ITEM 3. LEGAL PROCEEDINGS.
See Note 16 of the Notes to the Consolidated Financial Statements included elsewhere in this report.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
There were no matters submitted to a vote of our unitholders during the fourth quarter of 2001.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S EQUITY AND RELATED SECURITY HOLDER MATTERS.
The following table sets forth, for the periods indicated, the high and low sale prices per common unit, as reported on the New York Stock Exchange, the principal market in which our common units are traded, and the amount of distributions declared per common unit. All information has been adjusted to give effect to the two-for-one split of common units effective August 31, 2001.
All of the information is for distributions declared with respect to that quarter. The declared distributions were paid within 45 days after the end of the quarter. We currently expect that we will continue to pay comparable cash distributions in the future assuming no adverse change in our operations, economic conditions and other factors. However, we can give no assurance that future distributions will continue at such levels.
As of February 14, 2002, there were approximately 56,000 beneficial owners of our common units, one holder of our Class B units and one holder of our i-units.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
The following tables set forth, for the periods and at the dates indicated, selected historical financial data for us.
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(1) Represents income before extraordinary charge per unit adjusted for the two-for-one splits of units on October 1, 1997 and on August 31, 2001. Basic Limited Partners' income per unit before
extraordinary charge was computed by dividing the interest of our unitholders in income before extraordinary charge by the weighted average number of units outstanding during the period.
(2) Diluted Limited Partners' net income per unit reflects the potential dilution, by application of the treasury stock method, that could occur if options to issue units were exercised, which would result in the issuance of additional units that would then share in our net income.
(3) Includes results of operations for the remaining 50% interest in the Colton Processing Facility, KMTP, Casper and Douglas gas gathering assets, 50% interest in Coyote Gas Treating, LLC, 25% interest in Thunder Creek Gas Services, LLC, Central Florida Pipeline LLC, Kinder Morgan Liquids Terminals LLC, Pinney Dock & Transport LLC, CALNEV Pipe Line LLC, 34.8% interest in the Cochin Pipeline System, Vopak terminal LLCs, Boswell terminal assets, Stolt-Nielsen terminal assets and additional gasoline and gas plant interests since dates of acquisition. The remaining interest in the Colton Processing Facility, KMTP, Casper and Douglas gas gathering assets and our interests in Coyote and Thunder Creek were acquired on December 31, 2000. Central Florida and Kinder Morgan Liquids Terminals LLC were acquired January 1, 2001. Pinney Dock was acquired March 1, 2001. CALNEV was acquired March 30, 2001. Our second investment in Cochin, representing a 2.3% interest was made on June 20, 2001. Vopak terminal LLCs were acquired July 10, 2001. Boswell terminals were acquired August 31, 2001. Stolt-Nielsen terminals were acquired on November 8 and 29, 2001, and our additional interests in the Snyder Gasoline Plant and the Diamond M Gas Plant were acquired on November 14, 2001.
(4) Includes results of operations for KMIGT, 66 2/3% interest in Trailblazer, 49% interest in Red Cedar, Milwaukee Bulk Terminals, Dakota Bulk Terminal, remaining 80% interest in Kinder Morgan CO(2) Company, L.P., Devon Energy carbon dioxide properties, Kinder Morgan Transmix Company, LLC, a 32.5% interest in Cochin Pipeline System and Delta Terminal Services LLC since dates of acquisition. KMIGT, Trailblazer assets, and our 49% interest in Red Cedar were acquired on December 31, 1999. Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc. were acquired on January 1, 2000. Kinder Morgan Transmix Company, LLC was acquired on October 25, 2000. Our 32.5% interest in Cochin was acquired on November 3, 2000, and Delta Terminal Services LLC was acquired on December 1, 2000.
(5) Includes results of operations for 51% interest in Plantation Pipe Line Company, Products Pipelines' initial transmix operations and 33 1/3% interest in Trailblazer Pipeline Company since dates of acquisition. Our second investment in Plantation, representing a 27% interest was made on June 16, 1999. The Products Pipelines' initial transmix operations were acquired on September 10, 1999, and our initial 33 1/3% investment in Trailblazer was made on November 30, 1999.
(6) Includes results of operations for Pacific operations' pipeline system, Kinder Morgan Bulk Terminals and 24% interest in Plantation Pipe Line Company since dates of acquisition. Kinder Morgan Bulk Terminals were acquired on July 1, 1998 and our 24% interest in Plantation Pipe Line Company was acquired on September 15, 1998.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Our discussion and analysis of our financial condition and operations are based on our Consolidated Financial Statements, which were prepared in accordance with accounting principles generally accepted in the United States of America. You should read the following discussion and analysis in conjunction with our Consolidated Financial Statements included elsewhere in this report.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Certain amounts included in or affecting our Consolidated Financial Statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared.
The preparation of our financial statements in conformity with generally accepted accounting principles requires our management to make estimates and assumptions that affect:
- the amounts we report for assets and liabilities;
- our disclosure of contingent assets and liabilities at the date of the financial statements; and
- the amounts we report for revenues and expenses during the reporting period.
Therefore, the reported amounts of our assets and liabilities, revenues and expenses and associated disclosures with respect to contingent assets and obligations are necessarily affected by these estimates. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
In preparing our financial statements and related disclosures, we must use estimates in determining the economic useful lives of our assets, provisions for uncollectible accounts receivable, exposures under contractual indemnifications and various other recorded or disclosed amounts. However, we believe that certain accounting policies are of more significance in our financial statement preparation process than others. With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable. Finally, we are subject to litigation as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected.
RESULTS OF OPERATIONS
Our revenues, operating income, net income, earnings per unit and distributable cash flow again reached record levels, driven by acquisitions, strong internal growth and favorable performances by existing and newly acquired pipelines and terminal facilities. In 2001, we continued our strategy of:
- providing, for a fee, transportation, storage and handling services which are core to the energy infrastructure of growing markets;
- increasing utilization of assets while containing costs;
- leveraging economies of scale from incremental acquisitions; and
- maximizing the benefits of our financial structure.
In 2001, our net income was $442.3 million ($1.56 per diluted unit) on revenues of $2,946.7 million, compared to net income of $278.3 million ($1.34 per diluted unit) on revenues of $816.4 million in 2000,
and net income of $182.3 million ($1.29 per diluted unit) on revenues of $428.7 million in 1999. Included in our net income for 1999 was an extraordinary charge of $2.6 million, associated with debt refinancing transactions, and a benefit of $10.1 million related to the sale of our 25% interest in the Mont Belvieu fractionation facility, partially offset by special non-recurring charges.
Our total consolidated operating income was $563.8 million in 2001, $315.6 million in 2000 and $187.4 million in 1999. Our total consolidated net income before extraordinary charges was $442.3 million in 2001, $278.3 million in 2000 and $184.9 million in 1999. Operating expenses, consisting of our combined cost of sales, fuel, power and operating and maintenance expenses, were $2,087.5 million in 2001, compared with $332.2 million in 2000 and $143.1 million in 1999.
Our increases in overall revenues, expenses and net income in 2001 compared to 2000 resulted from assets and businesses that we acquired from GATX Corporation in the first quarter of 2001, from KMI on December 31, 2000, and from other acquisitions made during 2001 as well as internal growth from existing assets. Our increases in overall revenues, expenses and net income in 2000 compared to 1999 primarily resulted from the inclusion of our Natural Gas Pipelines segment, acquired from KMI on December 31, 1999, and our acquisition of the remaining 80% ownership interest in Kinder Morgan CO(2) Company, L.P. (formerly Shell CO(2) Company, Ltd.) effective April 1, 2000. Prior to that date, we owned a 20% equity interest in Kinder Morgan CO(2) Company, L.P. and reported its results under the equity method of accounting. The results of Kinder Morgan CO(2) Company, L.P. are included in our CO(2) Pipelines segment.
PRODUCTS PIPELINES
Our Products Pipelines segment reported earnings of $308.8 million on revenues of $605.4 million in 2001. In 2000, the segment reported earnings of $221.1 million on revenues of $420.3 million. In 1999, the segment reported earnings of $208.8 million on revenues of $313.0 million. The $87.7 million increase in segment earnings in 2001 compared to 2000 is attributable to acquisitions we made since December 2000 and cost savings resulting from our operation of Plantation Pipe Line Company. Our revenues increased by $185.1 million as a result of our acquisitions, operating reimbursements from Plantation and an 8% improvement in our Pacific operations' revenues. Our Pacific operations achieved a 3% increase in mainline delivery volumes and an over 4% increase in average tariff rates. Acquisitions made since the fourth quarter of 2000, which contributed to our segment's results include:
- Kinder Morgan Transmix Company, LLC;
- the remaining 50% interest in the Colton Transmix Processing Facility;
- a 34.8% interest in the Cochin Pipeline System (in January 2002, we acquired an additional 10% ownership interest, which was made effective December 31, 2001, bringing our total interest to 44.8%); and
- assets acquired from GATX Corporation, consisting of Central Florida Pipeline LLC, CALNEV Pipe Line LLC and petroleum product and chemical terminals.
Together, these businesses generated $202.0 million in revenues in 2001. The segment's overall increase in revenues was partially offset by lower transmix revenues. During the first quarter of 2001, we entered into a 10-year agreement with Duke Energy Merchants to process transmix on a fee basis only. Under the agreement, Duke Energy Merchants is responsible for procurement of the transmix and sale of the products after processing. This agreement allows us to eliminate commodity price exposure in our transmix operations.
Higher segment revenues in 2000 over 1999 resulted primarily from the inclusion of a full year of operations from our initial acquisition of transmix assets, acquired in September 1999, and the inclusion of two months of operations from Kinder Morgan Transmix Company, LLC, acquired in late October 2000. Additionally, higher throughput volumes on both our Pacific operations and North System pipelines contributed to the increase in segment revenues in 2000. On our Pacific operations, average tariff rates remained relatively flat between 2000 and 1999, but an almost 3% increase in mainline delivery volumes
resulted in a 3% increase in revenues. On our North System, revenues grew 14% in 2000 compared to 1999. The increase was due to an almost 10% increase in throughput revenue volumes, primarily due to strong refinery demand in the Midwest, as well as a 5% increase in average tariff rates.
Combined operating expenses for the Products Pipelines segment were $222.5 million in 2001, $172.4 million in 2000 and $76.4 million in 1999. The increase in segment operating expenses in 2001 over the prior year resulted primarily from our acquisitions, costs incurred under our operations agreement with Plantation Pipe Line Company, as well as higher fuel and power expenses on our Pacific operations' pipelines. This increase was partially offset by a reduction in transmix cost due to our agreement with Duke Energy Merchants.
The increase in 2000 expenses over 1999 levels resulted mainly from the inclusion of our transmix operations and the higher delivery volumes on our Pacific operations' pipelines. Segment operating income was $295.3 million in 2001, $193.4 million in 2000 and $186.0 million in 1999.
Earnings from our Products Pipelines' equity investments, net of amortization of excess costs, were $22.7 million in 2001, $29.1 million in 2000 and $21.4 million in 1999. The decrease in the segment's equity earnings in 2001 versus 2000 was due to lower equity earnings from Plantation Pipe Line Company as a result of lower throughput and the absence of equity earnings from our Colton Transmix Processing Facility during 2001. On December 31, 2000, we acquired the remaining 50% ownership interest in the facility and since that date, we have included Colton's operational results in our consolidated financial statements.
The increase in equity earnings in 2000 versus 1999 was chiefly due to our investments in Plantation Pipe Line Company. We acquired our initial 24% ownership interest in September 1998 and an additional 27% ownership interest in June 1999.
We are parties to proceedings at the Federal Energy Regulatory Commission and the California Public Utilities Commission that challenge certain tariffs on our Pacific operations. The Federal Energy Regulatory Commission complaint seeks approximately $137 million in tariff refunds and approximately $22 million in prospective annual tariff reductions. The California Public Utilities Commission complaint seeks approximately $20 million in tariff refunds and approximately $12 million in prospective annual tariff reductions. Amounts, if any, ultimately owed will be impacted by the passage of time and the application of interest. Decisions regarding these complaints could negatively impact our cash flow, and additional challenges to tariff rates could be filed with the Federal Energy Regulatory Commission and California Public Utilities Commission in the future. We believe we have meritorious defenses in the proceedings challenging our pipeline tariffs, and we are defending these proceedings vigorously. We believe the ultimate resolutions of these proceedings will be more favorable to us than the outcomes sought by the protesting shippers and expect these resolutions will not have a material adverse effect on our financial condition or results of operations; nonetheless, a decision by either or both of the California Public Utilities Commission and Federal Energy Regulatory Commission granting the complaining shippers the relief they seek may have a material adverse effect on our financial condition or results of operations.
NATURAL GAS PIPELINES
Our Natural Gas Pipelines segment reported earnings of $193.7 million on revenues of $1,869.3 million in 2001. In 2000, the segment reported earnings of $113.0 million on revenues of $174.2 million. The segment's operating expenses totaled $1,656.1 million in 2001 and $51.3 million in 2000. Segment results for 1999 primarily represent activity from a partnership interest in the Mont Belvieu fractionation facility. Total segment earnings of $17.0 million in 1999 include $2.5 million in equity earnings from our 25% interest in the Mont Belvieu Fractionator and $14.1 million from our third quarter gain on the sale of that interest to Enterprise Products Partners, L.P.
The year-to-year increases in operating results during 2001 and 2000 were primarily due to the inclusion of assets acquired from KMI on December 31, 1999 and December 31, 2000, and the strong performance from existing assets. Effective December 31, 1999, we acquired:
- KMIGT;
- a 33 1/3% interest in Trailblazer, having previously acquired a 33 1/3% interest in November 1999; and
- a 49% interest in Red Cedar.
Effective on December 31, 2000, we acquired:
- Kinder Morgan Texas Pipeline, L.P.;
- our Casper and Douglas natural gas gathering and processing systems;
- a 50% interest in Coyote Gas Treating, LLC; and
- a 25% interest in Thunder Creek.
Kinder Morgan Texas Pipeline, L.P. purchases and sells natural gas, which is transported through its pipeline. The purchase and sale activity results in significantly higher revenues and operating expenses compared to the natural gas pipelines acquired earlier from KMI. The earlier pipelines acquired charge a transportation fee but do not purchase and sell gas. Combined, Kinder Morgan Texas Pipeline, L.P. and the Casper and Douglas systems produced operating revenues of $1,688.6 million and operating expenses of $1,608.0 million in 2001. The segment's overall increase in revenues in 2001 over 2000 also resulted from a 6% increase in revenues earned by KMIGT, mainly due to higher fuel recovery revenues, driven by a reduction in fuel losses. The overall increase in segment operating expenses was partially offset by lower expenses on the Trailblazer Pipeline, primarily the result of favorable system imbalance settlements.
Transported gas volumes on our natural gas assets increased almost 6% in 2000 compared with 1999 when KMI owned these assets. The overall increase includes an almost 9% increase in volumes shipped on the Trailblazer Pipeline in 2000 compared to 1999. Higher capacity to receive natural gas on the Trailblazer Pipeline during 2000 resulted in an increase in the available quantity of gas delivered to the Trailblazer Pipeline. Segment operating income was $171.8 million in 2001 and $97.3 million in 2000.
We account for our investments in Red Cedar, Coyote Gas Treating, LLC and Thunder Creek under the equity method of accounting. Earnings from equity investments, net of amortization, were $21.2 million for 2001 versus $15.0 million for the same prior year period. The $6.2 million increase in equity earnings resulted from the inclusion of $3.5 million of net equity earnings from the segment's investments in Coyote and Thunder Creek and a $2.7 million increase in earnings from its 49% interest in the Red Cedar Gathering Company, primarily the result of higher revenues from custom compression projects.
CO(2) PIPELINES
Our CO(2) Pipelines segment consists of KMCO(2). In 2001, CO(2) Pipelines earned $91.8 million on revenues of $122.1 million. The segment reported operating expenses of $37.4 million and operating income of $59.3 million. Equity earnings, net of amortization of excess costs, were $32.0 million, consisting of $23.7 million from a full year of earnings from the segment's interest in Cortez Pipeline Company and $8.3 million from a full year of earnings from its 15% equity investment in MKM Partners, L.P., an oil and gas joint venture with Marathon Oil Company that began January 1, 2001.
Prior to our acquisition of the remaining 80% interest in KMCO(2), on April 1, 2000, we accounted for our investment under the equity method of accounting. Furthermore, under the terms of the prior KMCO(2) partnership agreement, we received a priority distribution of $14.5 million per year during 1999 and the first quarter of 2000. After our acquisition of the remaining 80% ownership interest, we amended this partnership agreement, among other things, to eliminate the priority distribution and other provisions rendered irrelevant by our sole ownership and we included the company's financial results in our
consolidated financial statements. The segment's 2000 results include one quarter of equity earnings from our original 20% interest in KMCO(2) and returns from the significant carbon dioxide pipeline assets and oil-producing property interests that we acquired from Devon Energy on June 1, 2000.
For the year 2000, the CO(2) Pipelines segment reported earnings of $68.0 million on revenues of $89.2 million. The segment reported operating expenses of $26.8 million and operating income of $47.9 million. Equity earnings, net of amortization of excess costs, totaled $19.3 million, representing $3.6 million from our 20% interest in KMCO(2) and $15.7 million from the segment's 50% interest in the Cortez Pipeline Company.
Our 1999 results primarily represent equity earnings from our original 20% interest in KMCO(2). Segment earnings of $15.2 million in 1999 included $14.5 million in equity earnings from our 20% interest in KMCO(2)
TERMINALS
Effective in the third quarter of 2001, our Terminals segment reflects changes we made in the organization of our business segments. We have combined our previous Bulk Terminals and Liquids Terminals business segments to present our current Terminals segment. The segment reported earnings of $129.9 million on revenues of $349.9 million in 2001. This compares to earnings of $37.6 million on revenues of $132.8 million in 2000 and to earnings of $35.0 million on revenues of $114.6 million in 1999.
The year-to-year increases in our Terminals revenues, expenses and earnings were driven principally by key acquisitions we have made since December 1999. The acquisitions include:
- Milwaukee Bulk Terminals, Inc., acquired effective January 1, 2000;
- Dakota Bulk Terminal, Inc., acquired effective January 1, 2000;
- Delta Terminal Services LLC, acquired effective December 1, 2000;
- KMLT, acquired from GATX Corporation effective January 1, 2001;
- Pinney Dock & Transport LLC, acquired effective March 1, 2001;
- the terminal businesses we acquired from Koninklijke Vopak N.V., effective July 10, 2001;
- the terminal businesses we acquired from The Boswell Oil Company, effective August 31, 2001; and
- the terminal businesses we acquired from an affiliate of Stolt-Nielsen, Inc. in November 2001.
In 2001, the acquisitions listed above generated revenues of $215.6 million. On an aggregate basis, bulk tonnage transfer volumes, including coal and all other bulk materials, increased 22% over 2000 levels. Our transfers of liquids volumes, including refined petroleum products, chemicals and all other liquids volumes increased 8% in 2001 compared with 2000 when the liquids terminals were owned by other entities. In 2000, the acquisitions listed above as 2000 acquisitions generated revenues of $11.4 million. Bulk tonnage transfer volumes, including coal and all other bulk material transfers, increased 6% in 2000 over 1999 levels.
Combined operating expenses for our Terminals segment totaled $171.5 million in 2001 versus $81.7 million in 2000 and $66.6 million in 1999. The increase in 2001 operating expenses over 2000 was the result of acquisitions made in 2001 and higher maintenance and operating expenses associated with the transfer of higher volumes. The increase in 2000 versus 1999 was the result of acquisitions made in 2000, higher operating expenses associated with the transfer of higher coal volumes and an increase in fuel costs.
