 2000. (Exhibit 4.4 on Form 8-K filed January 25, 2001).
4.8(a) Guaranty Agreement (relating to the 364-Day Credit Facility) by Enterprise Products Partners L.P. in favor of First Union National Bank, as administrative agent dated November 17, 2000. (Exhibit 4.5 on Form 8-K filed January 25, 2001).
4.9(a) Form of Global Note representing $450 million principal amount of 7.50% Senior Notes due 2011 (the "Senior Notes B"). (Exhibit 4.1 to Form 8-K filed January 25, 2001).
4.10(a) First Amendment to Multi-Year Credit Facility dated April 19, 2001. (Exhibit 4.12 to Form 10-Q filed May 14, 2001).
4.11* First Amendment to 364-Day Credit Facility dated November 6, 2001, effective as of November 16, 2001.
10.1(b) Articles of Merger of Enterprise Products Company, HSC Pipeline Partnership, L.P., Chunchula Pipeline Company, LLC, Propylene Pipeline Partnership, L.P., Cajun Pipeline Company, LLC and Enterprise Products Texas Operating L.P. dated June 1, 1998. (Exhibit 10.1 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998).
10.2(b) Form of EPCO Agreement among Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products GP, LLC and Enterprise Products Company. (Exhibit 10.2 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998).
10.3(b) Transportation Contract between Enterprise Products Operating L.P. and Enterprise Transportation Company dated June 1, 1998. (Exhibit 10.3 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998).
10.4(b) Venture Participation Agreement among Sun Company, Inc. (R&M), Liquid Energy Corporation and Enterprise Products Company dated May 1, 1992. (Exhibit 10.4 to Registration Statement on Form S-1, File No. 333-52537, filed on May 13, 1998).
10.5(b) Partnership Agreement among Sun BEF, Inc., Liquid Energy Fuels Corporation and Enterprise Products Company dated May 1, 1992. (Exhibit 10.5 to Registration Statement on Form S-1, File No. 333-52537, filed on May 13, 1998).
10.6(b) Amended and Restated MTBE Off-Take Agreement between Belvieu Environmental Fuels and Sun Company, Inc. (R&M) dated August 16, 1995. (Exhibit 10.6 to Registration Statement on Form S-1, File No. 333-52537, filed on May 13, 1998).
10.7(b) Propylene Facility and Pipeline Agreement between Enterprise Petrochemical Company and Hercules Incorporated dated December 13, 1978. (Exhibit 10.9 to Registration Statement on Form S-1, File No. 333-52537, filed on May 13, 1998).
10.8(b) Restated Operating Agreement for the Mont Belvieu Fractionation Facilities Chambers County, Texas among Enterprise Products Company, Texaco Producing Inc., El Paso Hydrocarbons Company and Champlin Petroleum Company dated July 17, 1985. (Exhibit 10.10 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998).
10.9(b) Ratification and Joinder Agreement relating to Mont Belvieu Associates Facilities among Enterprise Products Company, Texaco Producing Inc., El Paso Hydrocarbons Company, Champlin Petroleum Company and Mont Belvieu Associates dated July 17, 1985. (Exhibit 10.11 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998).
10.10(b) Amendment to Propylene Facility and Pipeline Agreement and Propylene Sales Agreement between HIMONT U.S.A., Inc. and Enterprise Products Company dated January 1, 1993. (Exhibit 10.12 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998).
10.11(b) Amendment to Propylene Facility and Pipeline Agreement and Propylene Sales Agreement between HIMONT U.S.A., Inc. and Enterprise Products Company dated January 1, 1995. (Exhibit 10.13 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998).
10.12(b) Fourth Amendment to Conveyance of Gas Processing Rights among Tejas Natural Gas Liquids, LLC and Shell Oil Company, Shell Exploration & Production Company, Shell Offshore Inc., Shell Deepwater Development Inc., Shell Land & Energy Company and Shell Frontier Oil & Gas Inc. dated August 1, 1999. (Exhibit 10.14 to Form 10-Q filed on November 15, 1999).
10.13(b) Fifth Amendment to Conveyance of Gas Processing Rights dated as of April 1, 2001 among Enterprise Gas Processing, LLC, Shell Oil Company, Shell Exploration & Production Company, Shell Offshore, Inc., Shell Consolidated Energy Resources, Inc., Shell Land & Energy Company and Shell Frontier Oil & Gas, Inc. (Exhibit 10.13 to Form 10-Q filed on August 13, 2001).
10.14(b) Enterprise Products Company 1998 Long-Term Incentive Plan (Exhibit 10.1 to Registration Statement on Form S-8, File No. 333-36856, filed on May 12, 2000).
10.15(b) Enterprise Products GP, LLC 1999 Long-Term Incentive Plan (Exhibit 10.2 to Registration Statement on Form S-8, File No. 333-36856, filed on May 12, 2000).
10.16(b) Form of Option Agreement under the 1998 Long-Term Incentive Plan and the 1999 Long-Term Incentive Plan (Exhibit 10.3 to the Registration Statement on Form S-8, File No. 333-36856, filed on May 12, 2000).
12.1* Computation of ratio of earnings to fixed charges for each of the five years ended December 31, 2001, 2000, 1999, 1998 and 1997.
21.1* List of subsidiaries.
23.1* Consent of Deloitte & Touche.
(a) Incorporated by reference to the filings of the Registrant as indicated (b) Incorporated by reference to the filings of Enterprise Products Partners L.P. as indicated (c) Incorporated by reference to the filings of Tejas Energy LLC as indicated * An asterisk indicates that an exhibit is filed in conjunction with this report.
(b) Reports on Form 8-K
Form 8-K filed November 13, 2001. In accordance with Regulation FD, the Limited Partner notified its investors and the SEC that representatives of our General Partner were to make a presentation to equity analysts and others on November 13, 2001 concerning the Limited Partner and the Company. We noted that interested parties could view the presentation materials on our website, www.epplp.com. - -------------
Page ENTERPRISE PRODUCTS OPERATING L.P.
Independent Auditors' Report
Consolidated Balance Sheets as of December 31, 2001 and 2000
Statements of Consolidated Operations for the Years Ended December 31, 2001, 2000 and 1999
Statements of Consolidated Cash Flows for the Years Ended December 31, 2001, 2000 and 1999
Statements of Consolidated Partners' Equity for the Years Ended December 31, 2001, 2000 and 1999
Notes to Consolidated Financial Statements
SUPPLEMENTAL SCHEDULE
Schedule II - Valuation and Qualifying Accounts
All schedules, except the one listed above, have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.
INDEPENDENT AUDITORS' REPORT
Enterprise Products Operating L.P.:
We have audited the accompanying consolidated balance sheets of Enterprise Products Operating L.P. and subsidiaries (the "Company") as of December 31, 2001 and 2000, and the related statements of consolidated operations, consolidated cash flows and consolidated partners' equity for each of the years in the three- year period ended December 31, 2001. Our audits also included the consolidated financial statement schedule of the Company listed in the Index to the Financial Statements. These consolidated financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company at December 31, 2001 and 2000, and the results of its consolidated operations and its consolidated cash flows for each of the years in the three-year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 11 to the consolidated financial statements, the Company changed its method of accounting for derivative instruments in 2001.
/s/ DELOITTE & TOUCHE LLP Houston, Texas March 8, 2002
ENTERPRISE PRODUCTS OPERATING L.P. CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS)
ENTERPRISE PRODUCTS OPERATING L.P. STATEMENTS OF CONSOLIDATED OPERATIONS (DOLLARS IN THOUSANDS)
ENTERPRISE PRODUCTS OPERATING L.P. STATEMENTS OF CONSOLIDATED CASH FLOWS (DOLLARS IN THOUSANDS)
See Notes to Consolidated Financial Statements
ENTERPRISE PRODUCTS OPERATING L.P. STATEMENTS OF CONSOLIDATED PARTNERS' EQUITY (DOLLARS IN THOUSANDS)
See Notes to Consolidated Financial Statements
ENTERPRISE PRODUCTS OPERATING L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ENTERPRISE PRODUCTS OPERATING L.P. (a Delaware limited partnership) was formed in April 1998 to acquire, own and operate all of the NGL processing and distribution assets of Enterprise Products Company ("EPCO"). We conduct substantially all of the business of our Limited Partner and parent, Enterprise Products Partners L.P. ("EPPLP"), which owns 98.9899% of our equity interests. Enterprise Products GP, LLC (the "General Partner") owns the remaining 1.0101% of our equity interests. Both the Limited Partner and General Partner are affiliates of EPCO. Our principal executive offices are located at 2727 North Loop West, Houston, Texas 77008-1038 and our telephone number is 713-880-6500. Unless the context requires otherwise, references to "we","us","our" or the "Company" are intended to mean Enterprise Products Operating L.P. and subsidiaries.
Prior to their consolidation, EPCO and its affiliate companies were controlled by members of a single family, who collectively owned at least 90% of each of the entities for all periods prior to the formation of the Company. As of April 30, 1998, the owners of all the affiliated companies exchanged their ownership interests for shares of EPCO. Accordingly, each of the affiliated companies became a wholly-owned subsidiary of EPCO or was merged into EPCO as of April 30, 1998. In accordance with generally accepted accounting principles, the consolidation of the affiliated companies with EPCO was accounted for as a reorganization of entities under common control in a manner similar to a pooling of interests.
On May 8, 1998, EPCO contributed all of its NGL assets to us (through our Limited and General Partners) and we assumed certain of EPCO's debt. As a result, we became the successor to the NGL operations of EPCO.
Effective July 27, 1998, our Limited Partner filed a registration statement pursuant to an initial public offering ("IPO") of 12,000,000 Common Units. The Common Units sold for $22 per unit. As a result, our Limited Partner contributed the proceeds of its IPO of approximately $243.3 million net of underwriting commissions and offering costs to the Company.
The accompanying consolidated financial statements include the historical accounts and operations of the NGL business of EPCO, including NGL operations conducted by affiliated companies of EPCO prior to their consolidation with EPCO. The consolidated financial statements include our accounts and those of our majority-owned subsidiaries, after elimination of all material intercompany accounts and transactions. In general, investments in which we own 20% to 50% and exercise significant influence over operating and financial policies are accounted for using the equity method. Investments in which we own less than 20% are accounted for using the cost method unless we exercise significant influence over operating and financial policies of the investee in which case the investment is accounted for using the equity method.
Certain reclassifications have been made to the prior years' financial statements to conform to the current year presentation. These reclassifications had no effect on previously reported results of consolidated operations.
CASH FLOWS are computed using the indirect method. For cash flow purposes, we consider all highly liquid investments with an original maturity of less than three months at the date of purchase to be cash equivalents.
FINANCIAL INSTRUMENTS such as swaps, forwards and other contracts to manage the price risks associated with inventories, firm commitments and certain anticipated transactions are used by the Company. We are required to recognize in earnings changes in fair value of these financial instruments that are not offset by changes in the fair value of the inventories, firm commitments and certain anticipated transactions. Fair value is generally defined as the amount at which the financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale.
The effective portion of these hedged transactions will be deferred until the firm commitment or anticipated transaction affects earnings. To qualify as a hedge, the item to be hedged must expose us to commodity or interest rate risk and the hedging instrument must reduce that exposure and meet the hedging requirements of SFAS No. 133. Any contracts held or issued that do not meet the requirements of a hedge (as defined by SFAS No. 133) will
be recorded at fair value on the balance sheet and any changes in that fair value recognized in earnings (using mark-to-market accounting). A contract designated as a hedge of an anticipated transaction that is no longer likely to occur is immediately recognized in earnings.
DOLLAR AMOUNTS presented in the tabulations within the notes to our financial statements are stated in thousands of dollars, unless otherwise indicated.
ENVIRONMENTAL COSTS for remediation are accrued based on the estimates of known remediation requirements. Such accruals are based on management's best estimate of the ultimate costs to remediate the site. Ongoing environmental compliance costs are charged to expense as incurred, and expenditures to mitigate or prevent future environmental contamination are capitalized. Environmental costs, accrued environmental liabilities and expenditures to mitigate or eliminate future environmental contamination for each of the years in the three-year period ended December 31, 2001 were not significant to the consolidated financial statements. Costs of environmental compliance and monitoring aggregated $1.3 million, $1.3 million and $0.9 million for the years ended December 31, 2001, 2000 and 1999, respectively. Our estimated liability for environmental remediation is not discounted.
EXCESS COST OVER UNDERLYING EQUITY IN NET ASSETS (or "excess cost") denotes the excess of our cost (or purchase price) over our underlying equity in the net assets of our investees. We have excess cost associated with our investments in K/D/S Promix L.L.C., Dixie Pipeline Company, Neptune Pipeline Company L.L.C. and Nemo Pipeline Company, LLC. The excess cost of these investments is reflected in our investments in and advances to unconsolidated affiliates for these entities. See Note 4 for a further discussion of the excess cost related to these investments.
EXCHANGES are movements of NGL and petrochemical products and natural gas between parties to satisfy timing and logistical needs of the parties. Volumes borrowed from us under such agreements are included in inventory, and volumes loaned to us under such agreements are accrued as a liability in accrued gas payables.
FEDERAL INCOME TAXES are not provided because we and our predecessors either had elected under provisions of the Internal Revenue Code to be a partnership or Subchapter S Corporation or were organized as other types of pass-through entities for federal income tax purposes. As a result, for federal income tax purposes, our owners are individually responsible for the taxes on their allocable share of our consolidated taxable income. State income taxes are not material to us.
INVENTORIES are valued at the lower of average cost or market (normal trade inventories of natural gas, NGLs and petrochemicals) or using specific identification (volumes dedicated to forward sales contracts).
INTANGIBLE ASSETS include the values assigned to a 20-year natural gas processing agreement and the excess cost of the purchase price over the fair market value of the assets acquired from Mont Belvieu Associates (the "MBA excess cost"), both of which were initially recorded in 1999. Of the intangible values at December 31, 2001, $194.4 million is assigned to the natural gas processing agreement and is being amortized on a straight-line basis over the contract term.
The remaining $7.9 million balance of intangibles relates to the MBA excess cost which has been amortized on a straight-line basis over 20 years. Upon adoption of SFAS No. 142 on January 1, 2002, this amount was reclassified to goodwill and will no longer be amortized but will be subject to periodic impairment testing in accordance with the new standard. For additional information regarding this reclassification and other details pertaining to the adoption of SFAS No. 142, see Note 5.
LONG-LIVED ASSETS are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. We have not recognized any impairment losses for any of the periods presented.
PROPERTY, PLANT AND EQUIPMENT is recorded at cost and is depreciated using the straight-line method over the asset's estimated useful life. Maintenance, repairs and minor renewals are charged to operations as
incurred. The cost of assets retired or sold, together with the related accumulated depreciation, is removed from the accounts, and any gain or loss on disposition is included in income.
Additions and improvements to and major renewals of existing assets are capitalized and depreciated using the straight-line method over the estimated useful life of the new equipment or modifications. These expenditures result in a long-term benefit to the Company. We generally classify improvements and major renewals of existing assets as sustaining capital expenditures and all other capital spending on existing and new assets referred to as expansion capital expenditures.
RESTRICTED CASH includes amounts held by a brokerage firm as margin deposits associated with our financial instruments portfolio and for physical purchase transactions made on the NYMEX exchange. At December 31, 2001, cash and cash equivalents includes $5.8 million of restricted cash related to these requirements.
REVENUE is recognized by our five reportable business segments 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. When the contracts settle (i.e., either physical delivery of product has taken place or the services designated in the contract have been performed), a determination of the necessity of an allowance is made and recorded accordingly.
In our Fractionation segment, we enter into NGL fractionation, isomerization and propylene fractionation tolling arrangements, NGL fractionation in-kind contracts and propylene fractionation merchant contracts. Under our tolling arrangements, we recognize revenue once contract services have been performed. These tolling arrangements typically include a base processing fee per gallon subject to adjustment for changes in natural gas, electricity and labor costs, which are the principal variable costs of fractionation and isomerization operations. At our Norco NGL fractionation facility, certain tolling arrangements involves the retention of a contractually-determined percentage of the NGLs produced for the processing customer in lieu of a cash tolling fee per gallon (i.e., an "in-kind" fee). We recognize revenue from these in-kind contracts when we sell (at market-related prices) and deliver the NGLs retained by our fractionator to customers. In our propylene fractionation merchant contracts, we recognize revenue once the products have been delivered to the customer. These merchant contracts are based upon market-related prices as determined by the individual contracts.
In our Pipelines segment, we enter into pipeline, storage and product loading contracts. Under our liquids pipeline and certain natural gas pipeline throughput contracts, revenue is recognized when volumes have been physically delivered for the customer through the pipeline. Revenue from this type of throughput contract is typically based upon a fixed fee per gallon of liquids or MMBtus of natural gas transported, whichever the case may be, multiplied by the volume delivered. The throughput fee is generally contractual or as regulated by the Federal Energy Regulatory Commission ("FERC"). Additionally, we have merchant contracts associated with our natural gas pipeline business whereby revenue is recognized once a quantity of natural gas has been delivered to a customer. These merchant contracts are based upon market-related prices as determined by the individual contracts.
In our storage contracts, we collect a fee based on the number of days a customer has NGL or petrochemical volumes in storage multiplied by a storage rate for each product. Under these contracts, revenue is recognized ratably over the length of the storage contract based on the storage rates specified in each contract. Revenues from product loading contracts (applicable to EPIK, an unconsolidated affiliate of the Company) are recorded once the loading services have been performed with the loading rates stated in the individual contracts.
As part of our Processing business, we have entered into a significant 20-year natural gas processing agreement with Shell ("Shell Processing Agreement"), whereby we have the right to process Shell's current and future natural gas production (including deepwater developments) from the Gulf of Mexico within the state and federal waters off Texas, Louisiana, Mississippi, Alabama and Florida. In addition to the Shell Processing Agreement, we have contracts to process natural gas for other customers.
Under these contracts, the fee for our natural gas processing services is based upon contractual terms with Shell or other third parties and may be specified as either a cash fee or the retention of a percentage of the NGLs extracted from the natural gas stream. If a cash fee for services is stipulated by the contract, we record revenue once the natural gas has been processed and sent back to Shell or other third parties (i.e., delivery has taken place).
If the contract stipulates that we retain a percentage of the NGLs extracted as payment for its services, revenue is recorded when the NGLs are sold and delivered to third parties. The Processing segment's merchant activities may also buy and sell NGLs in the open market (including forward sales contracts). The revenues recorded for these contracts are recognized upon the delivery of the products specified in each individual contract. Pricing under both types of arrangements is based upon market-related prices plus or minus other determining factors specific to each contract such as location pricing differentials.
The Octane Enhancement segment consists of our equity interest in Belvieu Environmental Fuels ("BEF") which owns and operates a facility that produces motor gasoline additives to enhance octane. This facility currently produces MTBE. BEF's operations primarily occur as a result of a contract with Sunoco, Inc. ("Sun") whereby Sun is obligated to purchase all of the facility's MTBE output at market-related prices through September 2004. Revenue is recognized once the product has been delivered to Sun.