OTHER
Items not attributable to any segment include general and administrative expenses, interest income and expense and minority interest. General and administrative expenses totaled $99.0 million in 2001
compared with $60.1 million in 2000 and $35.6 million in 1999. The year-to-year increases in our general and administrative expenses were mainly due to our larger and more diverse operations. During 2001, we incorporated pipeline and terminal businesses that we acquired from GATX Corporation, incorporated additional natural gas pipeline assets that we acquired from KMI on December 31, 2000 and operated Plantation Pipe Line Company for a full year. During 2000, we formed our natural gas pipelines and CO(2) pipelines business segments. We continue to manage aggressively our infrastructure expense and to focus on our productivity and expense controls.
Our total interest expense, net of interest income, was $171.5 million in 2001, $93.3 million in 2000 and $52.6 million in 1999. The 2001 increase was primarily due to the additional debt we issued related to the financing of the acquisitions that we have made since the end of 2000 and to the $134.8 million in third-party debt we assumed as part of the assets acquired from GATX Corporation. In March 2001, we closed a public offering of $1.0 billion in principal amount of senior notes. The 2000 increase was primarily due to the additional debt we incurred related to the financing of our 2000 and 1999 investments.
Minority interest increased to $11.4 million in 2001 compared with $8.0 million in 2000 and $2.9 million in 1999. The $3.4 million increase in 2001 over 2000 resulted from earnings attributable to MidTex Gas Storage Company, L.P., a partnership controlled by Kinder Morgan Texas Pipeline L.P. as well as to our higher overall income. The $5.1 million increase in 2000 over 1999 primarily resulted from the inclusion of earnings attributable to the Trailblazer Pipeline Company.
OUTLOOK
We actively pursue a strategy to increase our operating income. We will use a three-pronged approach to accomplish this goal.
- Cost Reductions. We have reduced the total operating, maintenance, general and administrative expenses of those operations that we owned at the time Kinder Morgan (Delaware), Inc. acquired our general partner in February 1997. In addition, we have made similar reductions in the operating, maintenance, general and administrative expenses of many of the businesses and assets that we acquired since February 1997, including our Pacific operations, Plantation Pipe Line Company and the businesses we acquired from GATX Corporation. Generally, these reductions in expense have been achieved by eliminating duplicative functions that we and the acquired businesses each maintained prior to their combination. We intend to continue to seek further reductions throughout our businesses where appropriate.
- Internal Growth. We intend to expand the operations of our current facilities. We have taken a number of steps that management believes will increase revenues from existing operations, including the following:
- a $25 million expansion of our carbon dioxide project in the SACROC unit in Scurry County of west Texas. The project is expected to increase deliveries of carbon dioxide to SACROC by nearly 80%, to 125 million cubic feet of carbon dioxide per day. The project is expected to be completed in the first quarter of 2002;
- a $9 million expansion project on the CALNEV pipeline. The project will bolster the jet fuel supply to McCarran International Airport in Las Vegas, Nevada. We will share the costs of the project with LASFUEL, the McCarran International Airport fuel consortium. The project is expected to be completed in the second quarter of 2002; and
- a $16.3 million plan to expand our Pasadena and Galena Park, Texas facilities, which, collectively, are the largest independently operated liquids terminals in the world. The expansion will increase tank storage capacity by an additional 830,000 barrels within the next year and will include pipe modifications to enhance docking facilities.
- Strategic Acquisitions. Since January 1, 2001, we have made the following acquisitions:
The costs and methods of financing for each of these acquisitions are discussed under "Capital Requirements for Recent Transactions."
We regularly seek opportunities to make additional strategic acquisitions, to expand existing businesses and to enter into related businesses. We periodically consider potential acquisition opportunities as they are identified, but we cannot assure you that we will be able to consummate any such acquisition. Our management anticipates that we will finance acquisitions by borrowings under our bank credit facilities or by issuing commercial paper, and subsequently reduce these short-term borrowings by issuing new long-term debt securities, common units and/or i-units to Kinder Morgan Management.
We are continuing to assess the effect of the terrorist attacks of September 11, 2001 on our businesses. In response to the attacks, we have increased security at our liquids terminals and performed security surveys on certain sections of our pipelines. We face the possibility that during 2002, property insurance carriers generally may terminate insurance coverage for all companies for incidents of sabotage and terrorism. We are exploring the availability of sabotage and terrorism insurance from other sources, though proposed federal legislation may provide an insurance framework that will cause current insurers to continue to provide sabotage and terrorism coverage under standard property insurance policies. Nonetheless, there is no assurance that federal legislation will be passed or adequate sabotage and terrorism insurance will be available throughout 2002.
We do not believe that the increased cost associated with these measures will have a material effect on our operating results. As of December 31, 2001, we have not noticed a significant decrease in the volumes of product that we are moving through our operations as a result of the September 11, 2001 attacks. However, if demand for the products that we handle were to significantly decrease, our shippers would decrease the volumes that they ship through our systems or that we handle and store for them, which may have a negative impact on our financial performance.
With respect to certain related party transactions, see Note 12 to the Consolidated Financial Statements included elsewhere in this report.
LIQUIDITY AND CAPITAL RESOURCES
The following table illustrates the sources of our invested capital. In addition to our results of operations, these balances are affected by our financing activities as discussed below (dollars in thousands):
SUMMARY OF OFF BALANCE SHEET FINANCING
We have obligations with respect to other entities which are not consolidated in our financial statements as shown below (in millions):
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(1) The remaining general partner interests are owned by ExxonMobil Cortez Pipeline, Inc., an indirect wholly-owned subsidiary of ExxonMobil Corporation and Cortez Vickers Pipeline Company, an indirect subsidiary of M.E. Zuckerman Energy Investors Incorporated.
(2) We are severally liable for our percentage ownership share of the Cortez Pipeline Company debt. Further, pursuant to a Throughput and Deficiency Agreement, the owners of Cortez Pipeline
Company are required to contribute capital to Cortez in the event of a cash deficiency. The agreement contractually supports the financings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by obligating the owners of Cortez Pipeline to fund cash deficiencies at Cortez Pipeline, including anticipated deficiencies and cash deficiencies relating to the repayment of principal and interest on the debt of Cortez Capital Corporation. Their respective parent or other companies further severally guarantee the obligations of the Cortez Pipeline owners under this agreement.
(3) Relates to our Vopak terminal acquisition in July 2001. See Note 3 to the Consolidated Financial Statements.
(4) Principally property, plant and equipment.
(5) Represents the portion of the entity's debt that we may be responsible for if the entity can not satisfy the obligation.
Our share of earnings, based on our ownership percentage, before income taxes and amortization of excess investment cost was $25.7 million from Cortez Pipeline Company, $25.3 million from Plantation Pipe Line Company and $18.8 million from Red Cedar Gathering Company. Additional information regarding these investments is included in Note 7 to the Consolidated Financial Statements included elsewhere in this report.
SUMMARY OF CERTAIN CONTRACTUAL OBLIGATIONS
PRIMARY CASH REQUIREMENTS
Our primary cash requirements, in addition to normal operating expenses, are debt service, sustaining capital expenditures, expansion capital expenditures and quarterly distributions to our common unitholders, Class B unitholders and general partner. In addition to utilizing cash generated from operations, we could meet our cash requirements (other than distributions to our common unitholders, Class B unitholders and general partner) through borrowings under our credit facilities or issuing short-term commercial paper, long-term notes, additional common units or additional i-units to Kinder Morgan Management. In general, we expect to fund:
- future cash distributions and sustaining capital expenditures with existing cash and cash flows from operating activities;
- expansion capital expenditures and working capital deficits through additional borrowings or issuance of additional common units or additional i-units to Kinder Morgan Management;
- interest payments from cash flows from operating activities; and
- debt principal payments with additional borrowings as they become due or by issuance of additional common units or additional i-units to Kinder Morgan Management.
The scheduled maturities of our outstanding debt at December 31, 2001, are summarized as follows (in thousands):
Of the $836.5 million scheduled to mature in 2002, we intend, and have the ability, to refinance $276.3 million on a long-term basis under our $300 million multi-year credit facility. We plan to refinance the remaining $560.2 million under a new credit agreement, through an extension of our existing $750 million unsecured 364-day credit facility, by newly issued long-term debt, or by the issuance of additional i-units to Kinder Morgan Management. Our existing $750 million credit facility expires in October 2002.
During the first quarter of 2002, we will need approximately $890 million for the following acquisitions and expansion projects (see Note 3 to our Consolidated Financial Statements):
- the remaining 33 1/3% ownership interest in Trailblazer;
- Tejas Gas, LLC;
- an additional 10% ownership interest in the Cochin Pipeline System; and
- two terminal acquisitions and a liquids terminal expansion project.
We expect to fund these acquisitions using a combination of borrowings under our commercial paper program, the issuance of new long-term debt, and/or the issuance of additional i-units to Kinder Morgan Management. We expect to secure a new temporary credit facility in the amount of $750 million to support an increase in outstanding commercial paper until permanent financing is put in place.
We announced on February 15, 2002 the termination of the proposed Sonoran Pipeline project, a proposed joint venture with Calpine Corporation, due to insufficient binding commitments from shippers to support the project. We did not spend significant dollars on the proposed development of the pipeline and it was not expected to begin service until 2004. The Sonoran Pipeline would have extended from the Blanco Hub and terminated near Needles and Topock, California, with the possibility of a second phase extending into northern California.
At December 31, 2001, our current commitments for capital expenditures were approximately $73.8 million. This amount has primarily been committed for the purchase of plant and equipment and is based on the payments we expect to need for our 2002 sustaining capital expenditure plan. We fund sustaining capital expenditures with cash flows from operating activities. All of our capital expenditures, with the exception of sustaining capital expenditures, are discretionary.
OPERATING ACTIVITIES
Net cash provided by operating activities was $581.2 million in 2001 versus $301.6 million in 2000. The $279.6 million increase in 2001 was driven by a $211.0 million increase in cash earnings, reflecting the strong performance and growth that occurred across most of our business portfolio. The year-to-year increase in operating cash flows also reflects the $52.5 million of tariff rate refund payments we made during 2000. The payment of these rate refunds was made under settlement agreements between shippers and our Natural Gas Pipelines. Distributions from our equity investments increased $21.3 million, mainly due to distributions received from our 50% investment in Cortez Pipeline Company. Following our
acquisition of the remaining ownership interest in KMCO(2) on April 1, 2000, we accounted for our investment in Cortez Pipeline Company under the equity method of accounting. The overall increase in cash provided by operating activities was partially offset by lower cash inflows relative to payments made on current accounts, primarily due to the business acquisitions we made during 2001.
INVESTING ACTIVITIES
Net cash used in investing activities was $1,818.9 million for the year ended December 31, 2001, compared to $1,197.6 million for the prior year. The $621.3 million increase in funds utilized in investing activities was mainly attributable to higher amounts spent on both asset acquisitions and capital expenditures. We continue to invest significantly in strategic acquisitions in order to fuel future growth and increase unitholder value. In 2001, we spent $1,523.5 million to acquire new assets and businesses. In 2000, our expenditures on acquisitions were $1,008.6 million.
Our expenditures in 2001 included:
- $982.7 million for the acquisition of GATX Corporation's domestic pipelines and terminals business, including KMLT, CALNEV Pipe Line LLC and Central Florida Pipeline LLC;
- $359.1 million for KM Texas Pipeline, L.P.;
- $44.8 million for liquids terminals acquired from an affiliate of Stolt-Nielsen, Inc.;
- $43.6 million for bulk terminal LLC's acquired from Koninklijke Vopak N.V.;
- $41.7 million for Pinney Dock & Transport LLC; and
- $18.0 million for bulk and liquids terminal assets acquired from Boswell Oil Company.
We expended an additional $169.6 million for capital expenditures in 2001 compared to 2000. Including expansion and maintenance projects, our capital expenditures were $295.1 million in 2001 and $125.5 million in 2000. The increase was driven primarily by continued investment in our CO(2) Pipelines and Natural Gas Pipelines business segments. Our overall increase in cash used in investing activities was partially offset by a reduction in expenditures for acquisitions of investments during 2001.
Our 2000 investment outlays included:
- $34.2 million for our 7.5% interest in the Yates field unit subsequently contributed to the carbon dioxide joint venture with Marathon Oil Company (MKM Partners, L.P.); and
- $44.6 million for our 25% interest in Thunder Creek and our 50% interest in Coyote Gas Treating, LLC.
FINANCING ACTIVITIES
Net cash provided by financing activities amounted to $1,241.2 million in 2001. This increase of $325.9 million from the prior year was the result of an additional $829.5 million we received from the issuance of limited partner units. In May 2001, we received net proceeds of approximately $996.9 million from Kinder Morgan Management for the issuance of i-units. In connection with Kinder Morgan Management's public offering of its shares, i-units were issued as follows:
- 2,975,000 units to KMI; and
- 26,775,000 to the public.
We used the proceeds from our i-unit issuance to reduce the debt we incurred in our acquisition of GATX Corporation's domestic pipeline and liquids terminal businesses during the first quarter of 2001. The i-units are a separate class of limited partner interest in us. All of our i-units are owned by Kinder Morgan Management and are not publicly traded.
The overall increase in funds received from the issuance of units increased in 2001 although proceeds from the issuance of common units decreased by $167.4 million. This was attributable to our 9 million common unit public offering on April 4, 2000, which resulted in net proceeds of $171.2 million. Additionally, our issuance of debt, net of repayments, provided $729.6 million in cash during 2001 versus $1,033.4 million during 2000. Our debt repayments increased as a result of the use of proceeds from our i-unit issuance. Funds received from our issuance of debt is attributable to our 2001 public offering of $1.0 billion in principal amount of senior notes, resulting in a net cash inflow of $990 million, net of discounts and issuing costs. We used the proceeds to pay for our acquisition of Pinney Dock & Transport LLC and to reduce the outstanding balances on our credit facilities and commercial paper borrowings. During 2000, we completed two private placements totaling $650 million in debt securities resulting in a cash inflow of $644.7 million, net of discounts and issuing costs.
The overall increase in funds provided by our financing activities was also offset by a $179.6 million increase in cash distributions to our partners. Cash distributions to all partners increased to $473.2 million in 2001 compared to $293.6 million in 2000. The increase in distributions was due to:
- an increase in the per unit cash distributions paid;
- an increase in the number of units outstanding; and
- an increase in the general partner incentive distributions, which resulted from both increased cash distributions per unit and an increase in the number of common units and i-units outstanding.
We paid distributions of $2.08 per unit in quarterly distributions in 2001 compared to $1.60 per unit in 2000. The 30% increase in paid distributions per unit resulted from favorable operating results in 2001.
We also distributed 886,361 i-units in quarterly distributions during 2001 to Kinder Morgan Management, our sole i-unitholder. The amount of i-units distributed was based upon the amount of cash we distributed to the owners of our common units for the second and third quarters of 2001. For each outstanding i-unit that Kinder Morgan Management held, a fraction of an i-unit was issued. The fraction was determined by dividing:
- the cash amount distributed per common unit
by
- the average of Kinder Morgan Management's shares' closing market prices for the ten consecutive trading days preceding the date on which the shares began to trade ex-dividend under the rules of the New York Stock Exchange.
PARTNERSHIP DISTRIBUTIONS
Our partnership agreement requires that we distribute 100% of "Available Cash" (as defined in our partnership agreement) to our partners within 45 days following the end of each calendar quarter in accordance with their respective percentage interests as described below. Available Cash consists generally of all of our cash receipts, including cash received by our operating partnerships, and net reductions in reserves less cash disbursements and net additions to reserves (including any reserves required under debt instruments for future principal and interest payments) and amounts payable to the former general partner of SFPP, L.P. in respect of its remaining 0.5% interest in SFPP, L.P.
Our general partner is granted discretion by our partnership agreement, which discretion has been delegated to Kinder Morgan Management, subject to the approval of our general partner in certain cases, to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, rate refunds and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When Kinder Morgan Management determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level. For 2001, 2000 and 1999, we distributed 100%, 102% and 97%, of the total of cash receipts less cash
disbursements, respectively. The difference between these numbers and 100% reflects net additions to or reductions in reserves.
Typically, our general partner and owners of our common units and Class B units receive distributions in cash, while Kinder Morgan Management, the sole owner of our i-units, receives distributions in additional i-units. For each outstanding i-unit, a fraction of an i-unit will be issued. The fraction is calculated by dividing the amount of cash being distributed per common unit by the average closing price of Kinder Morgan Management's shares over the ten consecutive trading days preceding the date on which the shares begin to trade ex-dividend under the rules of the New York Stock Exchange. The cash equivalent of distributions of i-units will be treated as if it had actually been distributed for purposes of determining the distributions to our general partner. We will not distribute cash to i-unit owners but will retain the cash for use in our business.
Available Cash is initially distributed 98% to our limited partners and 2% to our general partner. These distribution percentages are modified to provide for incentive distributions to be paid to our general partner in the event that quarterly distributions to unitholders exceed certain specified targets.
Available Cash for each quarter is distributed;
- first, 98% to the owners of all classes of units pro rata and 2% to our general partner until the owners of all classes of units have received a total of $0.15125 per unit in cash or equivalent i-units for such quarter;
- second, 85% of any available cash then remaining to the owners of all classes of units pro rata and 15% to our general partner until the owners of all classes of units have received a total of $0.17875 per unit in cash or equivalent i-units for such quarter;
- third, 75% of any available cash then remaining to the owners of all classes of units pro rata and 25% to our general partner until the owners of all classes of units have received a total of $0.23375 per unit in cash or equivalent i-units for such quarter; and
- fourth, 50% of any available cash then remaining to the owners of all classes of units pro rata, to owners of common units and Class B units in cash and to owners of i-units in the equivalent number of i-units, and 50% to our general partner.
Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate amount of cash being distributed. The general partner's incentive distribution that we declared for 2001 was $199.7 million, while the incentive distribution paid to our general partner during 2001 was $178.1 million. All partnership distributions we declared for the fourth quarters of each year were declared and paid in the first quarter of the following year.
On February 14, 2002, we paid a quarterly distribution of $0.55 per unit for the fourth quarter of 2001, 16% greater than the $0.475 distribution paid for the fourth quarter of 2000 and 5% greater than the $0.525 distribution paid for the first quarter of 2001. We paid this distribution in cash to our common unitholders and to our Class B unitholders. Kinder Morgan Management, our sole i-unitholder, received additional i-units based on the $0.55 cash distribution per common unit.
DEBT AND CREDIT FACILITIES
Our debt and credit facilities as of December 31, 2001, consist primarily of:
- $200 million of Floating Rate Senior Notes due March 22, 2002;
- a $750 million unsecured 364-day credit facility due October 23, 2002;
- an $85.2 million unsecured two-year credit facility due June 29, 2003 (our subsidiary, Trailblazer, is the obligor on the facility);
- a $300 million unsecured five-year credit facility due September 29, 2004;
- $200 million of 8.00% Senior Notes due March 15, 2005;
- $250 million of 6.30% Senior Notes due February 1, 2009;
- $250 million of 7.50% Senior Notes due November 1, 2010;
- $700 million of 6.75% Senior Notes due March 15, 2011;
- $25 million of New Jersey Economic Development Revenue Refunding Bonds due January 15, 2018 (our subsidiary, KMLT, is the obligor on the bonds);
- $23.7 million of tax-exempt bonds due 2024 (our subsidiary, Kinder Morgan Operating L.P. "B", is the obligor on the bonds);
- $300 million of 7.40% Senior Notes due March 15, 2031;
- $79.6 million of Series F First Mortgage Notes due December 2004 (our subsidiary, SFPP, L.P. is the obligor on the notes);
- $87.9 million of Industrial Revenue Bonds with final maturities ranging from September 2019 to December 2024 (our subsidiary, KMLT, is the obligor on the bonds);
- $35 million of 7.84% Senior Notes, with a final maturity of July 2008 (our subsidiary, Central Florida Pipe Line LLC, is the obligor on the notes); and
- a $900 million short-term commercial paper program.