The Other segment is primarily comprised of fee-based marketing services. We perform NGL marketing services for a small number of customers for which we charge a commission. Commissions are based on either a percentage of the final sales price negotiated on behalf of the client or a fixed-fee per gallon based on the volume sold for the client. Revenues are recorded at the time the services are complete.
USE OF ESTIMATES AND ASSUMPTIONS by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period are required for the preparation of financial statements in conformity with accounting principles generally accepted in the United States of America. Our actual results could differ from these estimates.
2. BUSINESS ACQUISITIONS
ACQUISITION OF ACADIAN GAS IN APRIL 2001
On April 2, 2001, we acquired Acadian Gas from an affiliate of Shell, for approximately $226 million in cash using proceeds from the issuance of the $450 million Senior Notes B (see Note 6). Acadian Gas is involved in the purchase, sale, transportation and storage of natural gas in Louisiana. Its assets are comprised of the 438-mile Acadian and 577-mile Cypress natural gas pipelines and a leased natural gas storage facility. Acadian Gas owns an approximate 49.5% of Evangeline which owns a 27-mile natural gas pipeline. We operate the systems. Overall, the Acadian Gas and Evangeline systems are comprised of 1,042 miles of pipeline with an optimal design capacity of 1.1 Bcf/d.
The Acadian Gas and Evangeline systems link supplies of natural gas from Gulf of Mexico production (through connections with offshore pipelines) and various onshore developments to industrial, electrical and local distribution customers primarily located in Louisiana. In addition, these systems have interconnects with twelve interstate and four intrastate pipelines and a bi-directional interconnect with the U.S. natural gas marketplace at the Henry Hub.
The Acadian Gas acquisition was accounted for under the purchase method of accounting and, accordingly, the initial purchase price has been allocated to the assets acquired and liabilities assumed based on their estimated fair values at April 1, 2001 as follows (in millions):
The balances related to the Acadian Gas acquisition included in the consolidated balance sheet dated December 31, 2001 are based upon preliminary information and are subject to change as additional information is obtained. The
initial purchase price is subject to certain post-closing adjustments attributable to working capital items and is expected to be finalized during the first half of 2002.
Historical information for periods prior to April 1, 2001 do not reflect any impact associated with the Acadian Gas acquisition.
PRO FORMA EFFECT OF BUSINESS COMBINATIONS
The following table presents selected unaudited pro forma information for the years ended December 31, 2001 and 2000 as if the acquisition of Acadian Gas had been made as of the beginning of the years presented. This table also incorporates selected unaudited pro forma information for the year ended December 31, 2000 relating to our equity investments in Starfish and Neptune (see Note 4).
The pro forma information is based upon data currently available to and certain estimates and assumptions by management and, as a result, are not necessarily indicative of our financial results had the transactions actually occurred on these dates. Likewise, the unaudited pro forma information is not necessarily indicative of our future financial results.
3. PROPERTY, PLANT AND EQUIPMENT
Our property, plant and equipment and accumulated depreciation are as follows:
Depreciation expense for the years ended December 31, 2001, 2000 and 1999 was $43.4 million, $33.3 million and $22.4 million, respectively. The increase in depreciation expense is primarily due to acquisitions and expansion capital projects over the last three years.
4. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES
We own interests in a number of related businesses that are accounted for under the equity or cost method. The investments in and advances to these unconsolidated affiliates are grouped according to the operating segment to which they relate. For a general discussion of our operating segments, see Note 13.
The following table shows investments in and advances to unconsolidated affiliates at:
The following table shows equity in income (loss) of unconsolidated affiliates for the year ended December 31:
At December 31, 2001, our share of accumulated earnings of equity method unconsolidated affiliates that had not been remitted to us was approximately $7.0 million.
FRACTIONATION SEGMENT:
At December 31, 2001, the Fractionation segment included the following unconsolidated affiliates accounted for using the equity method:
. Baton Rouge Fractionators LLC ("BRF") - an approximate 32.25% interest in an NGL fractionation facility located in southeastern Louisiana.
. Baton Rouge Propylene Concentrator, LLC ("BRPC") - a 30.0% interest in a propylene concentration unit located in southeastern Louisiana.
. K/D/S Promix LLC ("Promix") - a 33.33% interest in an NGL fractionation facility and related storage assets located in south Louisiana. Our investment includes excess cost over the underlying equity in the net assets of Promix of $8.0 million. The excess cost, which relates to plant assets, is being amortized against our share of Promix's earnings over a period of 20 years, which is the estimated useful life of the plant assets that gave rise to the difference. The unamortized balance of excess cost was $7.0 million at December 31, 2001.
The combined balance sheet information for the last two years and results of operations data for the last three years of the Fractionation segment's equity method investments are summarized below. As used in the following tables, gross operating margin for equity investments represents operating income before depreciation and amortization expense (both on operating assets) and selling, general and administrative costs.
PIPELINES SEGMENT:
At December 31, 2001, our Pipelines operating segment included the following unconsolidated affiliates accounted for using the equity method:
. EPIK Terminalling L.P. and EPIK Gas Liquids, LLC (collectively, "EPIK") - a 50% aggregate interest in a refrigerated NGL marine terminal loading facility located in southeast Texas. We own 50% of EPIK Terminalling L.P. which owns 99% of such facilities. In addition, we own 50% of EPIK Gas Liquids, LLC which owns 1% of such facilities. We do not exercise control over these entities; therefore, we are precluded from consolidating such entities into our financial statements.
. Wilprise Pipeline Company, LLC ("Wilprise") - a 37.35% interest in an NGL pipeline system located in southeastern Louisiana.
. Tri-States NGL Pipeline LLC ("Tri-States") - an aggregate 33.33% interest in an NGL pipeline system located in Louisiana, Mississippi and Alabama.
. Belle Rose NGL Pipeline LLC ("Belle Rose") - a 41.67% interest in an NGL pipeline system located in south Louisiana.
. Dixie Pipeline Company ("Dixie") - an aggregate 19.88% interest in a 1,301- mile propane pipeline and associated facilities extending from Mont Belvieu, Texas to North Carolina. Our investment includes excess cost over the underlying equity in the net assets of Dixie of $37.4 million. The excess cost, which relates to pipeline assets, is being amortized against our share of Dixie's earnings over a period of 35 years, which is the estimated useful life of the pipeline assets that gave rise to the difference. The unamortized balance of excess cost over the underlying equity in the net assets of Dixie was $35.7 million at December 31, 2001.
. Starfish Pipeline Company LLC ("Starfish") - a 50% interest in a natural gas gathering system and related dehydration and other facilities located in south Louisiana and the Gulf of Mexico offshore Louisiana.
. Neptune Pipeline Company LLC ("Neptune") - a 25.67% interest in the natural gas gathering and transmission systems owned by Manta Ray Offshore Gathering Company, LLC and Nautilus Pipeline Company LLC located in the Gulf of Mexico offshore Louisiana.
. Nemo Gathering Company, LLC ("Nemo") - a 33.92% interest in a natural gas gathering system located in the Gulf of Mexico offshore Louisiana that became operational in August 2001.
. Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp. (collectively, "Evangeline") - an approximate 49.5% aggregate interest in a natural gas pipeline system located in south Louisiana. We acquired our interest in Evangeline as a result of the Acadian Gas acquisition (see Note 2 for a description of this acquisition).
The combined balance sheet information for the last two years and results of operations data for the last three years of the Pipelines segment's equity method investments are summarized below:
Equity investments in Gulf of Mexico natural gas pipeline systems in January
On January 29, 2001, we acquired a 50% equity interest in Starfish which owns the Stingray natural gas pipeline system and a related natural gas dehydration facility. The Stingray system is a 379-mile, FERC-regulated natural gas pipeline system that transports natural gas and condensate from certain production areas located in the Gulf of Mexico offshore Louisiana to onshore transmission systems located in south Louisiana. The natural gas dehydration facility is connected to the onshore terminal of the Stingray system in south Louisiana. The optimal design capacity of the Stingray pipeline is 1.2 Bcf/d. Shell is the operator of these systems and owns the remaining equity interests
in Starfish.
In addition to Starfish, we acquired a 25.67% interest in Ocean Breeze Pipeline Company ("Ocean Breeze") and Neptune and a 33.92% interest in Nemo. Ocean Breeze and Neptune collectively owned the Manta Ray and Nautilus natural gas pipeline systems located in the Gulf of Mexico offshore Louisiana. The Manta Ray system comprises approximately 235 miles of unregulated pipelines and related equipment with an optimal design capacity of 0.75 Bcf/d and the Nautilus system comprises approximately 101 miles of FERC-regulated pipelines with an optimal design capacity of 0.6 Bcf/d. The Nemo system, which became operational in August 2001, comprises a 24-mile natural gas pipeline with an optimal design capacity of 0.3 Bcf/d. Like Stingray, Shell is the operator of the Manta Ray and Nemo systems. Shell is the administrative agent for Nautilus. In November 2001, Ocean Breeze was merged into Neptune with the Company retaining its 25.67% interest in Neptune. Shell and Marathon are the co-owners of Neptune and Shell owns the remaining interest in Nemo.
The cash purchase price of the Starfish interest was $25 million with the purchase price of the Ocean Breeze, Neptune and Nemo interests being $87 million. The investments were paid for using proceeds from the issuance of the $450 million Senior Notes B (see Note 6).
Our investment in Neptune and Nemo includes excess cost over the underlying equity in the net assets of these entities of $13.5 million. The excess cost, which relates to pipeline assets, is being amortized against our share of earnings from Neptune and Nemo over a period of 35 years, which is the estimated useful life of the pipeline assets that gave rise to the difference. The unamortized balance of excess cost over the underlying equity in the net assets of Neptune and Nemo was $12.4 million and $0.7 million, respectively, at December 31, 2001.
Historical information for periods prior to January 1, 2001 do not reflect any impact associated with our equity investments in Starfish, Neptune and Nemo.
OCTANE ENHANCEMENT SEGMENT:
At December 31, 2001, the Octane Enhancement segment included our 33.33% interest in Belvieu Environmental Fuels ("BEF"), a facility located in southeast Texas that produces motor gasoline additives to enhance octane. The BEF facility currently produces MTBE. The production of MTBE is driven by oxygenated fuel programs enacted under the federal Clean Air Act Amendments of 1990 and other legislation and as an additive to increase octane in motor gasoline. Any changes to these oxygenated fuel programs that enable localities to elect to not participate in these programs, to lessen the requirements for oxygenates or to favor the use of non-isobutane based oxygenated fuels reduce the demand for MTBE and could have an adverse effect on our results of operations.
In recent years, MTBE has been detected in water supplies. The major source of the ground water contamination appears to be leaks from underground storage tanks. Although these detections have been limited and the great majority have been well below levels of public health concern, there have been calls for the phase-out of MTBE in motor gasoline in various federal and state governmental agencies and advisory bodies.
In light of these regulatory developments, the owners of BEF have been formulating a contingency plan for use of the BEF facility if MTBE were banned or significantly curtailed. Management is exploring a possible conversion of the BEF facility from MTBE production to alkylate production. The Company believes that if MTBE usage is banned or significantly curtailed, the motor gasoline industry would need a substitute additive to maintain octane levels in motor gasoline and that alkylate would be an attractive substitute. Depending upon the type of alkylate process chosen and the level of alkylate production desired, the cost to convert the facility from MTBE production to alkylate production would range from $20 million to $90 million, with our share of these costs ranging from $6.7 million to $30 million.
Balance sheet information for the last two years and results of operations data for the last three years for BEF are summarized below:
PROCESSING SEGMENT:
At December 31, 2001, our investments in and advances to unconsolidated affiliates also includes Venice Energy Services Company, LLC ("VESCO"). The VESCO investment consists of a 13.1% interest in a company owning a natural gas processing plant, fractionation facilities, storage, and gas gathering pipelines in Louisiana. We account for this investment using the cost method.
5. RECENTLY ISSUED ACCOUNTING STANDARDS
In June 2001, the FASB issued two new pronouncements: SFAS No. 141, "Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS No. 141 prohibits the use of the pooling-of-interest method for business combinations initiated after June 30, 2001 and also applies to all business combinations accounted for by the purchase method that are completed after June 30, 2001. There are also transition provisions that apply to business combinations completed before July 1, 2001, that were accounted for by the purchase method. SFAS No. 142 is effective for our fiscal year that began January 1, 2002 for all goodwill and other intangible assets recognized in our consolidated balance sheet at that date, regardless of when those assets were initially recognized. We adopted SFAS No. 141 on January 1, 2002.
Within six months of our adoption of SFAS No. 142 (by June 30, 2002), we will have completed a transitional impairment review to identify if there is an impairment to the December 31, 2001 recorded goodwill or intangible assets of indefinite life using a fair value methodology. Professionals in the business valuation industry will be consulted to validate the assumptions used in such methodologies. Any impairment loss resulting from the transitional impairment test will be recorded as a cumulative effect of a change in accounting principle for the quarter ended June 30, 2002. Subsequent impairment losses will be reflected in operating income in the Statements of Consolidated Operations.
At January 1, 2002, our intangible assets included the values assigned to the 20-year Shell natural gas processing agreement (the "Shell agreement") and the excess cost of the purchase price over the fair market value of the assets acquired from Mont Belvieu Associates (the "MBA excess cost"), both of which were initially recorded in 1999. The value of the Shell agreement ($194.4 million net book value at December 31, 2001) is being amortized on a straight- line basis over its contract term. Likewise, the MBA excess cost ($7.9 million net book value at December
31, 2001) was being amortized on a straight-line basis over 20 years. Based upon initial interpretations of the new accounting standards, we anticipate that the intangible asset related to the Shell agreement will continue to be amortized over its contract term ($11.1 million annually for 2002 through July 2019); however, the MBA excess cost will be reclassified to goodwill in accordance with the new standard and its amortization will cease (currently, $0.5 million annually). This goodwill would then be subject to impairment testing as prescribed in SFAS No. 142. We are continuing to evaluate the complex provisions of SFAS No. 142 and will fully adopt the standard during 2002 within the prescribed time periods.
In addition to SFAS No. 141 and No. 142, the FASB also issued SFAS No. 143, "Accounting for Asset Retirement Obligations", in June 2001. This statement establishes accounting standards for the recognition and measurement of a liability for an asset retirement obligation and the associated asset retirement cost. This statement is effective for our fiscal year beginning January 1, 2003. We are continuing to evaluate the provisions of this statement. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets". This statement addresses financial accounting and reporting for the impairment and/or disposal of long-lived assets. We adopted this statement effective January 1, 2002 and determined that it will have no material impact on our financial statements as of that date.
6. LONG-TERM DEBT
Our long-term debt consisted of the following at:
Long-term debt does not reflect the $250 million Multi-Year Credit Facility or the $150 million 364-Day Credit Facility. No amount was outstanding under either of these two revolving credit facilities at December 31, 2001. See below for a complete description of these facilities.
At December 31, 2001, we had a total of $75 million of standby letters of credit capacity under our $250 Million Multi-Year Credit Facility of which $2.4 million was outstanding.
EPPLP, on a stand-alone basis, acts as guarantor of certain of our debt obligations. This parent-subsidiary guaranty provision exists under our Senior Notes, MBFC Loan and two current revolving credit facilities.
SENIOR NOTES A. On March 13, 2000, we completed a public offering of $350 million in principal amount of 8.25% fixed-rate Senior Notes due March 15, 2005 at a price to the public of 99.948% per Senior Note (the "Senior Notes A"). These notes were issued to retire certain revolving credit loan balances that were created as a result of the TNGL acquisition and other general partnership activities.
The Senior Notes A are subject to a make-whole redemption right. The notes are an unsecured obligation and rank equally with existing and future unsecured and unsubordinated indebtedness and senior to any future subordinated indebtedness. The notes are guaranteed by EPPLP through an unsecured and unsubordinated guarantee and were
issued under an indenture containing certain restrictive covenants. These covenants restrict our ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions. We were in compliance with these restrictive covenants at December 31, 2001.
SENIOR NOTES B. On January 24, 2001, we completed a public offering of $450 million in principal amount of 7.50% fixed-rate Senior Notes due February 1, 2011 at a price to the public of 99.937% per Senior Note (the "Senior Notes B"). These notes were issued to finance the acquisition of Acadian Gas, Ocean Breeze, Neptune, Nemo and Starfish; to cover construction costs of certain NGL pipelines and related projects; and to fund other general partnership activities.
The Senior Notes B were issued under the same indenture as Senior Notes A and therefore are subject to similar terms and restrictive covenants. The Senior Notes B are guaranteed by EPPLP through an unsecured and unsubordinated guarantee. We were in compliance with the restrictive covenants at December 31, 2001.
MBFC LOAN. On March 27, 2000, we executed a $54 million loan agreement with the Mississippi Business Finance Corporation ("MBFC") having a 8.70% fixed-rate and a maturity date of March 1, 2010. In general, the proceeds from this loan were used to retire certain revolving credit loan balances attributable to acquiring and constructing the Pascagoula, Mississippi natural gas processing facility.
The MBFC Loan is subject to a make-whole redemption right and is guaranteed by EPPLP through an unsecured and unsubordinated guarantee. The indenture agreement contains an acceleration clause whereby the outstanding principal and interest on the loan may become due and payable if our credit ratings decline below a Baa3 rating by Moody's (currently Baa2) and below a BBB- rating by Standard and Poors (currently BBB). Under these circumstances, the trustee (as defined in the indenture agreement) may, and if requested to do so by holders of at least 25% in aggregate of the principal amount of the outstanding underlying bonds, shall accelerate the maturity of the MBFC Loan, whereby the principal and all accrued interest would become immediately due and payable. If such an event occurred, we would have the option (a) to redeem the MBFC loan or (b) to provide an alternate credit agreement (as defined in the indenture agreement) to support our obligation under the MBFC loan, with both options exercisable within 120 days of receiving notice of the decline in our credit ratings from the ratings agencies.
The loan agreement contains certain covenants including maintaining appropriate levels of insurance on the Pascagoula facility and restrictions regarding mergers. We were in compliance with the restrictive covenants at December 31, 2001.
MULTI-YEAR CREDIT FACILITY. On November 17, 2000, we entered into a $250 million five-year revolving credit facility that includes a sublimit of $75 million for letters of credit. The November 17, 2005 maturity date may be extended for one year at our option with the consent of the lenders, subject to the extension provisions in the agreement. We can increase the amount borrowed under this facility, with the consent of the Administrative Agent (whose consent may not be unreasonable withheld), up to an amount not exceeding $350 million by adding to the facility one or more new lenders and/or increasing the commitments of existing lenders, so long as the aggregate amount of the funds borrowed under this credit facility and the 364-Day Credit Facility (described below) does not exceed $500 million. No lender will be required to increase its original commitment, unless it agrees to do so at its sole discretion. This credit facility is guaranteed by EPPLP through an unsecured guarantee.
Proceeds from this credit facility will be used for working capital, acquisitions and other general partnership purposes. No amount was outstanding for this credit facility at December 31, 2001.
Our obligations under this bank credit facility are unsecured general obligations and are non-recourse to the General Partner. As defined within the agreement, borrowings under this bank credit facility will generally bear interest at either (i) the greater of the Prime Rate or the Federal Funds Effective Rate plus one-half percent or (ii) a Eurodollar Rate plus an applicable margin or (iii) a Competitive Bid Rate. We elect the basis for the interest rate at the time of each borrowing.