None of our debt or credit facilities are subject to payment acceleration as a result of any change to our credit ratings. Our short-term debt at December 31, 2001, consisted of:
- $590.5 million of commercial paper borrowings;
- $200.0 million under our Floating Rate Senior Notes due March 22, 2002;
- $42.5 million under SFPP L.P.'s 10.70% Series F First Mortgage Notes; and
- $3.5 million in other borrowings.
Based on prior successful short-term debt refinancings and current market conditions, we intend and have the ability to refinance $276.3 million of our short-term debt on a long-term basis under our unsecured five-year credit facility, and we do not anticipate any liquidity problems.
During 2001, our cash used for acquisitions and expansions exceeded $1.5 billion. We utilized our short-term credit facilities and issued long-term debt securities to fund these acquisitions and then reduced our short-term borrowings with the proceeds from our May 2001 issuance of i-units. Historically, we have utilized our short-term credit facilities to fund acquisitions and expansions and then refinanced our short-term borrowings utilizing long-term credit facilities and by issuing equity or long-term debt securities. We intend to refinance our short-term debt during 2002 through a combination of long-term debt, equity and the issuance of additional commercial paper to replace maturing commercial paper borrowings.
Credit Facilities
Our $750 million and $300 million credit facilities referred to above are with a syndicate of financial institutions. First Union National Bank is the administrative agent under these facilities. Interest on borrowings is payable quarterly, and accrues at our option at a floating rate equal to either:
- First Union National Bank's base rate (but not less than the Federal Funds Rate, plus 0.5%) (as of December 31, 2001, First Union National Bank's base rate was 4.75%); or
- LIBOR, plus a margin, which varies depending upon the credit rating of our long-term senior unsecured debt (as of December 31, 2001, we could borrow for one month at a rate of 2.395% under our 364-day facility and 2.345% under our 5-year facility).
These rates have decreased since the beginning of 2001 as short-term interest rates have fallen. Our five-year credit facility also permits us to obtain bids for fixed rate loans from members of the lending syndicate.
Our credit facilities include the following restrictive covenants as of December 31, 2001:
- requirements to maintain certain financial ratios: total debt divided by EBITDA for the prior four quarters may not exceed 4.0, and EBITDA for the prior four quarters divided by interest expense for the prior four quarters may not fall below 3.5;
- limitations on our ability to incur additional debt having a senior position to the indebtedness under our credit facilities and on the amount of additional indebtedness that may be incurred by our subsidiaries;
- limitations on entering into mergers, consolidations and sales of assets;
- limitations on granting liens;
- prohibitions on making cash distributions to holders of units more frequently than quarterly;
- prohibitions on making cash distributions in excess of 100% of available cash for the immediately preceding calendar quarter; and
- prohibitions on making any distribution to holders of units if an event of default exists or would exist upon making such distribution.
We are in compliance with these covenants. No borrowings were outstanding under our two credit facilities at December 31, 2001. After taking into account outstanding commercial paper borrowings and letters of credit, the amount available for borrowing under our credit facilities was $435.8 million as of December 31, 2001. We intend to secure promptly after the date of this document an additional $750 million credit facility to back-up an increase in our commercial paper program to $1.8 billion to fund the Tejas acquisition. We expect to terminate this facility once we have issued debt and equity to permanently finance the acquisition. At that time, our commercial paper capacity will be reduced to $1.05 billion. We expect to increase the debt to EBITDA ratio allowed by our credit facilities to 4.25 to 1 through June 30, 2002.
We have an outstanding letter of credit issued under our five-year credit facility in the amount of $23.7 million that backs-up our tax-exempt bonds due 2024. The letter of credit reduces the amount available for borrowing under that credit facility. The $23.7 million principal amount of tax-exempt bonds due 2024 were issued by the Jackson-Union Counties Regional Port District. These bonds bear interest at a weekly floating market rate. At December 31, 2001, the interest rate was 1.70%.
Commercial Paper Program
In December 1999, we established a commercial paper program providing for the issuance of up to $200 million of commercial paper, subsequently increased to $300 million in January 2000. On October 25, 2000, in conjunction with our new 364-day credit facility, we also increased our commercial paper program to provide for the issuance of up to $600 million of commercial paper. During the first quarter of 2001, we increased our commercial paper program to provide for the issuance of an additional $1.1 billion of commercial paper, and during the second quarter of 2001, we decreased our commercial paper program back to $600 million. On October 17, 2001, we increased our commercial paper program to $900 million. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facilities. As of December 31, 2001, we had $590.5 million of commercial paper outstanding with an interest rate of 2.6585%. The borrowings under our commercial paper program were used to finance acquisitions and expansion projects that occurred during 2001. On February 11, 2002, our commercial paper program was increased to provide for the issuance of up to $1.8 billion of commercial paper. We intend to secure promptly after the date of this document an additional $750 million credit facility to back-up the increase in our commercial paper program. We expect to terminate this facility once we have
issued debt and equity to permanently finance the acquisition. At that time, our commercial paper capacity will be reduced to $1.05 billion. We expect to increase the debt to EBITDA ratio allowed by our credit facilities to 4.25 to 1 through June 30, 2002.
Trailblazer Pipeline Company Debt
At December 31, 2000, Trailblazer had a $10 million borrowing under an intercompany account payable in favor of KMI. In January 2001, Trailblazer entered into a 364-day revolving credit agreement with Credit Lyonnais New York Branch, providing for loans up to $10 million. The borrowings were used to pay the account payable to KMI. The agreement was to expire on December 27, 2001. The agreement provided for an interest rate of LIBOR plus 0.875%. Pursuant to the terms of the revolving credit agreement with Credit Lyonnais New York Branch, Trailblazer's partnership distributions were restricted by certain financial covenants.
On June 26, 2001, Trailblazer entered into a new two-year unsecured revolving credit facility with a bank syndication. The new facility, as amended August 24, 2001, provides for loans of up to $85.2 million and expires June 29, 2003. The agreement provides for an interest rate of LIBOR plus a margin as determined by certain financial ratios. On June 29, 2001, Trailblazer paid the $10 million outstanding balance under its 364-day revolving credit agreement and terminated that agreement. At December 31, 2001, the outstanding balance under Trailblazer's two-year revolving credit facility was $55.0 million, with a weighted average interest rate of 2.875%, which reflects three-month LIBOR plus a margin of 0.875%. Pursuant to the terms of the revolving credit facility, Trailblazer's partnership distributions are restricted by certain financial covenants. We do not believe that these restrictions will materially affect distributions to our partners.
On September 23, 1992, pursuant to the terms of a Note Purchase Agreement, Trailblazer Pipeline Company issued and sold an aggregate principal amount of $101 million of Senior Secured Notes to a syndicate of fifteen insurance companies. The Senior Secured Notes had a fixed annual interest rate of 8.03% and the $20.2 million balance as of December 31, 2000 was to be repaid in semiannual installments of $5.05 million from March 1, 2001 through September 1, 2002, the final maturity date. Interest was payable semiannually in March and September. Trailblazer provided collateral for the notes principally by an assignment of certain Trailblazer transportation contracts, and pursuant to the terms of this Note Purchase Agreement, Trailblazer's partnership distributions were restricted by certain financial covenants. Effective April 29, 1997, Trailblazer amended the Note Purchase Agreement. This amendment allowed Trailblazer to include several additional transportation contracts as collateral for the notes, added a limitation on the amount of additional money that Trailblazer could borrow and relieved Trailblazer from its security deposit obligation. On June 26, 2001, Trailblazer prepaid the $15.2 million balance outstanding under the Senior Secured Notes, plus $0.8 million for interest and a make-whole premium, using its new two-year unsecured revolving credit facility.
SFPP, L.P. Debt
At December 31, 2001, the outstanding balance under SFPP, L.P.'s Series F notes was $79.6 million. The annual interest rate on the Series F notes is 10.70%, the maturity is December 2004, and interest is payable semiannually in June and December. We expect to repay the Series F notes prior to maturity as a result of SFPP, L.P. taking advantage of certain optional prepayment provisions without penalty in 1999 and 2000. Remaining annual installments are $42.6 million in 2002 and $37.0 million in 2003. Additionally, the Series F notes may be prepaid in full or in part at a price equal to par plus, in certain circumstances, a premium. We agreed as part of the acquisition of SFPP, L.P.'s operations (which constitute a significant portion of our Pacific operations) not to take actions with respect to $190 million of SFPP, L.P.'s debt that would cause adverse tax consequences for the prior general partner of SFPP, L.P. The Series F notes are secured by mortgages on substantially all of the properties of SFPP, L.P. The Series F notes contain certain covenants limiting the amount of additional debt or equity that may be issued by SFPP, L.P. and limiting the amount of cash distributions, investments, and property dispositions by SFPP, L.P. We do not believe that these restrictions will materially affect distributions to our partners.
Kinder Morgan Liquids Terminals LLC Debt
Effective January 1, 2001, we acquired KMLT. As part of our purchase price, we assumed debt of $87.9 million, consisting of five series of Industrial Revenue Bonds. The Bonds consist of the following:
- $4.1 million of 7.30% New Jersey Industrial Revenue Bonds due September 1, 2019;
- $59.5 million of 6.95% Texas Industrial Revenue Bonds due February 1, 2022;
- $7.4 million of 6.65% New Jersey Industrial Revenue Bonds due September 1, 2022;
- $13.3 million of 7.00% Louisiana Industrial Revenue Bonds due March 1, 2023; and
- $3.6 million of 6.625% Texas Industrial Revenue Bonds due February 1, 2024.
In November 2001, we closed on a sale and purchase agreement with Stolthaven Perth Amboy Inc. and Stolt-Nielsen Transportation Group, Ltd. to acquire a liquids terminal in Perth Amboy, New Jersey. As part of our purchase price, we assumed debt of $25.0 million, consisting of $25.0 million of Economic Development Revenue Refunding Bonds issued by the New Jersey Economic Development Authority. The bonds have a maturity date of January 15, 2018. Interest on these bonds will be computed on the basis of a year of 365 or 366 days, as applicable, for the actual number of days elapsed during Commercial Paper, Daily or Weekly Rate Periods and on the basis of a 360-day year consisting of twelve 30-day months during a Term Rate Period. As of December 31, 2001, the interest rate was 1.391%.
We have an outstanding letter of credit issued by Citibank in the amount of $25.3 million that backs-up our $25 million of New Jersey Economic Development Revenue Refunding Bonds due January 15, 2018. The letter of credit backs-up the $25.0 million principal amount of the bonds and $0.3 million of interest on the bonds for up to 42 days computed at 12% on a per annum basis on the principal thereof.
Central Florida Pipeline LLC Debt
Effective January 1, 2001, we acquired Central Florida Pipeline LLC. As part of our purchase price, we assumed an aggregate principal amount of $40 million of Senior Notes originally issued to a syndicate of eight insurance companies. The Senior Notes have a fixed annual interest rate of 7.84% and will be repaid in annual installments of $5 million beginning July 23, 2001. The final payment is due July 23, 2008. Interest is payable semiannually on January 1 and July 23 of each year. At December 31, 2001, Central Florida's outstanding balance under the Senior Notes was $35.0 million.
CALNEV Pipe Line LLC Debt
Effective March 30, 2001, we acquired CALNEV Pipe Line LLC. As part of our purchase price, we assumed an aggregate principal amount of $6.8 million of Senior Notes originally issued to a syndicate of five insurance companies. The Senior Notes had a fixed annual interest rate of 10.07%. In June 2001, we prepaid the balance outstanding under the Senior Notes, plus $0.9 million for interest and a make-whole premium, from cash on hand.
Senior Notes
From time to time we issue long-term debt securities. All of our long-term debt securities issued to date, other than those issued under our revolving credit facilities, generally have the same terms except for interest rates, maturity dates and prepayment restrictions. All of our outstanding debt securities are unsecured obligations that rank equally with all of our other senior debt obligations. Our outstanding debt securities as of December 31, 2001, consist of the following:
- $250 million in principal amount of 6.3% senior notes due February 1, 2009. These notes were issued on January 29, 1999 at a price to the public of 99.67% per note. In the offering, we received proceeds, net of underwriting discounts and commissions, of approximately $248 million. We used
the proceeds to pay the outstanding balance on our credit facility and for working capital and other partnership purposes;
- $200 million of floating rate notes due March 22, 2002 and $200 million of 8.0% notes due March 15, 2005. In the offering, we received proceeds, net of underwriting discounts and commissions of approximately $397.9 million. We used the proceeds to reduce outstanding commercial paper. At December 31, 2001, the interest rate on our floating rate notes was 3.1025%;
- $250 million of 7.5% notes due November 1, 2010. These notes were issued on November 8, 2000. The proceeds from this offering, net of underwriting discounts, were $246.8 million. These proceeds were used to reduce our outstanding commercial paper; and
- $700 million of 6.75% notes due March 15, 2011 and $300 million of 7.40% notes due March 15, 2031. In the offering, we received proceeds, net of underwriting discounts and commissions of approximately $990.0 million. We used the proceeds to pay for our acquisition of Pinney Dock & Transport LLC and to reduce our outstanding balance on our credit facilities and commercial paper borrowings.
The fixed rate notes provide that we may redeem the notes at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make-whole premium. We may not prepay the floating rate notes prior to their maturity.
At December 31, 2001, our unamortized liability balance due on the various series of our senior notes were as follows (in millions):
CAPITAL REQUIREMENTS FOR RECENT TRANSACTIONS
During 2001, our cash outlays for the acquisitions of assets totaled $1,523.5 million. We utilized our short-term credit facilities and issued long-term debt securities to fund these acquisitions and then reduced our short-term borrowings with the proceeds from our May 2001 issuance of i-units. We intend to refinance the remainder of our current short-term debt and any additional short-term debt incurred during 2002 through a combination of long-term debt, equity and the issuance of additional commercial paper to replace maturing commercial paper borrowings.
GATX Domestic Pipelines and Terminals Businesses. Effective January 1, 2001 and March 30, 2001, we acquired GATX Corporation's United States pipelines and terminals businesses for approximately $1,231.6 million in aggregate consideration, consisting of $975.4 million in cash, $134.8 million in assumed debt and $121.4 million in assumed liabilities. We borrowed the necessary funds under our commercial paper program.
Pinney Dock & Transport LLC. Effective March 1, 2001, we acquired Pinney Dock & Transport LLC for approximately $52.5 million in aggregate consideration, consisting of $41.7 million in cash and $10.8 million in assumed liabilities. We borrowed the necessary funds under our offering of $1.0 billion in principal amount of senior notes during the first quarter of 2001.
Cochin Pipeline. On June 20, 2001, we acquired an additional 2.3% ownership interest in the Cochin Pipeline system for approximately $8.0 million in cash. We borrowed the necessary funds under our commercial paper program.
Vopak. Effective July 10, 2001, we acquired certain bulk terminal businesses, which were converted or merged into six single-member limited liability companies, for approximately $44.3 million in aggregate consideration, consisting of $43.6 million in cash and $0.7 million in assumed liabilities. We borrowed the necessary funds under our commercial paper program.
KM Texas Pipeline, L.P. Effective July 18, 2001, we acquired KM Texas Pipeline, L.P., a partnership that owns a natural gas pipeline system that we previously leased, for approximately $326.1 million in aggregate consideration, consisting of $359.1 million in cash, and a reduction of $33.0 million from the release of a previously held deferred credit. We borrowed the necessary funds under our commercial paper program.
Boswell. Effective August 31, 2001, we acquired certain bulk and liquids terminal assets from The Boswell Oil Company for approximately $22.2 million in aggregate consideration, consisting of $18.1 million in cash, $3.0 million from the issuance of a short-term note payable and $1.1 million in assumed liabilities. We borrowed the necessary funds under our commercial paper program.
Stolt-Nielsen. On November 8, 2001 and November 29, 2001, we acquired from affiliates of Stolt-Nielsen, Inc. certain liquids terminal assets for totaling approximately $69.8 million in aggregate consideration, consisting of $44.8 million in cash and $25.0 million in assumed debt. We borrowed the necessary funds under our commercial paper program.
Carbon Dioxide Business Interests. In November and December 2001, we paid approximately $14.7 million in cash for additional ownership interests in the Snyder Gasoline Plant and the Diamond M Gas Plant, both located in the Permian Basin of west Texas. We borrowed the necessary funds under our commercial paper program.
NEW ACCOUNTING PRONOUNCEMENTS
Statement of Financial Accounting Standards No. 141 supercedes Accounting Principles Board Opinion No. 16 and requires that all transactions fitting the description of a business combination be accounted for using the purchase method and prohibits the use of the pooling of interests for all business combinations initiated after June 30, 2001. The Statement also modifies the accounting for the excess of fair value of net assets acquired as well as intangible assets acquired in a business combination. The provisions of this statement apply to all business combinations initiated after June 30, 2001, and all business combinations accounted for by the purchase method that are completed after July 1, 2001. This Statement requires disclosure of the primary reasons for a business combination and the allocation of the purchase price paid to the assets acquired and liabilities assumed by major balance sheet caption. After July 1, 2001, we completed four acquisitions and have initiated or announced four additional acquisitions. Refer to Note 3 to the Consolidated Financial Statements included elsewhere in this report for more detail about our acquisitions.
SFAS No. 142 "Goodwill and Other Intangible Assets" supercedes Accounting Principles Board Opinion No. 17 and requires that goodwill no longer be amortized but should be tested, at least on an annual basis, for impairment. A benchmark assessment of potential impairment must also be completed within six months of adopting SFAS No. 142. After the first six months, goodwill will be tested for impairment annually. SFAS No. 142 applies to any goodwill acquired in a business combination completed after June 30, 2001. Other intangible assets are to be amortized over their useful life and reviewed for impairment in accordance with the provisions of SFAS No. 121,"Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed Of". An intangible asset with an indefinite useful life can no longer be amortized until its useful life becomes determinable. This Statement requires disclosure of information about goodwill and other intangible assets in the years subsequent to their acquisition that was not previously required. Required disclosures include information about the changes in the carrying amount of goodwill from period to period and the carrying amount of intangible assets by major intangible asset class. After June 30, 2001, we completed two acquisitions, our Boswell and Stolt-Nielsen acquisitions, which resulted in the recognition of goodwill. We adopted SFAS No. 142 on January 1, 2002, and we expect that SFAS No. 142 will not have a material impact on our business,
financial position or results of operations. With the adoption of SFAS No. 142, goodwill of approximately $546.7 million is no longer subject to amortization over its estimated useful life.
In July 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations". This statement requires companies to record a liability relating to the retirement and removal of assets used in their business. The liability is discounted to its present value, and the relative asset value is increased by the same amount. Over the life of the asset, the liability will be accreted to its future value and eventually extinguished when the asset is taken out of service. The provisions of this statement are effective for fiscal years beginning after June 15, 2002. We do not expect that SFAS No. 143 will have a material impact on our business, financial position or results of operations.
On January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This statement retains the requirements of SFAS 121, mentioned above, however, this statement requires that long-lived assets that are to be disposed of by sale be measured at the lower of book value or fair value less the cost to sell it. Furthermore, the scope of discontinued operations is expanded to include all components of an entity with operations of the entity in a disposal transaction. The adoption of SFAS No. 144 has not had an impact on our business, financial position or results of operations.
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This filing includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as "anticipate," "believe," "intend," "plan," "projection," "forecast," "strategy," "position," "continue," "estimate," "expect," "may," "will," or the negative of those terms or other variations of them or comparable terminology. In particular, statements, express or implied, concerning future operating results or the ability to generate sales, income or cash flow or to make distributions are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. The future results of our operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements, include:
- price trends and overall demand for natural gas liquids, refined petroleum products, oil, carbon dioxide, natural gas, coal and other bulk materials and chemicals in the United States. Consumer confidence, economic activity, political instability, weather, alternative energy sources, conservation and technological advances may affect price trends and demand;
- changes in our tariff rates implemented by the Federal Energy Regulatory Commission or the California Public Utilities Commission;
- our ability to integrate any acquired operations into our existing operations;
- any difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to our terminals;
- our ability to successfully identify and close strategic acquisitions and make cost saving changes in operations;
- shut-downs or cutbacks at major refineries, petrochemical or chemical plants, utilities, military bases or other businesses that use or supply our services;
- changes in laws or regulations, third party relations and approvals, decisions of courts, regulators and governmental bodies may adversely affect our business or our ability to compete;
- indebtedness could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, place us at competitive disadvantages compared to our competitors that have less debt or have other adverse consequences;
- interruptions of electric power supply to our facilities due to natural disasters, power shortages, strikes, riots, terrorism, war or other causes;
- acts of sabotage and terrorism for which insurance is not available at reasonable premiums;
- the condition of the capital markets and equity markets in the United States; and
- the political and economic stability of the oil producing nations of the world.
You should not put undue reliance on any forward-looking statements.
See Items 1 and 2 "Business and Properties -- Risk Factors" for a more detailed description of these and other factors that may affect the forward-looking statements. Our future results also could be adversely impacted by unfavorable results of litigation and the fruition of contingencies referred to in Note 16 to the Consolidated Financial Statements included elsewhere in this report. When considering forward-looking statements, one should keep in mind the risk factors described in "Risk Factors" above. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
ENERGY FINANCIAL INSTRUMENTS
We use energy financial instruments to reduce our risk of price changes in the spot and fixed price natural gas, natural gas liquids, crude oil and carbon dioxide markets. For a complete discussion of our risk management activities, see Note 14 to the Consolidated Financial Statements included elsewhere in this report.
To minimize the risks associated with changes in the market price of natural gas and associated transportation, natural gas liquids, crude oil and carbon dioxide, we use certain financial instruments for hedging purposes. These instruments include energy products traded on the New York Mercantile Exchange and over-the-counter markets including, but not limited to, futures and options contracts, fixed-price swaps and basis swaps. We are exposed to credit-related losses in the event of nonperformance by counterparties to these financial instruments but, given their existing credit ratings, we do not expect any counterparties to fail to meet their obligations. The credit ratings of the primary parties from whom we purchase financial instruments are as follows:
During the fourth quarter of 2001, we determined that Enron Corp. was no longer likely to honor the obligations it had to us in conjunction with derivatives we were accounting for as hedges under Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities". Upon making that determination, we:
- ceased to account for those derivatives as hedges;
- entered into new derivative transactions with other counterparties to replace our position with Enron;
- designated the replacement derivative positions as hedges of the exposures that had been hedged with the Enron positions; and
- recognized a $6.0 million loss (included with "General and administrative" expenses in the accompanying Consolidated Statement of Operations for 2001) in recognition of the fact that it was unlikely that we would be paid the amounts then owed under the contracts with Enron.
While we enter into derivative transactions only with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that additional losses will result from counterparty credit risk in the future.
Pursuant to our management's approved policy, we are to engage in these activities only as a hedging mechanism against price volatility associated with:
- pre-existing or anticipated physical natural gas, natural gas liquids, crude oil and carbon dioxide sales;
- natural gas purchases; and
- system use and storage.
Our risk management activities are only used in order to protect our profit margins and our risk management policies prohibit us from engaging in speculative trading. Commodity-related activities of our risk management group are monitored by KMI's Risk Management Committee, which is charged with the review and enforcement of our management's risk management policy.
Through December 31, 2000, gains and losses on hedging positions were deferred and recognized as cost of sales in the periods in which the underlying physical transactions occur. On January 1, 2001, we began accounting for derivative instruments under Statement of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging Activities" (after amendment by SFAS 137 and SFAS 138). As discussed above, our principal use of derivative financial instruments is to mitigate the market price risk associated with anticipated transactions for the purchase and sale of natural gas, natural gas liquids, crude oil and carbon dioxide. SFAS No. 133 allows these transactions to continue to be treated as hedges for accounting purposes, although the changes in the market value of these instruments will affect comprehensive income in the period in which they occur and any ineffectiveness in the risk mitigation performance of the hedge will affect net income currently. The change in the market value of these instruments representing effective hedge operation will continue to affect net income in the period in which the associated physical transactions are consummated. Adoption of SFAS No. 133 has resulted in $63.8 million of deferred net gain being reported as accumulated other comprehensive income in the accompanying balance sheet at December 31, 2001.
We measure the risk of price changes in the natural gas, natural gas liquids, crude oil and carbon dioxide markets utilizing a Value-at-Risk model. Value-at-Risk is a statistical measure of how much the mark-to-market value of a portfolio could change during a period of time, within a certain level of statistical confidence. We utilize a closed form model to evaluate risk on a daily basis. The Value-at-Risk computations utilize a confidence level of 97.7% for the resultant price movement and a holding period of one day chosen for the calculation. The confidence level used means that there is a 97.7% probability that the mark-to-market losses for a single day will not exceed the Value-at-Risk number presented. Financial instruments evaluated by the model include commodity futures and options contracts, fixed price swaps, basis swaps and over-the-counter options. During 2001, Value-at-Risk reached a high of $19.9 million and a low of $12.8 million. Value-at-Risk at December 31, 2001, was $14.6 million and averaged $16.7 million for 2001.
Our calculated Value-at-Risk exposure represents an estimate of the reasonably possible net losses that would be recognized on our portfolio or derivatives assuming hypothetical movements in future market rates, and is not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our portfolio of derivatives during the year.
INTEREST RATE RISK
The market risk inherent in our debt instruments and positions is the potential change arising from increases or decreases in interest rates as discussed below. Generally, our market risk sensitive instruments and positions are characterized as "other than trading." Our exposure to market risk as discussed below includes forward-looking statements and represents an estimate of possible changes in fair value or future earnings that would occur assuming hypothetical future movements in interest rates. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated, based on actual fluctuations in interest rates and the timing of transactions.
We utilize both variable rate and fixed rate debt in our financing strategy. See Note 9 to the Consolidated Financial Statements included elsewhere in this report for additional information related to our debt instruments. For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows. We do not have an obligation to prepay fixed rate debt prior to maturity and, as a result, interest rate risk and changes in fair value should not have a significant impact on our fixed rate debt until we would be required to refinance such debt.
As of December 31, 2001 and 2000, the carrying values of our long-term fixed rate debt were approximately $1,900.6 million and $836.7 million, respectively, compared to fair values of $2,197.9 million and $944.1 million, respectively. Fair values were determined using quoted market prices, where applicable, or future cash flow discounted at market rates for similar types of borrowing arrangements. A hypothetical 10% change in the average interest rates applicable to such debt for 2001 and 2000, respectively, would result in changes of approximately $77.4 million and $23.6 million, respectively, in the fair values of these instruments.
The carrying value and fair value of our variable rate debt, including accrued interest, was $885.4 million as of December 31, 2001 and $1,070.5 million as of December 31, 2000. Fair value was determined using future cash flows discounted based on market rates for similar types of borrowing arrangements. A hypothetical 10% change in the average interest rate applicable to this debt would result in a change of approximately $5.5 million in our 2001 annualized pre-tax earnings.
As of December 31, 2001, we were party to interest rate swap agreements with a notional principal amount of $900 million for the purpose of hedging the interest rate risk associated with our fixed rate debt obligations. A hypothetical 10% change in the average interest rates related to these swaps would not have a material effect on our annual pre-tax earnings. We monitor our mix of fixed rate and variable rate debt obligations in light of changing market conditions and from time to time may alter that mix by, for example, refinancing balances outstanding under our variable rate debt with fixed rate debt (or vice versa) or by entering into interest rate swaps or other interest rate hedging agreements.
As of December 31, 2001, our cash and investment portfolio did not include fixed-income securities. Due to the short-term nature of our investment portfolio, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect our operating results or cash flows to be materially affected to any significant degree by the effect of a sudden change in market interest rates on our investment portfolio.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The information required in this Item 8 is included in this report as set forth in the "Index to Financial Statements" on page 74.
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.
DIRECTORS AND EXECUTIVE OFFICERS OF OUR GENERAL PARTNER AND THE DELEGATE
Set forth below is certain information concerning the directors and executive officers of our general partner and Kinder Morgan Management, LLC as the delegate of our general partner. All directors of our general partner are elected annually by, and may be removed by, Kinder Morgan (Delaware), Inc. as its sole shareholder, and all directors of the delegate are elected annually by, and may be removed by, our general partner as the sole holder of the delegate's voting shares. All officers of the general partner and the delegate serve at the discretion of the board of directors of our general partner. In addition to the individuals named below, KMI is a director of the delegate.
Richard D. Kinder is Director, Chairman and Chief Executive Officer of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and KMI. Mr. Kinder has served as Director, Chairman and Chief Executive Officer of Kinder Morgan Management, LLC since its formation in February 2001. He was elected Director, Chairman and Chief Executive Officer of KMI in October 1999. He was elected Director, Chairman and Chief Executive Officer of Kinder Morgan G.P., Inc. in February 1997. Mr. Kinder is also a director of TransOcean Offshore Inc. and Baker Hughes Incorporated.
William V. Morgan is Director and Vice Chairman of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and KMI. Mr. Morgan served as the President of Kinder Morgan Management, LLC from February 2001 to July 2001. He served as President of KMI from October 1999 to July 2001. He served as President of Kinder Morgan G.P., Inc. from February 1997 to July 2001. Mr. Morgan has served as Director and Vice Chairman of Kinder Morgan Management, LLC since its formation in February 2001. Mr. Morgan has served as Director and Vice Chairman of KMI since October 1999. Mr. Morgan was elected Vice Chairman of Kinder Morgan G.P., Inc. in February 1997. On January 17, 2002, we announced that Mr. Morgan would transition to a non-executive role in April 2003. At that time, Mr. Morgan will retain his Vice Chairman title and remain an active board member, but he will be less involved in our day-to-day operations. Mr. Morgan is the father of Michael C. Morgan, President of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and KMI.
Michael C. Morgan is President of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and KMI. Mr. Morgan was elected to each of these positions in July 2001. Mr. Morgan served as Vice President, Strategy and Investor Relations of Kinder Morgan Management, LLC from February 2001 to July 2001. He served as Vice President, Strategy and Investor Relations of KMI and Kinder Morgan G.P., Inc. from January 2000 to July 2001. He served as Vice President, Corporate Development of Kinder
Morgan G.P., Inc. from February 1997 to January 2000. Mr. Morgan was the Vice President, Corporate Development of KMI from October 1999 to January 2000. From August 1995 until February 1997, Mr. Morgan was an associate with McKinsey & Company, an international management consulting firm. In 1995, Mr. Morgan received a Masters in Business Administration from the Harvard Business School. From March 1991 to June 1993, Mr. Morgan held various positions, including Assistant to the Chairman, at PSI Energy, Inc. Mr. Morgan received a Bachelor of Arts in Economics and a Masters of Arts in Sociology from Stanford University in 1990. Mr. Morgan is the son of William V. Morgan.
Edward O. Gaylord is a Director of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Gaylord was elected Director of Kinder Morgan Management, LLC upon its formation in February 2001. Mr. Gaylord was elected Director of Kinder Morgan G.P., Inc. in February 1997. Since 1989, Mr. Gaylord has been the Chairman of the Board of Directors of Jacintoport Terminal Company, a liquid bulk storage terminal on the Houston, Texas ship channel. Mr. Gaylord serves on the Board of Directors of Seneca Foods Corporation and is Chairman of the Board of Directors of the Houston Branch of the Federal Reserve Bank of Dallas.
Gary L. Hultquist is a Director of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Hultquist was elected Director of Kinder Morgan Management, LLC upon its formation in February 2001. He was elected Director of Kinder Morgan G.P., Inc. in October 1999. Since 1995, Mr. Hultquist has been the Managing Director of Hultquist Capital, LLC, a San Francisco-based strategic and merger advisory firm. Mr. Hultquist is a member of the Board of Directors of netMercury, Inc., a supplier of automated supply chain services, critical spare parts and consumables used in semiconductor manufacturing. Previously, Mr. Hultquist practiced law in two San Francisco area firms for over 15 years, specializing in business, intellectual property, securities and venture capital litigation.
Perry M. Waughtal is a Director of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Waughtal was elected Director of Kinder Morgan Management, LLC upon its formation in February 2001. Mr. Waughtal was elected Director of Kinder Morgan G.P., Inc. in April 2000. Mr. Waughtal is the Chairman, a limited partner and a 40% owner of Songy Partners Limited, an Atlanta, Georgia based real estate investment company. Mr. Waughtal advises Songy's management on real estate investments and has overall responsibility for strategic planning, management and operations. Previously, Mr. Waughtal served for over 30 years as Vice Chairman of Development and Operations and as Chief Financial Officer for Hines Interests Limited Partnership, a real estate and development entity based in Houston, Texas.
William V. Allison is President, Natural Gas Pipelines of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and KMI. Mr. Allison was elected President, Natural Gas Pipelines of Kinder Morgan Management, LLC upon its formation in February 2001. He was elected President, Natural Gas Pipelines of Kinder Morgan G.P., Inc. and of KMI in September 1999. He was President, Pipeline Operations of Kinder Morgan G.P., Inc. from February 1999 to September 1999. Mr. Allison served as Vice President and General Counsel of Kinder Morgan G.P., Inc. from April 1998 to February 1999. From May 1997 to April 1998, Mr. Allison managed his personal investments. From April 1996 through May 1997, Mr. Allison served as President of Enron Liquid Services Corporation. On February 8, 2002, we announced that Mr. Allison will retire effective June 1, 2002.
Thomas A. Bannigan is President, Product Pipelines of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. and President and Chief Executive Officer of Plantation Pipe Line Company. Mr. Bannigan was elected President, Product Pipelines of Kinder Morgan Management, LLC upon its formation in February 2001. He was elected President, Products Pipelines of Kinder Morgan G.P., Inc. in October 1999. Mr. Bannigan has served as President and Chief Executive Officer of Plantation Pipe Line Company since May 1998. From 1985 to May 1998, Mr. Bannigan was Vice President, General Counsel and Secretary of Plantation Pipe Line Company.
R. Tim Bradley is President, CO(2) Pipelines of Kinder Morgan Management, LLC and of Kinder Morgan G.P., Inc. and President of Kinder Morgan CO(2) Company, L.P. Mr. Bradley was elected President, CO(2) Pipelines of Kinder Morgan Management, LLC and Vice President (President, CO(2) Pipelines) of Kinder Morgan G.P., Inc. in April 2001. Mr. Bradley has been President of Kinder Morgan
CO(2) Company, L.P. (which name changed from Shell CO(2) Company, Ltd. in April 2000) since March 1998. From May 1996 to March 1998, Mr. Bradley was Manager of CO(2) Marketing for Shell Western E&P, Inc. Mr. Bradley received a Bachelor of Science in Petroleum Engineering from the University of Missouri at Rolla.
David G. Dehaemers, Jr. is Vice President, Corporate Development of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and KMI. Mr. Dehaemers was elected Vice President, Corporate Development of Kinder Morgan Management, LLC upon its formation in February 2001. Mr. Dehaemers was elected Vice President, Corporate Development of Kinder Morgan G.P., Inc. and Vice President, Corporate Development of KMI in January 2000. He served as Vice President and Chief Financial Officer of KMI from October 1999 to January 2000. He served as Vice President and Chief Financial Officer of Kinder Morgan G.P., Inc. from July 1997 to January 2000 and Treasurer of Kinder Morgan G.P., Inc. from February 1997 to January 2000. He served as Secretary of Kinder Morgan G.P., Inc. from February 1997 to August 1997. Mr. Dehaemers was previously employed by the national CPA firms of Ernst & Whinney and Arthur Young. Mr. Dehaemers received his law degree from the University of Missouri-Kansas City and is a member of the Missouri Bar. He is also a CPA and received his undergraduate Accounting degree from Creighton University in Omaha, Nebraska.
Joseph Listengart is Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and KMI. Mr. Listengart was elected Vice President, General Counsel and Secretary of Kinder Morgan Management, LLC upon its formation in February 2001. He was elected Vice President and General Counsel of Kinder Morgan G.P., Inc. and Vice President, General Counsel and Secretary of KMI in October 1999. Mr. Listengart was elected Kinder Morgan G.P., Inc.'s Secretary in November 1998 and became an employee of Kinder Morgan G.P., Inc. in March 1998. From March 1995 through February 1998, Mr. Listengart worked as an attorney for Hutchins, Wheeler & Dittmar, a Professional Corporation. Mr. Listengart received his Masters in Business Administration from Boston University in January 1995, his Juris Doctor, magna cum laude, from Boston University in May 1994, and his Bachelor of Arts degree in Economics from Stanford University in June 1990.
C. Park Shaper is Vice President, Treasurer and Chief Financial Officer of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and KMI. Mr. Shaper was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan Management, LLC upon its formation in February 2001. He has served as Treasurer of KMI since April 2000 and Vice President and Chief Financial Officer of KMI since January 2000. Mr. Shaper was elected Vice President, Treasurer and Chief Financial Officer of Kinder Morgan G.P., Inc. in January 2000. From June 1999 to December 1999, Mr. Shaper was President and Director of Altair Corporation, an enterprise focused on the distribution of web-based investment research for the financial services industry. He served as Vice President and Chief Financial Officer of First Data Analytics, a wholly-owned subsidiary of First Data Corporation, from 1997 to June 1999. From 1995 to 1997, he was a consultant with The Boston Consulting Group. He received a Masters in Business Administration degree from the J.L. Kellogg Graduate School of Management at Northwestern University. Mr. Shaper also has a Bachelor of Science degree in Industrial Engineering and a Bachelor of Arts degree in Quantitative Economics from Stanford University.
Thomas B. Stanley is President, Terminals of Kinder Morgan Management, LLC and Kinder Morgan G.P., Inc. Mr. Stanley became President of our Terminals segment in July 2001 when we combined our previously separate Bulk Terminals and Liquids Terminals segments. Prior to that, Mr. Stanley served as President, Bulk Terminals of Kinder Morgan G.P., Inc. since August 1998 and of Kinder Morgan Management, LLC since February 2001. From 1993 to July 1998, he was President of Hall-Buck Marine, Inc. (now known as Kinder Morgan Bulk Terminals, Inc.), for which he has worked since 1980. Mr. Stanley is a CPA with ten years' experience in public accounting, banking, and insurance accounting prior to joining Hall-Buck. He received his bachelor's degree from Louisiana State University in 1972.
James E. Street is Vice President, Human Resources and Administration of Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and KMI. Mr. Street was elected Vice President, Human Resources and Administration of Kinder Morgan Management, LLC upon its formation in February 2001.
He was elected Vice President, Human Resources and Administration of Kinder Morgan G.P., Inc. and KMI in August 1999. From October 1996 to August 1999, Mr. Street was Senior Vice President, Human Resources and Administration for Coral Energy, a subsidiary of Shell Oil Company. Mr. Street received a Masters of Business Administration degree from the University of Nebraska at Omaha and a Bachelor of Science degree from the University of Nebraska at Kearney.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
As is commonly the case for publicly traded limited partnerships, we have no officers. Under our limited partnership agreement, Kinder Morgan G.P., Inc., as the general partner of the partnership, is to direct, control and manage all of our activities. Pursuant to a delegation of control agreement, Kinder Morgan G.P., Inc. has delegated to Kinder Morgan Management, the management and control of our business and affairs to the maximum extent permitted by the partnership agreement and Delaware law, subject to the general partner's right to approve certain actions by Kinder Morgan Management. The executive officers and directors of Kinder Morgan G.P., Inc. serve in the same capacities for Kinder Morgan Management. Certain of those executive officers, including all of the named officers below, also serve as executive officers of KMI. All information in this report with respect to compensation of executive officers describes the total compensation received by those persons in all capacities for Kinder Morgan G.P., Inc., Kinder Morgan Management, KMI and their respective affiliates.