The credit agreement contains various affirmative and negative covenants applicable to the Company to, among other things, (i) incur certain indebtedness, (ii) grant certain liens, (iii) enter into certain merger or consolidation transactions and (iv) make certain investments. In addition, we may not directly or indirectly make any distribution
in respect of its partnership interests, except those payments in connection with the Buy-Back Program (not to exceed $30 million in the aggregate, see Note 7) and distributions from Available Cash from Operating Surplus, both as defined within the agreement.
The credit agreement also requires that we satisfy certain financial covenants at the end of each fiscal quarter. As defined within the agreement, we (i) must maintain Consolidated Net Worth of $750 million and (ii) not permit our ratio of Consolidated Indebtedness to Consolidated EBITDA, including pro forma adjustments (as defined within the agreement), for the previous four quarter period to exceed 4.0 to 1.0. We were in compliance with the restrictive covenants at December 31, 2001.
364-DAY CREDIT FACILITY. In conjunction with the Multi-Year Credit Agreement, we entered into a 364-day $150 million revolving bank credit facility. In November 2001, we and our lenders amended the revolving credit agreement to extend the maturity date to November 15, 2002 with the option to convert any revolving credit balance outstanding at November 15, 2002 to a one-year term loan.
We can increase the amount borrowed under this facility, with the consent of the Administrative Agent (whose consent may not be unreasonably withheld), up to an amount not exceeding $250 million by adding to the facility one or more new lenders and/or increasing the commitments of existing lenders, so long as the aggregate amount of the funds borrowed under this credit facility and the Multi- Year Credit Facility do not exceed $500 million. No lender will be required to increase its original commitment, unless it agrees to do so at its sole discretion. This credit facility is guaranteed by EPPLP through an unsecured guarantee.
Our obligations under this bank credit facility are unsecured general obligations and are non-recourse to the General Partner. As defined within the agreement, borrowings under this bank credit facility will generally bear interest at either (i) the greater of the Prime Rate or the Federal Funds Effective Rate plus one-half percent or (ii) a Eurodollar Rate plus an applicable margin or (iii) a Competitive Bid Rate. We elect the basis for the interest rate at the time of each borrowing.
Proceeds from this credit facility will be used for working capital, acquisitions and other general partnership purposes. No amount was outstanding for this credit facility at December 31, 2001.
Limitations on certain actions by the Company and financial condition covenants of this bank credit facility are substantially consistent with those existing for the Multi-Year Credit Facility as described previously. We were in compliance with the restrictive covenants at December 31, 2001.
February 2001 Registration Statement
On February 23, 2001, we filed a $500 million universal shelf registration (the "February 2001 Shelf") covering the issuance of an unspecified amount of equity securities of the Limited Partner and public debt of the Company or a combination thereof. We expect to use the net proceeds from any sale of securities for future business acquisitions and other general corporate purposes, such as working capital, investments in subsidiaries, the retirement of existing debt and/or the repurchase of Common Units or other securities. The exact amounts to be used and when the net proceeds will be applied to partnership purposes will depend on a number of factors, including our funding requirements and the availability of alternative funding sources. We routinely review acquisition opportunities.
Increase in fair value of fixed-rate debt
Upon adoption of SFAS No. 133 (see Note 11), we recorded a $2.3 million fair value adjustment associated with our fixed-rate debt. The fair value adjustment is not a cash obligation of the Company and does not alter the amount of our indebtedness. Under the specific rules of SFAS 133, the fair value adjustment will be amortized over the remaining life of the fixed-rate debt to which it is associated, which approximates 10 years. See "Interest Rate Swaps" under Note 11 for additional information concerning this item.
Impact of interest rate swap agreements upon interest expense
During 2001 and 2000, we utilized interest rate swap agreements to manage debt service costs by converting a portion of our fixed-rate debt into variable-rate debt. Income or losses sustained on these financial instruments are reflected as a component of consolidated interest expense. At December 31, 2000, we had three interest rate swaps outstanding having a combined notional value of $154 million (attributable to fixed-rate debt) with an estimated fair value of $2.0 million. Due to the early termination of two of the swaps, the notional amount and fair value of the remaining swap was $54 million and $2.3 million (an asset), respectively, at December 31, 2001.
We recorded as a reduction of interest expense $13.2 million from our interest rates swaps during 2001 and $10.0 million during 2000. The income recognized in 2001 from these swaps includes $2.3 the million in non-cash mark-to-market income at December 31, 2001 (attributable to the sole remaining swap). The remaining $10.9 million has been realized. No mark-to-market income was recorded prior to the implementation of SFAS No. 133. For additional information regarding our interest rate swaps, see Note 11.
7. CAPITAL STRUCTURE
We are owned 98.9899% by our Limited Partner and 1.0101% by our General Partner. For purposes of maintaining partner capital accounts, our partnership agreement generally specifies that items of income or loss shall be allocated among the partners in accordance with their respective ownership percentages. Net losses are first allocated to the partners in accordance with their respective percentages to the extent that the allocations do not cause the Limited Partner to have a deficit balance in its capital account. Any net loss not allocated to the Limited Partner is allocated to the General Partner. Normal allocations of net income to percentage interests are done only, however, after giving effect to any priority income allocations to the General Partner in an amount equal to any aggregate net losses incurred by the General Partner for all previous years. For the years ended December 31, 2001, 2000 and 1999, the allocation of earnings has been based solely on the respective ownership interests of the partners with no priority income allocations being necessary.
Our partnership agreement requires that we distribute 100% of the "Available Cash" (as defined within the agreement) to the partners within 45 days following the end of each calendar quarter in accordance with their respective ownership interests. Available Cash consists generally of cash receipts less cash disbursements, net of changes in reserves (as determined by the General Partner in its sole discretion). Our distributions to partners during the three years ended December 31, 2001, 2000 and 1999 were $167.0 million, $141.5 million and $112.9 million.
PARENT'S UNITS ACQUIRED BY TRUST. During the first quarter of 1999, we established a revocable grantor trust, EPOLP 1999 Grantor Trust or the "1999 Trust", to fund potential future obligations under the EPCO Agreement with respect to EPCO's long-term incentive plan (through the exercise of options granted to EPCO employees or directors of the General Partner). The Common Units purchased by the 1999 Trust are accounted for in a manner similar to treasury stock under the cost method of accounting. The 1999 Trust purchased 267,200 Common Units in 1999 at a cost of $4.7 million and 396,400 Common Units in 2001 at a cost of $18.0 million.
In November 2001, the 1999 Trust sold 500,000 Common Units previously held in treasury to EPCO for $22.6 million. The sales price of the treasury Common Units sold exceeded the purchase price of the Treasury Units by $6.0 million and has been credited to Partners' Equity accounts in a manner similar to additional paid-in capital.
BUY-BACK PROGRAM. In 2000, the General Partner authorized the Limited Partner to repurchase and retire up to 1,000,000 of its publicly-held Common Units. The repurchase and retirements will be made during periods of temporary market weakness at price levels that would be accretive to its remaining Unitholders.
In September 2001, the General Partner approved a modification to the Buy-Back Program that allows both the Limited Partner (on a stand-alone basis) and the 1999 Trust to repurchase Common Units under the program. Under the terms of the modification, purchases made by the Limited Partner will continue to be retired whereas purchases made by the 1999 Trust will remain outstanding and not be retired. The Common Units purchased by the 1999 Trust will be accounted for as Treasury Units.
During 2000, the Company repurchased and retired 28,400 Common Units under this program. The 1999 Trust purchased 396,400 Common Units under this program in 2001. At December 31, 2001, 575,200 Common Units could be repurchased and/or retired under this program on a pre-split basis (see Note 14 for a discussion of a subsequent event involving the declaration of a two-for-one split of Common Units that will occur in May 2002).
8. RELATED PARTY TRANSACTIONS
We have no employees. All management, administrative and operating functions are performed by employees of EPCO pursuant to the EPCO Agreement (in effect since July 1998). Under the terms of the EPCO Agreement, EPCO agreed to:
. employ the personnel necessary to manage our business and affairs (through the General Partner); . employ the operating personnel involved our business for which we reimburse EPCO at cost (based upon EPCO's actual salary costs and related fringe benefits); . allow us to participate as named insureds in EPCO's current insurance program with the costs being allocated among the parties on the basis of formulas set forth in the agreement; . grant us an irrevocable, non-exclusive worldwide license to use all of the EPCO trademarks and trade names; . indemnify us against any losses resulting from certain lawsuits; and to . sublease to us all of the equipment which it holds pursuant to operating leases relating to an isomerization unit, a deisobutanizer tower, two cogeneration units and approximately 100 railcars for one dollar per year and to assign its' purchase option under such leases to us. EPCO remains liable for the lease payments associated with these assets.
Operating costs and expenses (as shown in the audited Statements of Consolidated Operations) treat the full amount of lease payments being made by EPCO as a non- cash operating expense (with the offset to Partners' Equity on the Consolidated Balance Sheet). In addition, operating costs and expenses include compensation charges for EPCO's employees who operate the facilities.
Pursuant to the EPCO Agreement, we reimburse EPCO for our portion of the costs of certain of its employees who manage our business and affairs. In general, our reimbursement of EPCO's expense associated with administrative positions that were active at the time of our initial public offering in July 1998 is capped by the Administrative Services Fee that we pay (currently at $16 million annually). The General Partner, with the approval and consent of the Audit and Conflicts Committee, may agree to annual increases of such fee up to ten percent per year during the 10-year term of the EPCO Agreement. Any difference between the actual costs of this "pre-expansion" group (including those associated with equity- based awards granted to certain individuals within this group) and the Administrative Services Fee will be retained by EPCO (i.e., EPCO solely bears any shortfall in reimbursement for this group).