SUMMARY COMPENSATION TABLE
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(1) Effective October 1, 1999, Mr. Kinder's annual salary was reduced to $1.00. Mr. Kinder is not eligible for annual bonuses or option grants.
(2) Mr. Shaper commenced employment with our general partner in January 2000.
(3) Amounts earned in year shown and paid the following year.
(4) Represent shares of restricted KMI stock awarded in 2002 and 2001 that relate to performance in 2001 and 2000, respectively. Value computed as the number of shares awarded (10,000) times the closing price on date of grant ($56.99 at January 16, 2002 and $49.875 at January 17, 2001). Twenty-
five percent of the shares in each grant vest on each of the first four anniversaries after the date of grant. The holders of the restricted stock awards are eligible to vote and to receive dividends declared on such shares.
(5) Does not include for 1999, $3,753,868, or for 2000, $7,010,000 paid to Messrs. Dehaemers and Morgan under our Executive Compensation Plan. The payments made in 2000 were the last payments Messrs. Dehaemers and Morgan are to receive under our Executive Compensation Plan. We do not intend to compensate any employees providing services to us under the Executive Compensation Plan on a going forward basis. See "-- Executive Compensation Plan."
(6) The 150,000 options in KMI shares were granted and became fully vested on April 20, 2000. The options were granted to Messrs. Dehaemers and Morgan in connection with the execution of their employment agreements. See "-- Employment agreements."
(7) For 1999 and 2000, amounts represent our general partner's contributions to the Retirement Savings Plan (a 401(k) plan), the imputed value of general partner-paid group term life insurance exceeding $50,000, and compensation attributable to taxable moving and parking expenses allowed. For 2001, amounts represent contributions to Retirement Savings Plan, value of group-term life insurance exceeding $50,000, parking compensation and a $50 cash payment.
(8) The 6,300 options in KMI shares were granted in 2001, but relate to performance in 2000. The options were granted and became fully exercisable on January 17, 2001 at a grant price of $49.875 per share.
(9) The year 2000 options in KMI shares include 25,000 options granted in 2001, but relating to performance in 2000. These options were granted and became fully exercisable on January 17, 2001 at a grant price of $49.875 per share. The remaining 125,000 options were granted on January 20, 2000 at a grant price of $24.75. These options vest at twenty five percent on each of the first four anniversaries after the date of grant.
Executive Compensation Plan. Pursuant to our Executive Compensation Plan, executive officers of our general partner are eligible for awards equal to a percentage of the "incentive compensation value", which is defined as cash distributions to our general partner during the four calendar quarters preceding the date of redemption multiplied times eight (less a participant adjustment factor, if any). Under the plan, no eligible employee may receive a grant in excess of 2 percent and total awards under the plan may not exceed 10 percent. In general, participants may redeem vested awards in whole or in part from time to time by written notice. We may, at our option, pay the participant in units (provided, however, the unitholders approve the plan prior to issuing such units) or in cash. We may not issue more than 400,000 units in the aggregate under the plan. Units will not be issued to a participant unless such units have been listed for trading on the principal securities exchange on which the units are then listed. The plan terminates January 1, 2007 and any unredeemed awards will be automatically redeemed. However, the plan may be terminated before such date, and upon such early termination, we will redeem all unpaid grants of compensation at an amount equal to the highest incentive compensation value, using as the determination date any day within the previous twelve months, multiplied by 1.5. The plan was established in July 1997 and on July 1, 1997, the board of directors of our general partner granted awards totaling 2 percent of the incentive compensation value to each of David Dehaemers and Michael Morgan. Originally, 50 percent of such awards were to vest on each of January 1, 2000 and January 1, 2002. No awards were granted during 1998 and 1999.
On January 4, 1999, the awards granted to Mr. Dehaemers and Mr. Morgan were amended to provide for the immediate vesting and pay-out of 50 percent of their awards, or 1 percent of the incentive compensation value. On April 28, 2000, the awards granted to Mr. Dehaemers and Mr. Morgan were amended to provide for the immediate vesting and pay-out of the remaining 50 percent of their awards, or 1 percent of the incentive compensation value. The board of directors of our general partner believes that accelerating the vesting and pay-out of the awards was in our best interest because it capped the total payment the participants were entitled to receive with respect to their awards.
Retirement Savings Plan. Effective July 1, 1997, our general partner established the Kinder Morgan Retirement Savings Plan, a defined contribution 401(k) plan. This plan was subsequently amended and merged to form the Kinder Morgan Savings Plan. The plan now permits all full-time employees of Kinder Morgan, Inc. and Kinder Morgan Services LLC to contribute 1 percent to 50 percent of base compensation, on a pre-tax basis, into participant accounts. In addition to a mandatory contribution equal to 4 percent of base compensation per year for most plan participants, our general partner may make discretionary contributions in years when specific performance objectives are met. Certain employees' contributions are based on collective bargaining agreements. The mandatory contributions are made each pay period on behalf of each eligible employee. Any discretionary contributions are made during the first quarter following the performance year. All contributions, including discretionary contributions, are in the form of KMI stock that is immediately convertible into other available investment vehicles at the employee's discretion. In the first quarter of 2002, no discretionary contributions were made to individual accounts for 2001. All contributions, together with earnings thereon, are immediately vested and not subject to forfeiture. Participants may direct the investment of their contributions into a variety of investments. Plan assets are held and distributed pursuant to a trust agreement. Because levels of future compensation, participant contributions and investment yields cannot be reliably predicted over the span of time contemplated by a plan of this nature, it is impractical to estimate the annual benefits payable at retirement to the individuals listed in the Summary Compensation Table above.
Common Unit Option Plan. Pursuant to our Common Unit Option Plan, our and our affiliates' key personnel are eligible to receive grants of options to acquire common units. The total number of common units available under the option plan is 500,000. None of the options granted under the option plan may be "incentive stock options" under Section 422 of the Internal Revenue Code. If an option expires without being exercised, the number of common units covered by such option will be available for a future award. The exercise price for an option may not be less than the fair market value of a common unit on the date of grant. Either the board of directors of our general partner or a committee of the board of directors will administer the option plan. The option plan terminates on March 5, 2008.
No individual employee may be granted options for more than 20,000 common units in any year. Our board of directors or the committee referred to in the prior paragraph will determine the duration and vesting of the options to employees at the time of grant. As of December 31, 2001, outstanding options for 379,400 common units were granted to 106 employees of Kinder Morgan, Inc. and Kinder Morgan Services LLC. Forty percent of such options will vest on the first anniversary of the date of grant and twenty percent on each anniversary, thereafter. The options expire seven years from the date of grant.
The option plan also granted to each of our non-employee directors as of April 1, 1998, an option to acquire 10,000 common units at an exercise price equal to the fair market value of the common units on such date. In addition, each new non-employee director will receive options to acquire 10,000 common units on the first day of the month following his or her election. Under this provision, as of December 31, 2001, outstanding options for 30,000 common units had been granted to Kinder Morgan G.P., Inc.'s three non-employee directors. Forty percent of such options will vest on the first anniversary of the date of grant and twenty percent on each anniversary, thereafter. The non-employee director options will expire seven years from the date of grant.
No common unit options were granted during 2001 to any of the individuals named in the Summary compensation table above. The following table sets forth certain information at December 31, 2001 with respect to common unit options previously granted to the individuals named in the Summary Compensation Table above. Mr. Allison and Mr. Listengart were the only persons named in the Summary Compensation Table that were granted common unit options. No common unit options were granted at an option price below fair market value on the date of grant.
AGGREGATED COMMON UNIT OPTION EXERCISES IN 2001, AND 2001 YEAR-END COMMON UNIT OPTION VALUES
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(1) Calculated on the basis of the fair market value of the underlying common units at year-end, minus the exercise price.
KMI Option Plan. Under KMI's stock option plans, employees of KMI and its affiliates, including employees of Kinder Morgan, Inc. and its direct and indirect subsidiaries, are eligible to receive grants of options to acquire shares of common stock of KMI. KMI's board of directors administers this option plan. The primary purpose for granting stock options under this plan to employees of our general partner and our subsidiaries is to provide them with an incentive to increase the value of common stock of KMI. A secondary purpose of the grants is to provide compensation to those employees for services rendered to our subsidiaries and us.
The following tables set forth certain information at December 31, 2001 and for the fiscal year then ended with respect to KMI stock options granted to the individuals named in the Summary Compensation Table above. Mr. Listengart and Mr. Shaper are the only persons named in the Summary Compensation Table that were granted KMI stock options during 2001. None of these KMI stock options were granted with an exercise price below the fair market value of the common stock on the date of grant. The options were granted and became fully exercisable on January 17, 2001, but relate to performance in 2000. The options expire 10 years after the date of grant.
KMI STOCK OPTION GRANTS IN 2001
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(1) The dollar amounts under these columns use the 5% and 10% rates of appreciation prescribed by the Securities and Exchange Commission. The 5% and 10% rates of appreciation would result in per share prices of $81.24 and $129.36, respectively. We express no opinion regarding whether this level of appreciation will be realized and expressly disclaim any representation to that effect.
AGGREGATED KMI STOCK OPTION EXERCISES IN 2001 AND 2001 YEAR-END KMI STOCK OPTION VALUES
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(1) Calculated on the basis of the fair market value of the underlying shares at year-end, minus the exercise price.
Cash Balance Retirement Plan. Employees of our general partner and our subsidiaries are eligible to participate in a new Cash Balance Retirement Plan that was put into effect on January 1, 2001. Certain employees continue to accrue benefits through a career-pay formula, "grandfathered" according to age and years of service on December 31, 2000, or collective bargaining arrangements. All other employees will accrue benefits through a personal retirement account in the new Cash Balance Retirement Plan. Employees with prior service and not grandfathered converted to the Cash Balance Retirement Plan and were credited with the current fair value of any benefits they had previously accrued through the defined benefit plan. Under the plan, we make contributions on behalf of participating employees equal to 3% of eligible compensation every pay period. In addition, we may make discretionary contributions to the plan based on our performance. In the first quarter of 2002, an additional 1% discretionary contribution was made to individual accounts based on achieving 2001 financial targets to unitholders. Interest will be credited to the personal retirement accounts at the 30-year U.S. Treasury bond rate in effect each year. Employees will be fully vested in the plan after five years, and they may take a lump sum distribution upon termination of employment or retirement.
Compensation Committee Interlocks and Insider Participation. We do not have a separate compensation committee. Kinder Morgan Management's compensation committee, comprised of Mr. Edward O. Gaylord, Mr. Gary L. Hultquist and Mr. Perry M. Waughtal, makes compensation decisions regarding our executive officers. Mr. Richard D. Kinder and Mr. William V. Morgan, who are executive officers of Kinder Morgan Management, participate in the deliberations of the board of directors of Kinder Morgan Management concerning executive officer compensation. Messrs. Kinder and Morgan each receive $1.00 annually in total salary compensation for services to KMI and us.
Directors fees. During 2001, each of the three non-employee members of the board of directors of Kinder Morgan Management was paid $10,000 for each quarter in 2001 in which they served on the board of directors. Each will receive $10,000 for each quarter in 2002 in which they serve. Directors are reimbursed for reasonable expenses in connection with board meetings.
Employment agreements. In April 2000, Mr. David G. Dehaemers, Jr. and Mr. Michael C. Morgan entered into four-year employment agreements with KMI and our general partner. Under the employment agreements, each of Mr. David G. Dehaemers, Jr. and Mr. Michael C. Morgan receives an annual base salary of $200,000 and bonuses at the discretion of the compensation committee of our general partner. In connection with the execution of the employment agreements, Messrs. Dehaemers and Morgan no longer participate under our Executive Compensation Plan. In addition, each are prevented from competing with KMI and us for a period of four years from the date of the agreements, provided Mr. Richard D. Kinder or Mr. William V. Morgan continues to serve as chief executive officer of KMI or its successor.
Retention Agreement. Effective January 17, 2002, KMI entered into a retention agreement with C. Park Shaper, an officer of KMI, our general partner and its delegate. Pursuant to the terms of the agreement, Mr. Shaper received a $5 million personal loan guaranteed by us. Mr. Shaper was required to
purchase KMI common shares and our common units in the open market with the loan proceeds. If he voluntarily leaves us prior to the end of five years, then he must repay the entire loan. On the fifth anniversary date of the agreement, provided Mr. Shaper has continued to be employed by our general partner, we and KMI will assume Mr. Shaper's obligations under the loan. The agreement contains provisions that address termination for cause, death, disability and change of control.
Lines of Credit. Kinder Morgan Energy Partners, L.P. has agreed to guarantee potential borrowings under lines of credit available from First Union National Bank to Messrs. M. Morgan, Dehaemers, Listengart and Shaper. Each of these officers is primarily liable for any borrowing on his line of credit, and if Kinder Morgan Energy Partners, L.P. makes any payment with respect to an outstanding loan, the officer on behalf of whom payment is made must surrender a percentage of his Kinder Morgan, Inc. stock options. To date, Kinder Morgan Energy Partners, L.P. has made no payment with respect to these lines of credit.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The following table sets forth information as of January 31, 2002, regarding (a) the beneficial ownership of (i) our units, (ii) the common stock of KMI, the parent company of our general partner, and (iii) Kinder Morgan Management shares by all directors of our general partner and its delegate, each of the named executive officers and all directors and executive officers as a group and (b) the beneficial ownership of our common units by all persons known by our general partner to own beneficially more than 5% of our units or shares of Kinder Morgan Management. Unless otherwise noted, the address of each person below is c/o Kinder Morgan Energy Partners, L.P., 500 Dallas Street, Suite 1000, Houston, Texas 77002. All references to the number of our common units and to the number of Kinder Morgan Management shares have been restated to reflect the effect of the two-for-one splits of our outstanding common units and Kinder Morgan Management shares that occurred on August 31, 2001.
AMOUNT AND NATURE OF BENEFICIAL OWNERSHIP(1)
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* Less than 1%.
(1) Except as noted otherwise, all units and KMI shares involve sole voting power and sole investment power. For Kinder Morgan Management, see note (4).
(2) As of January 31, 2002, we had 129,862,418 common units issued and outstanding.
(3) As of January 31, 2002, we had 5,313,400 Class B units issued and outstanding.
(4) Represent the limited liability company shares of Kinder Morgan Management. As of January 31, 2002, there were 30,636,363 issued and outstanding Kinder Morgan Management shares. In all cases, our i-units will be voted in proportion to the affirmative and negative votes, abstentions and non- votes of owners of Kinder Morgan Management shares. Through the provisions in our partnership agreement and Kinder Morgan Management's limited liability company agreement, the number of outstanding Kinder Morgan Management shares, including voting shares owned by our general partner, and the number of our i-units will at all times be equal. Furthermore, Kinder Morgan Management shareholders have the option to exchange any or all of their shares for common units owned by KMI, directly or indirectly through its subsidiaries, at an exchange rate of one common unit per one share. At any time, instead of delivering a common unit, KMI may elect to make a cash payment in respect of any share surrendered for exchange by giving notice of the election to the tendering holder not more that three trading days after such share is surrendered for exchange. The numbers of our common units reported in the table do not include any common units which might be received upon surrender of the Kinder Morgan Management shares reflected in the table.
(5) As of January 31, 2002, KMI had a total of 123,622,415 shares of outstanding voting common stock.
(6) Includes (a) 7,100 common units owned by Mr. Kinder's spouse and (b) 5,100 KMI shares held by Mr. Kinder's spouse. Mr. Kinder disclaims any and all beneficial or pecuniary interest in these units and shares.
(7) Porticullis Partners, LP, a Texas limited partnership beneficially owned by Mr. Morgan and his wife Sara S. Morgan, holds the KMI shares. Mr. Morgan may be deemed to own the 4,500,000 KMI shares and thereby shares in the voting and disposition power with Porticullis Partners, LP. Includes 1,000,000 KMI shares with respect to which Porticullis Partners, LP wrote a costless collar that expires in August 2003.
(8) Includes options to purchase 212,500 KMI shares exercisable within 60 days of January 31, 2002, and includes 17,520 shares of restricted KMI stock.
(9) Includes options to purchase 8,000 common units exercisable within 60 days of January 31, 2002.
(10) Includes options to purchase 6,000 common units exercisable within 60 days of January 31, 2002.
(11) Includes options to purchase 4,000 common units exercisable within 60 days of January 31, 2002.
(12) Includes options to purchase 16,000 common units and includes 17,500 shares of restricted KMI stock.
(13) Includes options to purchase 212,500 KMI shares exercisable within 60 days of January 31, 2002, and includes 17,520 shares of restricted KMI stock.
(14) Includes options to purchase 10,000 common units and 45,050 KMI shares exercisable within 60 days of January 31, 2002, and includes 17,520 shares of restricted KMI stock.
(15) Includes options to purchase 87,500 KMI shares exercisable within 60 days of January 31, 2002, and includes 17,520 shares of restricted KMI stock.
(16) Includes options to purchase 60,000 common units and 756,050 KMI shares exercisable within 60 days of January 31, 2002, and includes 122,500 shares of restricted KMI stock.
(17) Includes common units owned by KMI and its consolidated subsidiaries, including 1,724,000 common units owned by Kinder Morgan G.P., Inc.
(18) As reported on the Schedule 13G filed February 15, 2002 by Fayez Sarofim & Co. and Fayez Sarofim. Mr. Sarofim reports that he has sole voting power over 2,000,000 common units, shared voting power over 4,107,830 common units, sole disposition power over 2,000,000 common units and
shared disposition power over 4,993,697 common units. Mr. Sarofim's address is 2907 Two Houston Center, Houston, Texas 77010.
(19) As reported on the Schedule 13G/A filed February 14, 2002 by Goldman, Sachs & Co. and The Goldman Sachs Group, Inc. Goldman Sachs & Co. and The Goldman Sachs Group, Inc. report that each has sole voting power over 0 common units, shared voting power over 7,402,780 common units, sole disposition power over 0 common units and shared disposition power over 7,402,780 common units. The address of Goldman Sachs & Co. and The Goldman Sachs Group, Inc. is 10 Hanover Square, New York, New York 10005.
(20) As reported on the Schedule 13G/A filed February 11, 2002 by Capital Group International, Inc. and Capital Guardian Trust Company. Capital Group International, Inc. and Capital Guardian Trust Company report that in regard to Kinder Morgan Management shares, each has sole voting power over 2,515,030 shares, shared voting power over 0 shares, sole disposition power over 3,261,210 shares and shared disposition power over 0 shares. Capital Group International, Inc. and Capital Guardian Trust Company disclaim beneficial ownership of the shares but may be deemed to be the beneficial owners of the shares. Capital Group International, Inc.'s and Capital Guardian Trust Company's address is 11100 Santa Monica Blvd., Los Angeles, California 90025.
(21) As reported on the Schedule 13G/A filed February 14, 2002 by FMR Corp. FMR Corp. reports that in regard to Kinder Morgan Management shares, it has sole voting power over 154,146 shares, shared voting power over 0 shares, sole disposition power over 3,204,988 shares and shared disposition power over 0 shares. FMR Corp.'s address is 82 Devonshire Street, Boston, Massachusetts 02109.
(22) As reported on the Schedule 13G filed February 12, 2002 by Massachusetts Financial Services Company. Massachusetts Financial Services Company reports that in regard to Kinder Morgan Management shares, it has sole voting power over 1,597,781 shares, shared voting power over 0 shares, sole disposition power over 1,597,781 shares and shared disposition power over 0 shares. Massachusetts Financial Services Company's address is 500 Boylston Street, Boston, Massachusetts 02116.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
See Note 12 of the Notes to the Consolidated Financial Statements included elsewhere in this report.
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
FINANCIAL STATEMENTS -- See "Index to Financial Statements" set forth on page 74.
FINANCIAL STATEMENT SCHEDULES
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
SCHEDULE II. -- VALUATION AND QUALIFYING ACCOUNTS (IN THOUSANDS)
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(1) Additions represent the allowance recognized when we acquired CALNEV Pipe Line LLC and Kinder Morgan Liquids Terminals LLC, as well as transfers from other accounts.
(2) Deductions represent the write-off of receivables and the revaluation of the allowance account.
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(1) Additions represent the allowance recognized when we acquired our Natural Gas Pipelines.
(2) Deductions represent the write-off of receivables and the revaluation of the allowance account.
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(1) Deductions represent the write-off of receivables and the revaluation of the allowance account.
(a)(3) Exhibits
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* Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith, except as noted otherwise.
(b) Reports on Form 8-K
Current Report on Form 8-K was furnished on November 9, 2001, pursuant to Item 9 of that form. We provided notice that we, along with KMI, a subsidiary of which serves as our general partner, and Kinder Morgan Management, LLC, a subsidiary of our general partner that manages and controls our business and affairs, intended to make several presentations beginning on November 9, 2001 and continuing over a two-week period, to analysts and others to address various strategic and financial issues relating to the business plans and objective of ourselves, KMI and Kinder Morgan Management, LLC. Notice was also given that prior to the meeting, interested parties would be able to view the materials presented at the meetings by visiting KMI's website at: http://www.kindermorgan.com/investor_relations/ presentations/kmi_nov2001_presentation.pdf
Current Report on Form 8-K was filed on December 24, 2001, pursuant to Item 5 of that form. We reported that on December 17, 2001 we had announced that we had entered into a definitive agreement to purchase Tejas Gas, LLC, a wholly owned subsidiary of InterGen (North America), Inc., for approximately $750,000,000 in cash. Tejas Gas owns an approximately 3,400-mile natural gas intrastate pipeline system that extends from South Texas along the Mexico border and the Texas Gulf Coast to near the Louisiana border, and north from near Houston to East Texas. The transaction is expected to close in the first quarter of 2002.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners of Kinder Morgan Energy Partners, L.P.
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Kinder Morgan Energy Partners, L.P. and its subsidiaries (the Partnership) at December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule appearing under Item 14(a)(2) on page 71 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Partnership's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 14 to the consolidated financial statements, the Partnership changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001.
/s/ PRICEWATERHOUSECOOPERS LLP
Houston, Texas February 15, 2002
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
The accompanying notes are an integral part of these consolidated financial statements.
1. ORGANIZATION
GENERAL
Kinder Morgan Energy Partners, L.P., the "Partnership", is a Delaware limited partnership formed in August 1992. We are a publicly traded limited partnership managing a diversified portfolio of midstream energy assets. We provide services to our customers and increase value for our unitholders primarily through the following activities:
- transporting, storing and processing refined petroleum products;
- transporting, storing and selling natural gas;
- transporting carbon dioxide for use in enhanced oil recovery operations; and
- transloading, storing and delivering a wide variety of bulk, petroleum and petrochemical products at terminal facilities located across the United States.
We focus on providing fee-based services to customers, avoiding commodity price risks and taking advantage of the low-cost capital available in a limited partnership structure. We trade on the New York Stock Exchange under the symbol "KMP" and presently conduct our business through four reportable business segments:
- Products Pipelines;
- Natural Gas Pipelines;
- CO(2) Pipelines; and
- Terminals.
On July 18, 2001, we announced a change in the organization of our business segments, effective in the third quarter of 2001. Prior to the third quarter of 2001, we reported Bulk Terminals and Liquids Terminals as separate business segments. As a result of combining our Bulk Terminals and Liquids Terminals businesses under one management team beginning with the third quarter of 2001, we are reporting the combined Bulk Terminals and Liquids Terminals segments as our Terminals segment. Prior period segment results have been restated to conform to our current organization. For more information on our reportable business segments, see Note 15.
MERGER OF KMI
On October 7, 1999, K N Energy, Inc., a Kansas corporation that provided integrated energy services including the gathering, processing, transportation and storage of natural gas, the marketing of natural gas and natural gas liquids and the generation of electric power, acquired Kinder Morgan (Delaware), Inc., a Delaware corporation. Kinder Morgan (Delaware), Inc. is the sole stockholder of our general partner, Kinder Morgan G.P., Inc. At the time of the closing of the acquisition, K N Energy, Inc. changed its name to Kinder Morgan, Inc. It is referred to as "KMI" in this report. KMI trades on the New York Stock Exchange under the symbol "KMI" and is one of the largest midstream energy companies in the United States, operating, either for themselves or on behalf of us, more than 30,000 miles of natural gas and products pipelines in 26 states. KMI also has significant retail natural gas distribution and electric generation operations. KMI, through its subsidiary Kinder Morgan (Delaware), Inc., is the sole stockholder of our general partner. At December 31, 2001, KMI and its consolidated subsidiaries owned approximately 18.7% of our outstanding limited partner units.
KINDER MORGAN MANAGEMENT, LLC
Kinder Morgan Management, LLC, a Delaware limited liability company, was formed on February 14, 2001. It is referred to as "KMR" in this report. Our general partner owns all of KMR's voting securities.
In May 2001, KMR issued 2,975,000 of its shares representing limited liability company interests to KMI and 26,775,000 of its shares to the public in an initial public offering. KMR's shares were initially issued at a price of $35.21 per share, less commissions and underwriting expenses, and the shares trade on the New York Stock Exchange under the symbol "KMR". Substantially all of the net proceeds from the offering were used to buy i-units from us. The i-units are a new and separate class of limited partner interests in us and are issued only to KMR.
When it purchased i-units from us, KMR became a limited partner in us and, pursuant to a delegation of control agreement, manages and controls our business and affairs. Under the delegation of control agreement, our general partner delegated to KMR, to the fullest extent permitted under Delaware law and our partnership agreement, all of its power and authority to manage and control our business and affairs, except that it cannot take certain specified actions without the approval of our general partner. In accordance with its limited liability company agreement, KMR's activities will be restricted to being a limited partner in, and managing and controlling the business and affairs of the Partnership, including our operating partnerships and our subsidiaries. See Note 11 for more information.
TWO-FOR-ONE COMMON UNIT SPLIT
On July 18, 2001, KMR, the delegate of our general partner, approved a two-for-one unit split of its outstanding shares and our outstanding common units representing limited partner interests in us. The common unit split entitled our common unitholders to one additional common unit for each common unit held. Our partnership agreement provides that when a split of our common units occurs, a unit split on our Class B units and our i-units will be effected to adjust proportionately the number of our Class B units and i-units. The issuance and mailing of split units occurred on August 31, 2001 to unitholders of record on August 17, 2001. All references to the number of KMR shares, the number of our limited partner units and per unit amounts in our consolidated financial statements and related notes, have been restated to reflect the effect of the split for all periods presented.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION
Our consolidated financial statements include our accounts and those of our majority-owned and controlled subsidiaries and our operating partnerships. All significant intercompany items have been eliminated in consolidation. Certain amounts from prior years have been reclassified to conform to the current presentation.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared.
The preparation of our financial statements in conformity with generally accepted accounting principles requires our management to make estimates and assumptions that affect:
- the amounts we report for assets and liabilities;
- our disclosure of contingent assets and liabilities at the date of the financial statements; and
- the amounts we report for revenues and expenses during the reporting period.
Therefore, the reported amounts of our assets and liabilities, revenues and expenses and associated disclosures with respect to contingent assets and obligations are necessarily affected by these estimates. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of
operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
In preparing our financial statements and related disclosures, we must use estimates in determining the economic useful lives of our assets, provisions for uncollectible accounts receivable, exposures under contractual indemnifications and various other recorded or disclosed amounts. However, we believe that certain accounting policies are of more significance in our financial statement preparation process than others. With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable. Finally, we are subject to litigation as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected.
CASH EQUIVALENTS
We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less.
INVENTORIES
Our inventories of products consist of natural gas liquids, refined petroleum products, natural gas, carbon dioxide and coal. We report these assets at the lower of weighted-average cost or market. We report materials and supplies at the lower of cost or market.
PROPERTY, PLANT AND EQUIPMENT
We state property, plant and equipment at its acquisition cost. We expense costs for maintenance and repairs in the period incurred. The cost of property, plant and equipment sold or retired and the related depreciation are removed from our balance sheet in the period of sale or disposition. We compute depreciation using the straight-line method based on estimated economic lives. Generally, we apply composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 2.0% to 12.5%, excluding certain short-lived assets such as vehicles. Depreciation, depletion and amortization of the capitalized costs of producing carbon dioxide properties, both tangible and intangible, are provided for on a units-of-production basis. Proved developed reserves are used in computing units-of-production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs. The basis for units-of-production rate determination is by field. We charge the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. We do not include retirement gain or loss in income except in the case of significant retirements or sales.
We evaluate impairment of our long-lived assets in accordance with Statement of Financial Accounting Standards No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." We review for the impairment of long-lived assets whenever events or changes in circumstances indicate that our carrying amount of an asset may not be recoverable. We would recognize an impairment loss when estimated future cash flows expected to result from our use of the asset and its eventual disposition is less than its carrying amount.
In practice, the composite life may not be determined with a high degree of precision, and hence the composite life may not reflect the weighted average of the expected useful lives of the asset's principal components. The Financial Accounting Standards Board has issued a proposed Statement of Position entitled "Accounting for Certain Costs and Activities Related to Property, Plant and Equipment". For purposes of the SOP, a project stage or timeline frame works is used and property, plant and equipment
assets are to be accounted for at a component level. Costs incurred for property, plant and equipment are to be classified into four stages:
- preliminary;
- preacquisition;
- acquisition-or-construction; and
- in-service.
Furthermore, a component is a tangible part or portion of property, plant and equipment that:
- can be separately identified as an asset and depreciate or amortized over its own expected use life; and
- is expected to provide economic benefit for more than one year.
If a component has an expected useful life that differs from the expected useful life of the property, plant and equipment asset to which it relates, the cost should be accounted for separately and depreciated or amortized over its expected useful life. We are currently evaluating the effects of this proposed SOP.
On January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This statement retains the requirements of SFAS 121, mentioned above, however, this statement requires that long-lived assets that are to be disposed of by sale be measured at the lower of book value or fair value less the cost to sell it. Furthermore, the scope of discontinued operations is expanded to include all components of an entity with operations of the entity in a disposal transaction. The adoption of SFAS No. 144 has not had an impact on our business, financial position or results of operations.
NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
In July 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations". This statement requires companies to record a liability relating to the retirement and removal of assets used in their business. The liability is discounted to its present value, and the relative asset value is increased by the same amount. Over the life of the asset, the liability will be accreted to its future value and eventually extinguished when the asset is taken out of service. The provisions of this statement are effective for fiscal years beginning after June 15, 2002. We do not expect that SFAS No. 143 will have a material impact on our business, financial position or results of operations.
EQUITY METHOD OF ACCOUNTING
We account for investments in greater than 20% owned affiliates, which we do not control, by the equity method of accounting. Under this method, an investment is carried at our acquisition cost, plus our equity in undistributed earnings or losses since acquisition.
EXCESS OF COST OVER FAIR VALUE
As of December 31, 2001, we amortized the excess cost over our underlying net asset book value in equity investments using the straight-line method over the estimated remaining useful lives of the assets in accordance with Accounting Principles Board Opinion No. 16. We amortized this excess for undervalued depreciable assets over a period not to exceed 50 years and for intangible assets over a period not to exceed 40 years. For our investments in consolidated affiliates, we reported amortization of excess cost over fair value of net assets (goodwill) as amortization expense in our accompanying consolidated statements of income. For our investments accounted for under the equity method, we reported amortization of excess cost on investments as amortization of excess cost of equity investments in our accompanying consolidated statements of income. Our total unamortized excess cost over fair value of net assets on investments in consolidated affiliates was approximately $546.7 million as of December 31, 2001 and $158.1 million as of December 31, 2000. These amounts are included within intangibles on our accompanying consolidated
balance sheet. Our total unamortized excess cost over underlying book value of net assets on investments accounted for under the equity method was approximately $341.2 million as of December 31, 2001 and $350.2 million as of December 31, 2000. These amounts are included within equity investments on our accompanying balance sheet.
We periodically reevaluate the amount at which we carry the excess of cost over fair value of net assets of businesses we acquired, as well as the amortization period for such assets, to determine whether current events or circumstances warrant adjustments to our carrying value and/or revised estimates of useful lives. At December 31, 2001, we believed no such impairment had occurred and no reduction in estimated useful lives was warranted. On January 1, 2002, we adopted SFAS No. 141 "Business Combinations".
SFAS No. 141 supercedes Accounting Principles Board Opinion No. 16 and requires that all transactions fitting the description of a business combination be accounted for using the purchase method and prohibits the use of the pooling of interests for all business combinations initiated after June 30, 2001. The Statement also modifies the accounting for the excess of fair value of net assets acquired as well as intangible assets acquired in a business combination. The provisions of this statement apply to all business combinations initiated after June 30, 2001, and all business combinations accounted for by the purchase method that are completed after July 1, 2001. This Statement requires disclosure of the primary reasons for a business combination and the allocation of the purchase price paid to the assets acquired and liabilities assumed by major balance sheet caption. After July 1, 2001, we completed four acquisitions and have initiated or announced four additional acquisitions. Refer to Note 3 for more detail about our acquisitions.
SFAS No. 142 "Goodwill and Other Intangible Assets" supercedes Accounting Principles Board Opinion No. 17 and requires that goodwill no longer be amortized but should be tested, at least on an annual basis, for impairment. A benchmark assessment of potential impairment must also be completed within six months of adopting SFAS No. 142. After the first six months, goodwill will be tested for impairment annually. SFAS No. 142 applies to any goodwill acquired in a business combination completed after June 30, 2001. Other intangible assets are to be amortized over their useful life and reviewed for impairment in accordance with the provisions of SFAS No. 121,"Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed Of". An intangible asset with an indefinite useful life can no longer be amortized until its useful life becomes determinable. This Statement requires disclosure of information about goodwill and other intangible assets in the years subsequent to their acquisition that was not previously required. Required disclosures include information about the changes in the carrying amount of goodwill from period to period and the carrying amount of intangible assets by major intangible asset class. After June 30, 2001, we completed two acquisitions, our Boswell and Stolt-Nielsen acquisitions, which resulted in the recognition of goodwill. We adopted SFAS No. 142 on January 1, 2002, and we expect that SFAS No. 142 will not have a material impact on our business, financial position or results of operations. With the adoption of SFAS No. 142, goodwill of approximately $546.7 million is no longer subject to amortization over its estimated useful life. For more information on our acquisitions, see Note 3.
REVENUE RECOGNITION
We recognize revenues for our pipeline operations based on delivery of actual volume transported or minimum obligations under take-or-pay contracts. We recognize bulk terminal transfer service revenues based on volumes loaded. We recognize liquid terminal tank rental revenue ratably over the contract period. We recognize liquid terminal through-put revenue based on volumes received or volumes delivered depending on the customer contract. Liquid terminal minimum take-or-pay revenue is recognized at the end of the contract year or contract term depending on the terms of the contract. We recognize transmix processing revenues based on volumes processed or sold, and if applicable, when title has passed. We recognize energy-related product sales revenues based on delivered quantities of product.
ENVIRONMENTAL MATTERS
We expense or capitalize, as appropriate, environmental expenditures that relate to current operations. We expense expenditures that relate to an existing condition caused by past operations, and which do not contribute to current or future revenue generation. We do not discount liabilities to net present value and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our making of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action.
MINORITY INTEREST
Minority interest consists of the following:
- the 1.0101% general partner interest in our operating partnerships;
- the 0.5% special limited partner interest in SFPP, L.P.;
- the 33 1/3% interest in Trailblazer Pipeline Company;
- the 50% interest in Globalplex Partners, a Louisiana joint venture owned 50% and controlled by Kinder Morgan Bulk Terminals, Inc.; and
- the approximate 32% interest in MidTex Gas Storage Company, L.L.P., a Texas limited liability partnership owned approximately 68% and controlled by Kinder Morgan Texas Pipeline L.P. and its consolidated subsidiaries.
INCOME TAXES
We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined as we do not have access to information about each partner's tax attributes in the Partnership.
Some of our corporate subsidiaries and corporations in which we have an equity investment do pay federal and state income taxes. Deferred income tax assets and liabilities for certain of our operations conducted through corporations are recognized for temporary differences between the assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit not expected to be realized.
COMPREHENSIVE INCOME
Statement of Financial Accounting Standards No. 130, "Accounting for Comprehensive Income", requires that enterprises report a total for comprehensive income. For the year ended December 31, 2001, the only difference between net income and comprehensive income for us was the unrealized gain or loss on derivatives utilized for hedging purposes. There was no difference between net income and comprehensive income for each of the years ended December 31, 2000 and 1999. For more information on our hedging activities, see Note 14.
NET INCOME PER UNIT
We compute Basic Limited Partners' Net Income per Unit by dividing limited partner's interest in net income by the weighted average number of units outstanding during the period. Diluted Limited Partners' Net Income per Unit reflects the potential dilution, by application of the treasury stock method, that could occur if options to issue units were exercised, which would result in the issuance of additional units that would then share in our net income.
RISK MANAGEMENT ACTIVITIES
We utilize energy derivatives for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas, natural gas liquids, crude oil and carbon dioxide. In addition, we enter into interest rate swap agreements for the purpose of hedging the interest rate risk associated with our fixed rate debt obligations. Prior to December 31, 2000, our accounting policy for these activities was based on a number of authoritative pronouncements including SFAS No. 80 "Accounting for Futures Contracts". Our new policy, which is based on SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities", became effective on January 1, 2001. See Note 14 for more information on our risk management activities.
3. ACQUISITIONS AND JOINT VENTURES
During 1999, 2000 and 2001, we completed the following significant acquisitions. Each of the acquisitions was accounted for under the purchase method and the assets acquired and liabilities assumed were recorded at their estimated fair market values as of the acquisition date. The preliminary amounts assigned to assets and liabilities may be adjusted during a short period following the acquisition. The results of operations from these acquisitions are included in the consolidated financial statements from the date of acquisition.
Plantation Pipe Line Company
On June 16, 1999, we acquired an additional approximate 27% interest in Plantation Pipe Line Company for approximately $124.2 million. Collectively, we now own approximately 51% of Plantation Pipe Line Company, and ExxonMobil Pipeline Company, an affiliate of ExxonMobil Corporation, owns approximately 49%. Plantation Pipe Line Company owns and operates a 3,100-mile pipeline system throughout the southeastern United States. The pipeline is a common carrier of refined petroleum products to various metropolitan areas, including Atlanta, Georgia; Charlotte, North Carolina; and the Washington, D.C. area. We do not control Plantation Pipe Line Company, and therefore, we account for our investment in Plantation under the equity method of accounting.
Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands):
Transmix Operations
On September 10, 1999, we acquired transmix processing plants in Richmond, Virginia and Dorsey Junction, Maryland and other related assets from Primary Corporation. As consideration for the purchase, we paid Primary approximately $16 million in cash and 1,020,294 common units valued at approximately $14.3 million. In addition, we assumed approximately $5.8 million of liabilities.
Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands):
Trailblazer Pipeline Company
Effective November 30, 1999, we acquired a 33 1/3% interest in Trailblazer Pipeline Company for $37.6 million from Columbia Gulf Transmission Company, an affiliate of Columbia Energy Group. Trailblazer Pipeline Company is an Illinois partnership that owns and operates a 436-mile natural gas pipeline system that traverses from Colorado through southeastern Wyoming to Beatrice, Nebraska. Trailblazer Pipeline Company has a certificated capacity of 492 million cubic feet per day of natural gas. For the month of December 1999, we accounted for our 33 1/3% interest in Trailblazer Pipeline Company under the equity method of accounting. Effective December 31, 1999, following our acquisition of an additional 33 1/3% interest in Trailblazer Pipeline Company, which is discussed below, we included Trailblazer Pipeline Company's activities as part of our consolidated financial statements.