Beginning in January 2000, we began reimbursing EPCO for our share of the compensation of administrative personnel that it had hired in response to our expansion and business development activities (through the construction of new facilities, business acquisitions or the like). EPCO began hiring "expansion" administrative personnel during 1999 in connection with the TNGL acquisition and other development activities. In general, we reimburse EPCO for our share of its compensation expense associated with these "expansion" administrative positions, including those costs attributable to equity-based awards.
The following table summarizes of the Administrative Services Fee paid to EPCO during the last three years. In addition, the table shows the total compensation reimbursed to EPCO for operations personnel and "expansion" administrative positions.
We elected to prepay EPCO a discounted amount of $15.7 million for the 2002 Administrative Services Fee in December 2001 (the undiscounted amount was $16.0 million). We will owe EPCO for any undiscounted amount above the $16.0 million if the General Partner approves an increase in the fee during 2002.
Other related party and similar transactions with EPCO or its affiliates
EPCO also operates the facilities owned by BEF and EPIK and charges them for actual salary costs and related fringe benefits. In addition, EPCO is paid a management fee by these entities in lieu of reimbursement for the actual cost of providing management services; such charges aggregated $0.8 for 2001, $0.9 million for 2000 and $0.8 million in 1999.
We have entered into an agreement with EPCO to provide trucking services related to the loading and transportation of NGL products. EPCO charged us $9.0 million in 2001, $7.9 million in 2000 and $5.7 million in 1999 for these services. On occasion, in the normal course of business, we may engage in transactions with EPCO involving the buying and selling of NGL products. No such sales or purchases were transacted with EPCO during 2001 and 2000; however, we purchased a net $20.6 million of such products from EPCO during 1999.
In addition, trust affiliates of EPCO (Enterprise Products 1998 Unit Option Plan Trust and the Enterprise Products 2000 Rabbi Trust) purchase Common Units of the Limited Partner for the purpose of granting options to EPCO management and certain key employees (many of whom also serve in similar capacities with the General Partner). During 2001, these trusts purchased 211,518 Common Units on the open market or through privately negotiated transactions. At December 31, 2001, these trusts owned a total of 1,461,518 Common Units. In November 2001, EPCO directly purchased 500,000 Common Units at market prices from the Trust on behalf of a key executive.
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.
Relationships with Shell
We have an extensive and ongoing relationship with Shell as a partner, customer and vendor. Shell, through its subsidiary Shell US Gas & Power LLC, owns approximately 23.2% of our Limited Partner and 30.0% of the General Partner. Currently, three members of the Board of Directors of the General Partner are employees of Shell.
The most significant contract affecting our natural gas processing business is the 20-year Shell Processing Agreement which grants us the right to process Shell's current and future production from the Gulf of Mexico within the state and federal waters off Texas, Louisiana, Mississippi, Alabama and Florida (on a keepwhole basis). This includes natural gas production from deepwater developments. Shell is the largest oil and gas producer and holds one of the largest lease positions in the deepwater Gulf of Mexico. Generally, this contract has the following rights and obligations:
. the exclusive right to process any and all of Shell's Gulf of Mexico natural gas production from existing and future dedicated leases; plus
. the right to all title, interest and ownership in the mixed NGL stream extracted by our gas plants from Shell's natural gas production from such leases; with . the obligation to deliver to Shell the natural gas stream after the mixed NGL stream is extracted.
Apart from operating expenses arising from the Shell Processing Agreement, we also sell NGL and petrochemical products to Shell.
The following table shows the related party amounts by major category in the Company's Statements of Consolidated Operations for the last three years. The table also shows the total amounts paid to EPCO separately under the EPCO Agreement for employee-related costs for the last three years.
9. COMMITMENTS AND CONTINGENCIES
REDELIVERY COMMITMENTS
From time to time, we store NGL, petrochemical and natural gas volumes for third parties under various processing, storage and similar agreements. Under the terms of these agreements, we are generally required to redeliver to the owner volumes on demand. We are insured for any physical loss of such volumes due to catastrophic events. At December 31, 2001, NGL and petrochemical volumes aggregating 320 million gallons were due to be redelivered to their owners along with 887,414 MMBtus of natural gas.
LEASE COMMITMENTS
We lease certain equipment and processing facilities under noncancelable and cancelable operating leases. Minimum future rental payments on such leases with terms in excess of one year at December 31, 2001 are as follows:
2002 $ 5,115 2003 4,862 2004 4,324 2005 279 2006 181 Thereafter 1,077 ------- Total minimum obligations $15,838 =======
The operating lease commitments shown above exclude the expense associated with various equipment leases contributed to us by EPCO at our formation for which EPCO has retained the liability. During 2001, 2000 and 1999, our non-cash lease expense associated with these EPCO "retained" leases was $10.4 million, $10.6 million and $10.6 million, respectively.
Lease and rental expense (including Retained Leases) included in operating income for the years ended December 31, 2001, 2000 and 1999 was approximately $23.4 million, $21.2 million and $20.6 million. EPCO has assigned us the purchase options associated with the retained leases. Should we decide to exercise our purchase options under the retained leases, up to $26.0 million will be payable in 2004, $3.4 million in 2008 and $3.1 million in 2016.
PURCHASE COMMITMENTS
Gas purchase commitments. We have long-term purchase commitments for NGL products and related-streams including natural gas with several suppliers. The purchase prices contained within these contracts approximate market value at the time of delivery. The following table shows our long-term volume commitments under these contracts.
Capital spending commitments. As of December 31, 2001, we had capital expenditure commitments totaling approximately $5.3 million, of which $0.3 million relates to our portion of internal growth projects of unconsolidated affiliates.
LITIGATION
We are indemnified for any litigation pending as of the date of our formation by EPCO. We are sometimes named as a defendant in litigation relating to our normal business operations. 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. Except as noted below, 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. Our operations are subject to the Clean Air Act and comparable state statutes. Amendments to the Clean Air Act were adopted in 1990 and contain provisions that may result in the imposition of certain pollution control requirements with respect to air emissions from our pipelines and processing and storage facilities. For example, the Mont Belvieu processing and storage facilities are located in the Houston-Galveston ozone non-attainment area, which is categorized as a "severe" area and, therefore, is subject to more restrictive regulations for the issuance of air permits for new or modified facilities. The Houston- Galveston area is among nine areas of the country in this "severe" category. One of the other consequences of this non-attainment status is the potential imposition of lower limits on emissions of certain pollutants, particularly oxides of nitrogen which are produced through combustion, as in the gas turbines at the Mont Belvieu complex.
Regulations imposing more strict air emissions requirements on existing facilities in the Houston-Galveston area were issued in December 2000. These regulations may necessitate extensive redesign and modification of our Mont Belvieu facilities to achieve the air emissions reductions needed for federal Clean Air Act compliance. The technical practicality and economic reasonableness of these regulations have been challenged under state law in litigation filed on January 19, 2001, against the Texas Natural Resource Conservation Commission and its principal officials in the District Court of Travis County, Texas, by a coalition of major Houston-Galveston area industries, including us. Until this litigation is resolved, the precise level of technology to be employed and the cost for modifying the facilities to achieve the required amount of reductions cannot be determined. Currently, the litigation
has been stayed by agreement of the parties pending the outcome of expanded, cooperative scientific research to more precisely define sources and mechanisms of air pollution in the Houston-Galveston area. Completion of this research is anticipated in mid-2002.
10. SUPPLEMENTAL CASH FLOWS DISCLOSURE
The net effect of changes in operating assets and liabilities is as follows:
On April 1, 2001, we paid approximately $225.7 million in cash to Shell to acquire Acadian Gas. This acquisition was recorded using the purchase method of accounting and as a result the initial purchase price has been allocated to various balance sheet asset and liability accounts. For additional information regarding the acquisition of Acadian Gas (including the allocation of the purchase price), see Note 2.
On August 1, 1999, we paid $166 million in cash and our Limited Partner issued 14.5 million non-distribution bearing, convertible Special Units (valued at $210.4 million at time of issuance) to Shell in connection with the TNGL acquisition. Also, the Limited Partner issued 6.0 million additional non- distribution bearing, convertible Special Units to Shell based on Shell having met certain performance criteria in calendar years 2000 and 2001. Of the 6.0 million additional Special Units issued, 3.0 million were issued in 2000 and 3.0 million during 2001. The value of the Special Units issued in 2000 was $55.2 million while the value of those issued during 2001 was $117.1 million, both values determined using present value techniques. The $172.3 million combined value of these two issues increased the overall purchase price of the TNGL acquisition and was allocated to the intangible asset, Shell Processing Agreement. The combined $382.7 million value of the Special Units issued to Shell was accounted for as a non-cash contribution to us by our Limited Partner.
In addition, during 2000, we increased the value of the Shell Processing Agreement by $25.2 million for non-cash purchase accounting adjustments related to the acquisition. The offset to such adjustment was various working capital accounts. With all adjustments completed (including those of the Special Units discussed above), the final purchase price of TNGL increased to $528.8 million.
On July 1, 1999, we paid approximately $42.1 million in cash to EPCO and Kinder Morgan and assumed approximately $4 million of debt in connection with the acquisition of an additional interest in the Mont Belvieu NGL fractionation facility.
As a result of our adoption of SFAS No. 133 on January 1, 2001, we record various financial instruments relating to commodity positions and interest rate swaps at their respective fair values using mark-to-market accounting. During 2001, we recognized a net $5.7 million in non-cash mark-to-market income related to increases in the fair value of these financial instruments. See Note 11 for additional information on our financial instruments.