On December 12, 2001, we announced that we had signed a definitive agreement to acquire the remaining 33 1/3% ownership interest in Trailblazer Pipeline Company from Enron Trailblazer Pipeline Company for $68 million in cash. Following the acquisition, we will own 100% of Trailblazer Pipeline Company. The transaction, which is expected to close in the first quarter of 2002, is subject to standard closing conditions, as well as approvals by the court overseeing the Enron Corp. bankruptcy and by the Enron board of directors. Through capital contributions it will make to the current expansion project on the Trailblazer pipeline, CIG Trailblazer Gas Company, an affiliate of El Paso Corporation, is expected to become a 7% to 8% equity owner in Trailblazer Pipeline Company in mid-2002.
1999 Kinder Morgan, Inc. Asset Contributions
Effective December 31, 1999, we acquired over $935.8 million of assets from KMI. As consideration for the assets, we paid to KMI $330 million in cash and 19,620,000 common units, valued at approximately $406.3 million. In addition, we assumed $40.3 million in debt and approximately $121.6 million in liabilities. We acquired Kinder Morgan Interstate Gas Transmission LLC (formerly K N Interstate Gas Transmission Co.), a 33 1/3% interest in Trailblazer Pipeline Company and a 49% equity interest in Red Cedar Gathering Company. The acquired interest in Trailblazer Pipeline Company, when combined with the interest purchased on November 30, 1999, gave us a 66 2/3% ownership interest.
Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands):
Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc.
Effective January 1, 2000, we acquired all of the shares of the capital stock of Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc. We paid an aggregate consideration of approximately $31.0 million, including 1,148,344 common units, approximately $0.8 million in cash and the assumption of approximately $7.0 million in liabilities. The Milwaukee terminal is located on nine acres of property leased from the Port of Milwaukee. Its major cargoes are coal and bulk de-icing salt. The Dakota terminal, located in St. Paul, Minnesota, primarily handles bulk de-icing salt and grain products.
Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands):
Kinder Morgan CO(2) Company, L.P.
Effective April 1, 2000, we acquired the remaining 78% limited partner interest and the 2% general partner interest in Shell CO(2) Company, Ltd. from Shell for approximately $212.1 million and the assumption of approximately $37.1 million of liabilities. We renamed the limited partnership Kinder Morgan CO(2) Company, L.P., and going forward from April 1, 2000, we have included its results as part of our consolidated financial statements under our CO(2) Pipelines business segment. As is the case with all of our operating partnerships, we own a 98.9899% limited partner ownership interest in KMCO(2) and our general partner owns a direct 1.0101% general partner ownership interest.
Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands):
- ---------------
(a) Represents reclassification of our original 20% equity investment in Shell CO(2) Company, L.P. of ($86.7) million and our allocation of purchase price to the equity investment purchased in our acquisition of Shell CO(2) Company, L.P. of $7.0 million.
Devon Energy
Effective June 1, 2000, we acquired significant interests in carbon dioxide pipeline assets and oil-producing properties from Devon Energy Production Company L.P. for $53.4 million. Included in the acquisition was an approximate 81% equity interest in the Canyon Reef Carriers CO(2) Pipeline, an approximate 71% working interest in the SACROC oil field, and minority interests in the Sharon Ridge unit and the Reinecke unit. All of the assets and properties are located in the Permian Basin of west Texas.
Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands):
Buckeye Refining Company, LLC
On October 25, 2000, we acquired Kinder Morgan Transmix, LLC, formerly Buckeye Refining Company, LLC, which owns and operates transmix processing plants in Indianola, Pennsylvania and Wood River, Illinois and other related transmix assets. As consideration for the purchase, we paid Buckeye approximately $37.3 million for property, plant and equipment plus approximately $8.4 million for net working capital and other items. We also assumed approximately $11.5 million of liabilities.
Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands):
Cochin Pipeline
Effective November 3, 2000, we acquired from NOVA Chemicals Corporation an undivided 32.5% interest in the Cochin Pipeline System for approximately $120.5 million. On June 20, 2001, we acquired an additional 2.3% ownership interest in the Cochin Pipeline System from Shell Canada Limited for approximately $8.0 million. We now own approximately 34.8% of the Cochin Pipeline System and the remaining interests are owned by subsidiaries of BP Amoco, Conoco and NOVA Chemicals. We record our proportional share of joint venture revenues and expenses and cost of joint venture assets as part of our Products Pipelines business segment.
Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands):
Effective December 31, 2001, we purchased an additional 10% ownership interest in the Cochin Pipeline System from NOVA Chemicals Corporation for approximately $29 million in cash. We now own approximately 44.8% of the Cochin Pipeline System. We allocated the purchase price to property, plant and equipment in January 2002.
Delta Terminal Services LLC
Effective December 1, 2000, we acquired all of the shares of the capital stock of Delta Terminal Services LLC, formerly Delta Terminal Services, Inc., for approximately $114.1 million and the assumption of approximately $22.5 million of liabilities. The acquisition includes two liquid bulk storage terminals in New Orleans, Louisiana and Cincinnati, Ohio.
Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands):
MKM Partners, L.P.
On December 28, 2000, we announced that KMCO()2 had entered into a definitive agreement to form a joint venture with Marathon Oil Company in the southern Permian Basin of west Texas. The joint venture holds a nearly 13% interest in the SACROC unit and a 49.9% interest in the Yates Field unit. The joint venture was formed on January 1, 2001 and named MKM Partners, L.P. As of December 31, 2000, we paid $34.2 million plus committed 30 billion cubic feet of carbon dioxide for our 7.5% interest in the Yates field unit. In January 2001, we contributed our interest in the Yates field unit together with an approximate 2% interest in the SACROC unit in return for a 15% interest in the joint venture. In January 2001, Marathon Oil Company purchased an approximate 11% interest in the SACROC unit from KMCO(2) for $6.2 million. Marathon Oil Company then contributed this interest in the SACROC unit and its 42.4% interest in the Yates field unit for an 85% interest in the joint venture. Going forward from January 1, 2001, we accounted for this investment under the equity method of accounting.
Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands):
2000 Kinder Morgan, Inc. Asset Contributions
Effective December 31, 2000, we acquired $621.7 million of assets from KMI. As consideration for these assets, we paid to KMI $192.7 million in cash and approximately $156.3 million in units, consisting of 1,280,000 common units and 5,313,400 class B units. We also assumed liabilities of approximately $272.7 million. We acquired Kinder Morgan Texas Pipeline, L.P. and MidCon NGL Corp. (both of which were converted to single-member limited liability companies), the Casper and Douglas natural gas gathering and processing systems, a 50% interest in Coyote Gas Treating, LLC and a 25% interest in Thunder Creek Gas Services, LLC.
Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands):
Colton Transmix Processing Facility
Effective December 31, 2000, we acquired the remaining 50% interest in the Colton Transmix Processing Facility from Duke Energy Merchants for approximately $11.2 million and the assumption of approximately $1.8 million of liabilities. We now own 100% of the Colton facility. Prior to our acquisition of the controlling interest in the Colton facility, we accounted for our ownership interest in the Colton facility under the equity method of accounting.
Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands):
GATX Domestic Pipelines and Terminals Businesses
During the first quarter of 2001, we acquired GATX Corporation's domestic pipeline and terminal businesses. The acquisition included:
- KMLT (formerly GATX Terminals Corporation), effective January 1, 2001;
- Central Florida Pipeline LLC (formerly Central Florida Pipeline Company), effective January 1, 2001; and
- CALNEV Pipe Line LLC (formerly CALNEV Pipe Line Company), effective March 30, 2001.
KMLT's assets includes 12 terminals, located across the United States, which store approximately 35.6 million barrels of refined petroleum products and chemicals. Five of the terminals are included in our Terminals business segment, and the remaining assets are included in our Products Pipelines business segment. Central Florida Pipeline LLC consists of a 195-mile pipeline transporting refined petroleum
products from Tampa to the growing Orlando, Florida market. CALNEV Pipe Line LLC consists of a 550-mile refined petroleum products pipeline originating in Colton, California and extending into the growing Las Vegas, Nevada market. The pipeline interconnects in Colton with our Pacific operations' West Line pipeline segment. Our purchase price was approximately $1,231.6 million, consisting of $975.4 million in cash, $134.8 million in assumed debt and $121.4 million in assumed liabilities.
Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands):
Pinney Dock & Transport LLC
Effective March 1, 2001, we acquired all of the shares of the capital stock of Pinney Dock & Transport LLC, formerly Pinney Dock & Transport Company, for approximately $52.5 million. The acquisition includes a bulk product terminal located in Ashtabula, Ohio on Lake Erie. The facility handles iron ore, titanium ore, magnetite and other aggregates. Our purchase price consisted of approximately $41.7 million in cash and approximately $10.8 million in assumed liabilities.
Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands):
Vopak
Effective July 10, 2001, we acquired certain bulk terminal businesses, which were converted or merged into six single-member limited liability companies, from Koninklijke Vopak N.V. (Royal Vopak) of The Netherlands. Acquired assets included four bulk terminals. Two of the terminals are located in Tampa, Florida and the other two are located in Fernandina Beach, Florida and Chesapeake, Virginia. As a result of the acquisition, our bulk terminals portfolio gained entry into the Florida market. Our purchase
price was approximately $44.3 million, consisting of approximately $43.6 million in cash and approximately $0.7 million in assumed liabilities.
Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands):
Kinder Morgan Texas Pipeline
Effective July 18, 2001, we acquired, from an affiliate of Occidental Petroleum Corporation, Kinder Morgan Texas Pipeline, L.P., a partnership that owns a natural gas pipeline system in the State of Texas. Prior to our acquisition of this natural gas pipeline system, these assets were leased and operated by Kinder Morgan Texas Pipeline, L.P., a business unit included in our Natural Gas Pipelines business segment. As a result of this acquisition, we will be released from lease payments of $40 million annually from 2002 through 2005 and $30 million annually from 2006 through 2026. The acquisition included 2,600 miles of pipeline that primarily transports natural gas from south Texas and the Texas Gulf Coast to the greater Houston/Beaumont area. In addition, we signed a five-year agreement to supply approximately 90 billion cubic feet of natural gas to chemical facilities owned by Occidental affiliates in the Houston area. Our purchase price was approximately $326.1 million and the entire cost was allocated to property, plant and equipment.
Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands):
Note: These assets were previously leased from a third party under an operating lease. The released Statement of Financial Accounting Standards No. 13, "Accounting for Leases" deferred credit relates to a deferred credit accumulated to spread non-straight line operating lease rentals over the period expected to benefit from those rentals.
The Boswell Oil Company
Effective August 31, 2001, we acquired from The Boswell Oil Company three terminals located in Cincinnati, Ohio, Pittsburgh, Pennsylvania and Vicksburg, Mississippi. The Cincinnati and Pittsburgh terminals handle both liquids and dry-bulk materials. The Vicksburg terminal is a break-bulk facility, primarily handling paper and steel products. As a result of the acquisition, we continued the expansion of our bulk terminal businesses and entered new markets. Our purchase price was approximately $22.2 million, consisting of approximately $18.1 million in cash, a $3.0 million one-year note payable and approximately $1.1 million in assumed liabilities.
Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands):
The $6.6 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes.
Stolt-Nielsen
In November 2001, we acquired certain liquids terminals in Chicago, Illinois and Perth Amboy, New Jersey from Stolthaven Perth Amboy Inc., Stolthaven Chicago Inc. and Stolt-Nielsen Transportation Group, Ltd. As a result of the acquisition, we expanded our liquids terminals businesses into strategic markets. The Perth Amboy facility provides liquid chemical and petroleum storage and handling, as well as dry-bulk handling of salt and aggregates, with liquid capacity exceeding 2.3 million barrels annually. We closed on the Perth Amboy, New Jersey portion of this transaction on November 8, 2001. The Chicago terminal handles a wide variety of liquid chemicals with a working capacity in excess of 0.7 million barrels annually. We closed on the Chicago, Illinois portion of this transaction on November 29, 2001. Our purchase price was approximately $69.8 million, consisting of approximately $44.8 million in cash and $25.0 million in assumed debt.
Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands):
The $0.1 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes.
Snyder and Diamond M Plants
On November 14, 2001, we announced that KMCO(2) had purchased Mission Resources Corporation's interest in the Snyder Gasoline Plant and Diamond M Gas Plant. In December 2001, KMCO(2) purchased Torch E&P Company's interest in the Snyder Gasoline Plant and entered into a definitive agreement to
purchase Torch's interest in the Diamond M Gas Plant. As of December 31, 2001, we have paid approximately $14.7 million for these interests. Final purchase price adjustments should be made in the first quarter of 2002. All of these assets are located in the Permian Basin of west Texas. As a result of the acquisition, we have increased our ownership interests in both plants, each of which process gas produced by the SACROC unit.
Our purchase price and the allocation to assets acquired and liabilities assumed was as follows (in thousands):
PRO FORMA INFORMATION
The following summarized unaudited Pro Forma Consolidated Income Statement information for the twelve months ended December 31, 2001 and 2000, assumes the 2001 and 2000 acquisitions and joint ventures had occurred as of January 1, 2000. We have prepared these unaudited Pro Forma financial results for comparative purposes only. These unaudited Pro Forma financial results may not be indicative of the results that would have occurred if we had completed the 2001 and 2000 acquisitions and joint ventures as of January 1, 2000 or the results which will be attained in the future. Amounts presented below are in thousands, except for the per unit amounts:
ACQUISITIONS SUBSEQUENT TO DECEMBER 31, 2001
On December 12, 2001, we announced that we had signed a definitive agreement to acquire the remaining 33 1/3% ownership interest in Trailblazer Pipeline Company from Enron Trailblazer Pipeline Company for $68 million in cash. Following the acquisition, we will own 100% of Trailblazer Pipeline Company. The transaction, which is expected to close in the first quarter of 2002, is subject to standard closing conditions, as well as approvals by the court overseeing the Enron Corp. bankruptcy and by the Enron board of directors. Through capital contributions it will make to the current expansion project on the Trailblazer pipeline, CIG Trailblazer Gas Company, an affiliate of El Paso Corporation, is expected to become a 7% to 8% equity owner in Trailblazer Pipeline Company in mid-2002.
On December 17, 2001, we announced that we had entered into a definitive agreement to purchase Tejas Gas, LLC, a wholly owned subsidiary of InterGen (North America), Inc., for approximately $750 million in cash. Tejas Gas, LLC is a 3,400-mile natural gas intrastate pipeline system that extends from south Texas along the Mexico border and the Texas Gulf Coast to near the Louisiana border and
north from near Houston to east Texas. InterGen is a joint venture owned by affiliates of the Royal Dutch/Shell Group of Companies and Bechtel Enterprises Holding, Inc. The transaction is subject to standard closing conditions including receipt of certain regulatory and third party approvals. It is expected to close in the first quarter of 2002.
On February 4, 2002, we announced two acquisitions and a major expansion program, both within our Terminals business segment. Together, the investments represent approximately $43 million. The purchases included Pittsburgh, Pennsylvania based Laser Materials Services LLC, operator of 59 transload facilities in 18 states, and a 66 2/3% interest in International Marine Terminals Partnership (IMT), which operates a bulk terminal site in Port Sulphur, Louisiana. The expansion project, which is being carried out at our Carteret, New Jersey, liquids terminal, will add 400,000 barrels of storage (6% of current storage capacity) within 2002.
4. GAIN ON SALE OF EQUITY INTEREST, NET OF SPECIAL CHARGES
During the third quarter of 1999, we completed the sale of our partnership interest in the Mont Belvieu fractionation facility for approximately $41.8 million. We recognized a gain of $14.1 million on the sale and included that gain as part of our Natural Gas Pipelines business segment. Offsetting the gain were charges of approximately $3.6 million relating to our write-off of abandoned project costs, primarily within our Products Pipelines business segment, and a charge of $0.4 million relating to prior years' over-billed storage tank lease fees, also within our Products Pipelines business segment.
5. INCOME TAXES
Components of the income tax provision applicable to continuing operations for federal and state taxes are as follows (in thousands):
The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows:
Deferred tax assets and liabilities result from the following (in thousands):
We had available, at December 31, 2001, approximately $1.1 million of alternative minimum tax credit carryforwards, which are available indefinitely, and $1.9 million of net operating loss carryforwards, which will expire between the years 2002 and 2018. We believe it is more likely than not that the net operating loss carryforwards will be utilized prior to their expiration; therefore, no valuation allowance is necessary.
6. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consists of the following (in thousands):
Depreciation and depletion expense charged against property, plant and equipment consists of the following (in thousands):
7. INVESTMENTS
Our significant equity investments at December 31, 2001 consisted of:
- Plantation Pipe Line Company (51%);
- Red Cedar Gathering Company (49%);
- Thunder Creek Gas Services, LLC (25%);
- Coyote Gas Treating, LLC (Coyote Gulch) (50%);
- Cortez Pipeline Company (50%)
- MKM Partners, L.P. (15%); and
- Heartland Pipeline Company (50%).
On June 16, 1999, we acquired an additional approximate 27% interest in Plantation Pipe Line Company. As a result, we now own approximately 51% of Plantation Pipe Line Company, and an affiliate of ExxonMobil owns the remaining approximate 49%. Each investor has an equal number of directors on Plantation's board of directors, and board approval is required for certain corporate actions that are considered participating rights. Therefore, we do not control Plantation Pipe Line Company, and we account for our investment under the equity method of accounting.
On April 1, 2000, we acquired the remaining 80% ownership interest in Shell CO(2) Company, Ltd. and renamed the entity Kinder Morgan CO(2) Company, L.P. (KMCO(2)). On December 31, 2000, we acquired the remaining 50% ownership interest in the Colton Transmix Processing Facility. Due to these acquisitions, we no longer report these two investments under the equity method of accounting. In addition, we had an equity investment in Trailblazer Pipeline Company (33 1/3%) for one month of 1999 and had an equity interest in Mont Belvieu Associates through two quarters of 1999. We sold our equity interest in Mont Belvieu Associates in the third quarter of 1999 and acquired an additional 33 1/3% interest in Trailblazer Pipeline Company effective December 31, 1999.
On December 28, 2000, we announced that KMCO(2) had entered into a definitive agreement to form a joint venture with Marathon Oil Company in the southern Permian Basin of west Texas. The joint venture consists of a nearly 13% interest in the SACROC unit and a 49.9% interest in the Yates oil field. The joint venture was formed on January 1, 2001 and named MKM Partners, L.P. As of December 31, 2000, we paid $34.2 million plus committed 30 billion cubic feet of carbon dioxide for our 7.5% interest in the Yates oil field. In January 2001, we contributed our interest in the Yates oil field together with an approximate 2% interest in the SACROC unit in return for a 15% interest in the joint venture. In January 2001, Marathon Oil Company purchased an approximate 11% interest in the SACROC unit from KMCO(2) for $6.2 million. Marathon Oil Company then contributed this interest in the SACROC unit and its 42.4% interest in the Yates oil field for an 85% interest in the joint venture. Going forward from January 1, 2001, we have accounted for this investment under the equity method.
We acquired our investment in Cortez Pipeline Company as part of our KMCO(2) acquisition and we acquired our investments in Coyote Gas Treating, LLC and Thunder Creek Gas Services, LLC from KMI on December 31, 2000.
Please refer to Notes 3 and 4 for more information.
Our total equity investments consisted of the following (in thousands):
Our earnings from equity investments were as follows (in thousands):
Summarized combined unaudited financial information for our significant equity investments is reported below (in thousands; amounts represent 100% of investee financial information, not our pro rata portion):
8. INTANGIBLES
Our intangible assets include acquired goodwill, lease value, contracts and agreements. We acquired our 2000 intangible lease value as part of our acquisition of Kinder Morgan Texas Pipeline, L.P. on December 31, 2000 from KMI. In our July 2001 acquisition of K M Texas Pipeline, L.P., we acquired the leased pipeline asset from Occidental Petroleum and our operating lease was terminated. We allocated the balance of the KMTP intangible lease value between goodwill and property.