11. FINANCIAL INSTRUMENTS
We are exposed to financial market risks, including changes in commodity prices in our natural gas and NGL businesses and in interest rates with respect to a portion of our debt obligations. 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, primarily in our Processing segment. In general, the types of risks hedged are those relating to the variability of future earnings and cash flows caused by changes in commodity prices and interest rates. As a matter of policy, we do not use financial instruments for speculative (or trading) purposes.
Our disclosure of fair value estimates are determined using available market information and appropriate valuation methodologies. We must use considerable judgment, however, in interpreting market data and to develop the related estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize upon disposition of the financial instruments. The use of different market assumptions and/or estimation methodologies may have a material effect on our estimates of fair value.
COMMODITY FINANCIAL INSTRUMENTS
Our Processing and Octane Enhancement segments are directly exposed to commodity price risk through their respective business operations. The prices of natural gas, NGLs and MTBE 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 its Processing segment, we may enter into swaps, forwards, commodity futures, options and other commodity financial instruments with similar characteristics that are permitted by contract or business custom to be settled in cash or with another financial instrument. The primary purpose of these risk management activities is to hedge exposure to price risks associated with natural gas, NGL production and inventories, firm commitments and certain anticipated transactions. We do not hedge our exposure to the MTBE markets. Also, in its Pipelines segment, we may utilize a limited number of commodity financial instruments to manage the price Acadian Gas charges certain of its customers for natural gas.
We have adopted a commercial policy to manage our exposure to the risks of its 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 General Partner. We 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 18 months. The General Partner oversees the 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.
On January 1, 2001, we adopted SFAS No. 133 (as amended and interpreted) which required us to recognize the fair value of our commodity financial instrument portfolio on the balance sheet based upon then current market conditions. The fair market value of the then outstanding commodity financial instruments portfolio was a net payable of $42.2 million (the "cumulative transition adjustment") with an offsetting equal amount recorded in Other Comprehensive Income ("OCI"). The amount in OCI was fully reclassified to earnings during 2001.
At December 31, 2001, we had open commodity financial instruments that settle at different dates extending through December 2002. We routinely review our outstanding instruments in light of current market conditions. If market conditions warrant, some 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.
These commodity financial instruments may not qualify for hedge accounting treatment under the specific guidelines of SFAS No. 133 because of ineffectiveness. A hedge is normally regarded as effective if, among other things, at inception and throughout the term of the financial instrument, we could expect changes in the fair value of the hedged item to be almost fully offset by the changes in the fair value of the financial instrument. Currently, a majority of our commodity financial instruments do not qualify as effective hedges under the guidelines of SFAS No. 133, with the result being that changes in the fair value of these positions are recorded on the balance sheet and in earnings through mark-to-market accounting. The use of mark-to-market accounting for these commodity financial instruments results in a degree of non-cash earnings volatility that is dependent upon changes in the underlying commodity prices. Even though these financial instruments do not qualify for hedge accounting treatment under the specific guidelines of SFAS No. 133, we continue to view these financial instruments as hedges inasmuch as this was the intent when such contracts were executed. This characterization is consistent with the actual economic performance of these contracts to date and we expect these financial instruments to continue to mitigate (or offset) commodity price risk in future. The specific accounting for these contracts, however, is consistent with the requirements of SFAS No. 133.
We recognized income of $101.3 million in 2001 from our commodity hedging activities that is treated as a decrease of operating costs and expenses in the Statements of Consolidated Operations. Of this amount, $95.7 million was realized during 2001. The remaining $5.6 million represents mark-to-market income on positions open at December 31, 2001 (based on market prices at that date).
INTEREST RATE SWAPS
Our interest rate exposure results from variable-rate borrowings from commercial banks and fixed-rate borrowings pursuant to its Senior Notes and MBFC Loan. We manage its exposure to changes in interest rates by utilizing interest rate swaps. The objective of holding interest rate swaps is to manage debt service costs by converting a portion of fixed-rate debt into variable-rate debt or a portion of variable-rate debt into fixed-rate debt. An interest rate swap, in general, requires one party to pay a fixed-rate on the notional amount while the other party pays a floating-rate based on the notional amount. We believe that it is prudent to maintain an appropriate mixture of variable-rate and fixed-rate debt.
We assess interest rate cash flow risk by identifying and measuring changes in interest rate exposure that impact future cash flows and evaluating hedging opportunities. We use analytical techniques to measure its exposure to fluctuations in interest rates, including cash flow sensitivity analysis to estimate the expected impact of changes in interest rates on our future cash flows.
The General Partner oversees the strategies associated with financial risks and approves instruments that are appropriate for our requirements. The notional amount of an interest rate swap does not represent exposure to credit loss. We monitor our positions and the credit ratings of counterparties. Management believes the risk of incurring a credit loss is remote, and that if incurred, such losses would be immaterial.
At December 31, 2001, we had one interest rate swap outstanding having a notional amount of $54 million extending through March 2010. Under this agreement, we exchanged a fixed-rate of 8.70% for a variable-rate that ranged from 4.28% to 7.66% during 2001 (the variable-rate may fluctuate over time depending on market conditions). If it elects to do so, the counterparty may terminate this swap in March 2003. During 2001, two counterparties terminated their swap agreements with us either through early termination clauses or negotiation. The closed agreements had a combined notional amount of $100 million.
Upon adoption of SFAS No. 133, we were required to recognize the fair value of the interest rate swaps on the balance sheet offset by an equal increase in the fair value of associated fixed-rate debt and, therefore, the adoption of the new standard had no impact on earnings at transition. Subsequently, it was determined that the interest rate swaps would not qualify for hedge accounting treatment under SFAS No. 133 due to differences between the maturity dates of the swaps and the associated fixed-rate debt; thus, changes in the fair value of the interest rate swaps would be recorded in earnings through mark-to-market accounting (i.e., the interest rate swaps were deemed ineffective under SFAS No. 133). As a result, the increase in fair value of the associated fixed-rate debt will not be adjusted for future changes in its fair value and will be amortized to earnings over the remaining life of the underlying debt instrument, which approximates 10 years.
We recognized income of $13.2 million in 2001 from our interest rate swaps that is treated as a reduction of interest expense in the Statements of Consolidated Operations. Of this amount, $2.3 million represents the mark-to-market income on the remaining swap at December 31, 2001 (estimated fair value of swap based on market rates at that date). The balance of $10.9 million was realized during 2001.
The $2.3 million estimated fair value of the remaining swap at December 31, 2001 is based on market rates (assuming its early termination option in March 2003 is exercised). The fair value estimate represents the amount that we would receive to terminate the swap, taking into consideration current interest rates.
FUTURE ISSUES CONCERNING SFAS NO. 133
Due to the complexity of SFAS No. 133, the FASB is continuing to provide guidance about implementation issues. Since this guidance is still continuing, our initial conclusions regarding the application of SFAS No. 133 upon adoption may be altered. As a result, additional SFAS No. 133 transition adjustments may be recorded in future periods as we adopt new FASB interpretations.
OTHER FAIR VALUE INFORMATION
Cash and cash equivalents, Accounts Receivable, Accounts Payable and Accrued Expenses are carried at amounts which reasonably approximate their fair value at year end due to their short-term nature.
Fixed-rate long term debt. The estimated fair value of our fixed-rate long-term debt is estimated based on quoted market prices for debt of similar terms and maturities. No variable rate long-term debt was outstanding at December 31, 2001.
The following table summarizes the estimated fair values of our various financial instruments at December 31, 2001 and 2000:
- --------------- (1) 2001 includes a $1.2 million receivable related to the remaining interest rate swap (2) 2001 values are a component of other current assets in our consolidated balance sheet (3) 2001 value represents the aggregate fair value of the remaining swap (net of the $1.2 million receivable reflected under accounts receivable). $1.3 million of the $2.3 million mark-to-market value is a component of other current assets while the balance of $1.0 million is reflected in other assets. (4) 2001 values are a component of other current liabilities in our consolidated balance sheet (5) Prior to our adoption of SFAS No. 133 on January 1, 2001, interest rate swaps and certain commodity financial instruments were off-balance sheet instruments. As a result of SFAS No. 133, these financial instruments are now recorded as part of balance sheet assets and liabilities, as the circumstances warrant.
12. SIGNIFICANT CONCENTRATIONS OF RISK
CREDIT RISK. A substantial portion of our revenues are derived from various companies in the NGL and petrochemical industry, located in the United States. Although this concentration could affect our overall exposure to credit risk since these customers might be affected by similar economic or other conditions, management believes we are exposed to minimal credit risk, since the majority of our business is conducted with major companies within the industry including those with whom it has joint operations. We do not require collateral for our accounts receivable.
NATURE OF OPERATIONS. We are subject to a number of risks inherent in the industry in which it operates, including fluctuating gas and liquids prices. Our financial condition and results of operation will depend significantly on the prices received for NGLs and the price paid for gas consumed in the NGL extraction process. These prices are subject to fluctuations in response to changes in supply, market uncertainty, weather and a variety of additional factors that are beyond our control.
In addition, we must obtain access to new natural gas volumes along the Gulf Coast of the United States for its processing business in order to maintain or increase gas plant throughput levels to offset natural declines in field reserves. The number of wells drilled by third-parties to obtain new volumes will depend on, among other factors, the price of gas and oil, the energy policy of the federal government and the availability of foreign oil and gas, none of which is in our control.
The products that we process, sell or transport are principally used as feedstocks in petrochemical manufacturing and in the production of motor gasoline and as fuel for residential and commercial heating. A reduction in demand for our products or services by industrial customers, whether because of general economic conditions, reduced demand for the end products made with NGL products, increased competition from petroleum-based products due to pricing differences, adverse weather conditions, governmental regulations affecting prices and production levels of natural gas or the content of motor gasoline or other reasons, could have a negative impact on our results of operation. A material decrease in natural gas production or crude oil refining, as a result of depressed commodity prices or otherwise, or a decrease in imports of mixed butanes, could result in a decline in volumes processed and sold by us.
COUNTERPARTY RISK. From time to time, we have credit risk with our counterparties in terms of settlement risk associated with its 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.
In December 2001, Enron Corp., or Enron, filed for protection under Chapter 11 of the U.S. Bankruptcy Code. As a result, we established a $10.6 million reserve for amounts owed to us by Enron North America, a subsidiary of Enron. Enron North America was our counterparty to various past financial instruments. The Enron amounts were unsecured and the amount that we may ultimately recover, if any, is not presently determinable. Of the reserve amount established, $4.3 million was attributable to various unbilled commodity financial instrument positions that terminate during the first quarter of 2002.
13. SEGMENT INFORMATION
Operating segments are components of a business about which separate financial information is available and that are regularly evaluated by the chief operating decision maker 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.
We have five reportable operating segments: Fractionation, Pipelines, Processing, Octane Enhancement and Other. The reportable segments are generally organized according to the type of services rendered (or process employed) and products produced and/or sold, as applicable. The segments are regularly evaluated by the Chief Executive Officer of the General Partner. Fractionation primarily includes NGL fractionation, isomerization, and polymer grade propylene fractionation services. Pipelines consists of both liquids and natural gas pipeline systems, storage and import/export terminal services. Processing includes the natural gas processing business and its related merchant activities. Octane Enhancement represents our equity interest in BEF, a facility that produces motor gasoline additives to enhance octane (currently producing MTBE). The Other operating segment consists of fee-based marketing services and other plant support functions.
We evaluate segment performance based on gross operating margin. Gross operating margin reported for each segment represents operating income before depreciation and amortization, lease expense obligations retained by EPCO, gains and losses on the sale of assets and general and administrative expenses. In addition, segment gross operating margin is exclusive of interest expense, interest income (from unconsolidated affiliates or others), dividend income from unconsolidated affiliates, minority interest, extraordinary charges and other income and expense transactions.
We include equity earnings from unconsolidated affiliates in segment gross operating margin and as a component of revenues. Our equity investments with industry partners are a vital component of our business strategy and a means by which we conduct our operations to align our interests with a supplier of raw materials to a facility or a consumer of finished products from a facility. 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. For example, we use the Promix NGL fractionator to process NGLs extracted by our gas plants. The NGLs received from Promix then can be sold by our merchant businesses. Another example would be our relationship with the BEF MTBE facility. Our isomerization facilities process normal butane for this plant and our HSC pipeline transports MTBE for delivery to BEF's storage facility on the Houston Ship Channel.
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 property is construction-in-progress. Segment property represents those facilities and projects that contribute to gross operating margin and is net of accumulated depreciation on these assets. Since assets under construction do not generally contribute to segment gross operating margin, these assets are not included in the operating segment totals until they are deemed operational.
Segment gross operating margin is inclusive of intersegment revenues, which are generally based on transactions made at market-related rates. These revenues have been eliminated from the consolidated totals.
Information by operating segment, together with reconciliations to the consolidated totals, is presented in the following table:
Our revenues are derived from a wide customer base. Shell accounted for 10.5% of consolidated revenues in 2001 (up from 9.5% of consolidated revenues in 2000). No single external customer accounted for more than 10% of consolidated revenues during 2000 and 1999. Approximately 80% of our revenues from Shell during 2001 and 2000 are attributable to sales of NGL products which are recorded in our Processing segment. No single third-party customer provided more than 10% of consolidated revenues during 2000 or 1999. All consolidated revenues were earned in the United States. Our operations are centered along the Texas, Louisiana and Mississippi Gulf Coast areas.
A reconciliation of segment gross operating margin to consolidated income before minority interest follows:
14. SUBSEQUENT EVENTS (UNAUDITED)
PURCHASE OF DIAMOND-KOCH STORAGE ASSETS. On January 17, 2002, we completed the purchase of various hydrocarbon storage assets from affiliates of Valero Energy Corporation and Koch Industries, Inc. The purchase price of the storage assets was approximately $129 million (subject to certain post-closing adjustments) and will be accounted for as an asset purchase. The purchase price was funded entirely by internally generated funds.
The storage facilities include 30 salt dome storage caverns with a total useable capacity of 68 million barrels, local distribution pipelines and related equipment. The facilities provide storage services for mixed natural gas liquids, ethane, propane, butanes, natural gasoline and olefins (such as ethylene), polymer grade propylene, chemical grade propylene and refinery grade propylene. The facilities are located in Mont Belvieu, Texas.
PURCHASE OF DIAMOND-KOCH PROPYLENE FRACTIONATION ASSETS. On February 1, 2002, we completed the purchase of various propylene fractionation assets from affiliates of Valero Energy Corporation and Koch Industries, Inc. and certain inventories of refinery grade propylene, propane and polymer grade propylene owned by such affiliates. The purchase price of these assets was approximately $238.5 million (subject to certain post-closing adjustments) and will be accounted for as an asset purchase. The purchase price was funded by a drawdown on our existing revolving bank credit facilities.
The propylene fractionation assets being acquired include a 66.67% interest in a polymer grade propylene fractionation facility located in Mont Belvieu, Texas, a 50.0% interest in an entity which owns a polymer grade propylene export terminal located on the Houston Ship Channel in La Porte, Texas and varying interests in several supporting distribution pipelines and related equipment. The propylene fractionation facility has the gross capacity to produce approximately 41,000 barrels per day of polymer grade propylene.
Both the storage and propylene fractionation acquisitions have been approved by the requisite regulatory authorities. The post-closing purchase price adjustments of both transactions are expected to be completed during the second quarter of 2002.
TWO-FOR-ONE SPLIT OF LIMITED PARTNER UNITS. On February 27, 2002, the Limited Partners announced that the Board of Directors of the General Partner had approved a two-for-one split for each class of its Units. The partnership Unit split will be accomplished by distributing one additional partnership Unit for each partnership Unit outstanding to holders of record on April 30, 2002. The Units will be distributed on May 15, 2002. All references to the number of Limited Partner Units contained in this document relate to the pre-split Units, except if indicated otherwise.
15. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Earnings in the fourth quarter of 2001 declined relative to the third quarter of 2001 primarily due to a decrease in the mark-to-market value of our commodity financial instruments. The decrease was due to (1) the settlement of certain positions during the fourth quarter, (2) a decrease in the relative amount of hedging activities at December 31, 2001 versus September 30, 2001 and (3) a decrease in the value of certain outstanding financial instruments from September 30, 2001 due to changes in natural gas prices.
SCHEDULE II
ENTERPRISE PRODUCTS OPERATING L.P. VALUATION AND QUALIFYING ACCOUNTS
- ---------------- (1) In December 2001, Enron North America (our counterparty to various past financial instruments) filed for protection under Chapter 11 of the U.S. Bankruptcy Code. As a result, we established a $10.6 million reserve for amounts owed to us by Enron. The Enron amounts were unsecured and the amount that we may ultimately recover, if any, is not presently determinable. Of the $10.6 million reserve we established, $6.3 million offsets invoices that had been billed to Enron as of December 31, 2001 with the remaining $4.3 million in a credit reserve offsetting various unbilled commodity financial instrument positions. The unbilled amounts are expected to be settled and invoiced during the first quarter of 2002.
(2) Prior to the TNGL acquisition in 1999, we did not experience any significant losses from bad debts and therefore did not require an allowance account. As a result of the TNGL acquisition in August 1999, we acquired a $12.9 million allowance for doubtful accounts. In April 2001, we acquired an additional $6.5 million allowance for doubtful accounts in connection with the acquisition of Acadian Gas.
(3) The reserve for inventory gains and losses generally denotes net underground NGL storage well product losses.
(4) A review of the reserve balance was performed during the fourth quarter of 2001 and based upon its findings and estimated future losses, a reserve balance of $2.0 million at December 31, 2001 was deemed appropriate.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, in the City of Houston, State of Texas on March 25, 2002.
ENTERPRISE PRODUCTS OPERATING L.P. (A Delaware Limited Partnership) By: ENTERPRISE PRODUCTS GP, LLC as General Partner
By: /s/ Michael J. Knesek ------------------------ Name: Michael J. Knesek Title: Vice President, Controller and Principal Accounting Officer of Enterprise Products GP, LLC
Pursuant to the requirements of the Securities Exchange 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 March 25, 2002:
SIGNATURE POSITIONS HELD IN GENERAL PARTNER - --------- ---------------------------------
/s/ Dan L. Duncan Chairman of the Board and Director - --------------------------- Dan L. Duncan
/s/ O.S. Andras President, Chief Executive Officer and - --------------------------- Director O.S. Andras
/s/ Randa Duncan Williams Director - --------------------------- Randa Duncan Williams
/s/ Richard H. Bachmann Executive Vice President, Chief Legal Officer, - --------------------------- Secretary and Director Richard H. Bachmann
/s/ Michael A. Creel Chief Financial Officer and Executive Vice - --------------------------- President Michael A. Creel
/s/ J.A. Berget Director - --------------------------- J.A. Berget
/s/ Dr. Ralph S. Cunningham Director - --------------------------- Dr. Ralph S. Cunningham
/s/ J. R. Eagan Director - --------------------------- J.R. Eagan
/s/ Curtis R. Frasier Director - --------------------------- Curtis R. Frasier
/s/ Lee W. Marshall, Sr. Director - --------------------------- Lee W. Marshall, Sr.
/s/ Richard S. Snell Director - --------------------------- Richard S. Snell
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