All of our intangible assets having definite lives are being amortized on a straight-line basis over their estimated useful lives. As of December 31, 2001, goodwill was being amortized over a period of 40 years.
Intangible assets consisted of the following (in thousands):
Amortization expense consists of the following (in thousands):
9. DEBT
Our debt and credit facilities as of December 31, 2001, consist primarily of:
- $200 million of Floating Rate Senior Notes due March 22, 2002;
- an $85.2 million unsecured two-year credit facility due June 29, 2003 (our subsidiary Trailblazer Pipeline Company is the obligor on the facility);
- a $750 million unsecured 364-day credit facility due October 23, 2002;
- a $300 million unsecured five-year credit facility due September 29, 2004;
- $200 million of 8.00% Senior Notes due March 15, 2005;
- $250 million of 6.30% Senior Notes due February 1, 2009;
- $250 million of 7.50% Senior Notes due November 1, 2010;
- $700 million of 6.75% Senior Notes due March 15, 2011;
- $25 million of New Jersey Economic Development Revenue Refunding Bonds due January 15, 2018 (our subsidiary, Kinder Morgan Liquids Terminals LLC, is the obligor on the bonds);
- $23.7 million of tax-exempt bonds due 2024 (our subsidiary, Kinder Morgan Operating L.P. "B", is the obligor on the bonds);
- $300 million of 7.40% Senior Notes due March 15, 2031;
- $79.6 million of Series F First Mortgage Notes due December 2004 (our subsidiary, SFPP, L.P. is the obligor on the notes);
- $87.9 million of Industrial Revenue Bonds with final maturities ranging from September 2019 to December 2024 (our subsidiary, Kinder Morgan Liquids Terminals LLC, is the obligor on the bonds);
- $35 million of 7.84% Senior Notes, with a final maturity of July 2008 (our subsidiary, Central Florida Pipe Line LLC, is the obligor on the notes); and
- a $900 million short-term commercial paper program.
None of our debt or credit facilities are subject to payment acceleration as a result of any change to our credit ratings. Our short-term debt at December 31, 2001, consisted of:
- $590.5 million of commercial paper borrowings;
- $200.0 million under our Floating Rate Senior Notes due March 22, 2002;
- $42.5 million under the SFPP 10.7% First Mortgage Notes; and
- $3.5 million in other borrowings.
Based on prior successful short-term debt refinancings and current market conditions, we intend and have the ability to refinance $276.3 million of our short-term debt on a long-term basis under our unsecured five-year credit facility, and we do not anticipate any liquidity problems.
Credit Facilities
On September 29, 1999, our $325 million credit facility was replaced with a $300 million unsecured five-year credit facility expiring in September 2004 and a $300 million unsecured 364-day credit facility. We recorded an extraordinary charge of $2.6 million related to the retirement of our $325 million credit facility. Our 364-day credit facility expired on September 29, 2000 and was extended until October 25, 2000. On October 25, 2000, the facility was replaced with a new $600 million unsecured 364-day credit facility expiring on October 25, 2001. The outstanding balance under our 364-day credit facility was $582 million at December 31, 2000.
During the first quarter of 2001, we obtained a third unsecured credit facility, in the amount of $1.1 billion, expiring on December 31, 2001. The terms of this credit facility were substantially similar to the terms of the other two facilities. Upon issuance of additional senior notes on March 12, 2001, this short-term credit facility was reduced to $500 million. During the second quarter of 2001, we terminated our $500 million credit facility, which was scheduled to expire on December 31, 2001. On October 25, 2001, our 364-day credit facility expired and we obtained a new $750 million unsecured 364-day credit facility. The terms of this credit facility are substantially similar to the terms of the expired facility. No borrowings were outstanding under our 364-day credit facility at December 31, 2001.
On August 11, 2000, we refinanced the outstanding balance under SFPP, L.P.'s secured credit facility with a $175.0 million borrowing under our five-year credit facility. The outstanding balance under our five-year credit facility was $207.6 million at December 31, 2000. No borrowings were outstanding under our five-year credit facility at December 31, 2001.
Our two credit facilities are with a syndicate of financial institutions. First Union National Bank is the administrative agent under the agreements. Interest on our credit facilities accrues at our option at a floating rate equal to either:
- First Union National Bank's base rate (but not less than the Federal Funds Rate, plus 0.5%); or
- LIBOR, plus a margin, which varies depending upon the credit rating of our long-term senior unsecured debt.
Our five-year credit facility also permits us to obtain bids for fixed rate loans from members of the lending syndicate. The weighted average interest rate on our borrowings under our credit facilities was 6.1531% during 2001 and 6.8987% during 2000.
The amount available for borrowing under our credit facilities are reduced by a $23.7 million letter of credit that supports Kinder Morgan Operating L.P. "B"'s tax-exempt bonds and our outstanding commercial paper borrowings.
We intend to secure promptly after the date of this document an additional $750 million credit facility to back-up an increase in our commercial paper program to $1.8 billion to fund the Tejas acquisition. We expect to terminate this facility once we have issued debt and/or equity to permanently finance the
acquisition. At that time, our commercial paper capacity will be reduced to $1.05 billion. We expect to increase the debt to EBITDA ratio allowed by our credit facilities to 4.25 to 1 through June 30, 2002.
Senior Notes
Under an indenture dated March 22, 2000, we completed a private placement of $200 million of floating rate notes due March 22, 2002 and $200 million of 8.0% notes due March 15, 2005. On May 31, 2000, we exchanged these notes with substantially identical notes that were registered under the Securities Act of 1933. The proceeds from this offering, net of underwriting discounts, were $397.9 million. The proceeds from the issuance of these notes were used to reduce our outstanding commercial paper. At December 31, 2001, the interest rate on our floating rate notes was 3.1025%.
On November 8, 2000, we closed a private placement of $250 million of 7.5% notes due November 1, 2010. On March 28, 2001, we exchanged these notes with substantially identical notes that were registered under the Securities Act of 1933. The proceeds from this offering, net of underwriting discounts, were $246.8 million. These proceeds were used to reduce our outstanding commercial paper.
On March 12, 2001, we closed a public offering of $1.0 billion in principal amount of senior notes, consisting of $700 million in principal amount of 6.75% senior notes due March 15, 2011 at a price to the public of 99.705% per note, and $300 million in principal amount of 7.40% senior notes due March 15, 2031 at a price to the public of 99.748% per note. In the offering, we received proceeds, net of underwriting discounts and commissions, of approximately $693.4 million for the 6.75% notes and $296.6 million for the 7.40% notes. We used the proceeds to pay for our acquisition of Pinney Dock & Transport LLC (see Note 3) and to reduce our outstanding balance on our credit facilities and commercial paper borrowings.
At December 31, 2001, our unamortized liability balance due on the various series of our senior notes were as follows (in millions):
In addition, in order to maintain a cost effective capital structure, it is our policy to borrow funds utilizing a mix of fixed rate debt and variable rate debt. In the third quarter of 2001, we elected to adjust our mix to be closer to our target ratio of 50% fixed rate debt and 50% variable rate debt. Accordingly, in August 2001, we entered into interest rate swap agreements with a notional principal amount of $750 million for the purpose of hedging the interest rate risk associated with our fixed rate debt obligations. These agreements effectively convert the interest expense associated with the following series of our senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread:
- 8.0% senior notes due March 15, 2005;
- 6.30% senior notes due February 1, 2009; and
- 7.40% senior notes due March 15, 2031.
The swap agreements for our 8.0% senior notes and 6.30% senior notes have terms that correspond to the maturity dates of such series. The swap agreement for our 7.40% senior notes contains mutual cash-out agreements at the then-current economic value every seven years.
Commercial Paper Program
In December 1999, we established a commercial paper program providing for the issuance of up to $200 million of commercial paper, subsequently increased to $300 million in January 2000. On October 25, 2000, in conjunction with our new 364-day credit facility, we also increased our commercial paper program to provide for the issuance of up to $600 million of commercial paper. During the first quarter of 2001, we increased our commercial paper program to provide for the issuance of an additional $1.1 billion of commercial paper, and during the second quarter of 2001, we decreased our commercial paper program back to $600 million. On October 17, 2001, we increased our commercial paper program to $900 million. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facilities. As of December 31, 2001, we had $590.5 million of commercial paper outstanding with an interest rate of 2.6585%. The borrowings under our commercial paper program were used to finance acquisitions made during 2001.
We intend to secure promptly after the date of this document an additional $750 million credit facility to back-up an increase in our commercial paper program to $1.8 billion to fund the Tejas acquisition. We expect to terminate this facility once we have issued debt and/or equity to permanently finance the acquisition. At that time, our commercial paper capacity will be reduced to $1.05 billion. We expect to increase the debt to EBITDA ratio allowed by our credit facilities to 4.25 to 1 through June 30, 2002.
SFPP, L.P. Debt
At December 31, 2001, the outstanding balance under SFPP, L.P.'s Series F notes was $79.6 million. The annual interest rate on the Series F notes is 10.70%, the maturity is December 2004, and interest is payable semiannually in June and December. We expect to repay the Series F notes prior to maturity as a result of SFPP , L.P. taking advantage of certain optional prepayment provisions without penalty in 1999 and 2000. Remaining annual installments are $42.6 million in 2002 and $37.0 million in 2003. Additionally, the Series F notes may be prepaid in full or in part at a price equal to par plus, in certain circumstances, a premium. We agreed as part of the acquisition of SFPP, L.P.'s operations (which constitute a significant portion of our Pacific operations) not to take actions with respect to $190 million of SFPP, L.P.'s debt that would cause adverse tax consequences for the prior general partner of SFPP, L.P. The Series F notes are secured by mortgages on substantially all of the properties of SFPP, L.P. The Series F notes contain certain covenants limiting the amount of additional debt or equity that may be issued by SFPP, L.P. and limiting the amount of cash distributions, investments, and property dispositions by SFPP, L.P. We do not believe that these restrictions will materially affect distributions to our partners.
Kinder Morgan Liquids Terminals LLC Debt
Effective January 1, 2001, we acquired Kinder Morgan Liquids Terminals LLC (see Note 3). As part of our purchase price, we assumed debt of $87.9 million, consisting of five series of Industrial Revenue Bonds. The Bonds consist of the following:
- $4.1 million of 7.30% New Jersey Industrial Revenue Bonds due September 1, 2019;
- $59.5 million of 6.95% Texas Industrial Revenue Bonds due February 1, 2022;
- $7.4 million of 6.65% New Jersey Industrial Revenue Bonds due September 1, 2022;
- $13.3 million of 7.00% Louisiana Industrial Revenue Bonds due March 1, 2023; and
- $3.6 million of 6.625% Texas Industrial Revenue Bonds due February 1, 2024.
In November 2001, we acquired a liquids terminal in Perth Amboy, New Jersey from Stolthaven Perth Amboy Inc. and Stolt-Nielsen Transportation Group, Ltd. As part of our purchase price, we assumed $25.0 million of Economic Development Revenue Refunding Bonds issued by the New Jersey Economic Development Authority. The bonds have a maturity date of January 15, 2018. Interest on these bonds is computed on the basis of a year of 365 or 366 days, as applicable, for the actual number of days elapsed during Commercial Paper, Daily or Weekly Rate Periods and on the basis of a 360-day year
consisting of twelve 30-day months during a Term Rate Period. As of December 31, 2001, the interest rate was 1.391%. We have an outstanding letter of credit issued by Citibank in the amount of $25.3 million that backs-up the $25.0 million principal amount of the bonds and $0.3 million of interest on the bonds for up to 42 days computed at 12% on a per annum basis on the principal thereof.
Central Florida Pipeline LLC Debt
Effective January 1, 2001, we acquired Central Florida Pipeline LLC (see Note 3). As part of our purchase price, we assumed an aggregate principal amount of $40 million of Senior Notes originally issued to a syndicate of eight insurance companies. The Senior Notes have a fixed annual interest rate of 7.84% and will be repaid in annual installments of $5 million beginning July 23, 2001. The final payment is due July 23, 2008. Interest is payable semiannually on January 1 and July 23 of each year. At December 31, 2001, Central Florida's outstanding balance under the Senior Notes was $35.0 million.
CALNEV Pipe Line LLC Debt
Effective March 30, 2001, we acquired CALNEV Pipe Line LLC (see Note 3). As part of our purchase price, we assumed an aggregate principal amount of $6.8 million of Senior Notes originally issued to a syndicate of five insurance companies. The Senior Notes had a fixed annual interest rate of 10.07%. In June 2001, we prepaid the balance outstanding under the Senior Notes, plus $0.9 million for interest and a make-whole premium, from cash on hand.
Trailblazer Pipeline Company Debt
At December 31, 2000, Trailblazer Pipeline Company had a $10 million borrowing under an intercompany account payable in favor of KMI. In January 2001, Trailblazer Pipeline Company entered into a 364-day revolving credit agreement with Credit Lyonnais New York Branch, providing for loans up to $10 million. The borrowings were used to pay the account payable to KMI. The agreement was to expire on December 27, 2001. The agreement provided for an interest rate of LIBOR plus 0.875%. Pursuant to the terms of the revolving credit agreement with Credit Lyonnais New York Branch, Trailblazer Pipeline Company partnership distributions were restricted by certain financial covenants.
On June 26, 2001, Trailblazer Pipeline Company prepaid the balance outstanding under its Senior Secured Notes using a new two-year unsecured revolving credit facility with a bank syndication. The new facility, as amended August 24, 2001, provides for loans of up to $85.2 million and expires June 29, 2003. The agreement provides for an interest rate of LIBOR plus a margin as determined by certain financial ratios. On June 29, 2001, Trailblazer Pipeline Company paid the $10 million outstanding balance under its 364-day revolving credit agreement and terminated that agreement. At December 31, 2001, the outstanding balance under Trailblazer Pipeline Company's two-year revolving credit facility was $55.0 million, with a weighted average interest rate of 2.875%, which reflects three-month LIBOR plus a margin of 0.875%. Pursuant to the terms of the revolving credit facility, Trailblazer Pipeline Company partnership distributions are restricted by certain financial covenants. We do not believe that these restrictions will materially affect distributions to our partners.
On September 23, 1992, pursuant to the terms of a Note Purchase Agreement, Trailblazer Pipeline Company issued and sold an aggregate principal amount of $101 million of Senior Secured Notes to a syndicate of fifteen insurance companies. The Senior Secured Notes had a fixed annual interest rate of 8.03% and the $20.2 million balance as of December 31, 2000 was to be repaid in semiannual installments of $5.05 million from March 1, 2001 through September 1, 2002, the final maturity date. Interest was payable semiannually in March and September. Trailblazer Pipeline Company provided collateral for the notes principally by an assignment of certain Trailblazer Pipeline Company transportation contracts, and pursuant to the terms of this Note Purchase Agreement, Trailblazer Pipeline Company's partnership distributions were restricted by certain financial covenants. Effective April 29, 1997, Trailblazer Pipeline Company amended the Note Purchase Agreement. This amendment allowed Trailblazer Pipeline Company to include several additional transportation contracts as collateral for the notes, added a
limitation on the amount of additional money that Trailblazer Pipeline Company could borrow and relieved Trailblazer Pipeline Company from its security deposit obligation. On June 26, 2001, Trailblazer Pipeline Company prepaid the $15.2 million balance outstanding under the Senior Secured Notes, plus $0.8 million for interest and a make-whole premium, using its new two-year unsecured revolving credit facility.
Kinder Morgan Operating L.P. "B" Debt
The $23.7 million principal amount of tax-exempt bonds due 2024 were issued by the Jackson-Union Counties Regional Port District. These bonds bear interest at a weekly floating market rate. During 2001, the weighted-average interest rate on these bonds was 2.71% per annum, and at December 31, 2001 the interest rate was 1.70%. We have an outstanding letter of credit issued under our credit facilities that backs-up our tax-exempt bonds. The letter of credit reduces the amount available for borrowing under our credit facilities.
Cortez Pipeline
Pursuant to a certain Throughput and Deficiency Agreement, the owners of Cortez Pipeline Company are required to contribute capital to Cortez in the event of a cash deficiency. The agreement contractually supports the financings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by obligating the owners of Cortez Pipeline to fund cash deficiencies at Cortez Pipeline, including cash deficiencies relating to the repayment of principal and interest. Their respective parent or other companies further severally guarantee the obligations of the Cortez Pipeline owners under this agreement.
Due to our indirect ownership of Cortez through KMCO(2), we severally guarantee 50% of the debt of Cortez Capital Corporation. Shell Oil Company shares our guaranty obligations jointly and severally through December 31, 2006 for Cortez's debt programs in place as of April 1, 2000.
At December 31, 2001, the debt facilities of Cortez Capital Corporation consisted of:
- a $127 million uncommitted 364-day revolving credit facility;
- a $48 million committed 364-day revolving credit facility;
- $136.4 million of Series D notes; and
- a $175 million short-term commercial paper program.
At December 31, 2001, Cortez had $146 million of commercial paper outstanding with an interest rate of 1.87%, the average interest rate on the series D notes was 6.8378% and there were no borrowings under the credit facilities.
MATURITIES OF DEBT
The scheduled maturities of our outstanding debt at December 31, 2001, are summarized as follows (in thousands):
Of the $836.5 million scheduled to mature in 2002, we intend and have the ability to refinance $276.3 million on a long-term basis under our existing credit facilities. We expect to pay the remaining portion of our short-term debt within the next year.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair value of our long-term debt based upon prevailing interest rates available to us at December 31, 2001 and December 31, 2000 is disclosed below.
Fair value as used in SFAS No. 107 "Disclosures About Fair Value of Financial Instruments" represents the amount at which an instrument could be exchanged in a current transaction between willing parties.
10. PENSIONS AND OTHER POST-RETIREMENT BENEFITS
In connection with our acquisition of SFPP and Kinder Morgan Bulk Terminals in 1998, we acquired certain liabilities for pension and post-retirement benefits. We provide medical and life insurance benefits to current employees, their covered dependents and beneficiaries of SFPP and Kinder Morgan Bulk Terminals. We also provide the same benefits to former salaried employees of SFPP. Additionally, we will continue to fund these costs for those employees currently in the plan during their retirement years.
The noncontributory defined benefit pension plan covering the former employees of Kinder Morgan Bulk Terminals is the Employee Benefit Plan for Employees of Hall-Buck Marine Services Company and the benefits under this plan were based primarily upon years of service and final average pensionable earnings. Benefit accruals were frozen as of December 31, 1998 for the Hall-Buck plan. Effective December 31, 2000, the Hall-Buck plan, along with the K N Energy, Inc. Retirement Plan for Bargaining Employees, was merged into the K N Energy, Inc. Retirement Plan for Non-Bargaining employees, with the Non-Bargaining Plan being the surviving plan. The merged plan was renamed the Kinder Morgan, Inc. Retirement Plan.
SFPP's post-retirement benefit plan is frozen and no additional participants may join the plan. As a result of these events, we recognized a curtailment gain related to the SFPP's plan of $3.9 million in 1999.
Net periodic benefit costs and weighted-average assumptions for these plans include the following components (in thousands):
Information concerning benefit obligations, plan assets, funded status and recorded values for these plans follows (in thousands):
In 2001, SFPP modified benefits associated with its post-retirement benefit plan. This plan amendment resulted in a $2.5 million increase in its benefit obligation for 2001. The unrecognized prior service credit is amortized on a straight-line basis over the remaining expected service to retirement (3.5 years). For measurement purposes, a 12% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2001. The rate was assumed to decrease gradually to 5% by 2008 and remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% change in assumed health care cost trend rates would have the following effects:
Multiemployer Plans and Other Benefits. With our acquisition of Kinder Morgan Bulk Terminals, effective July 1, 1998, we participate in multi-employer pension plans for the benefit of its employees who are union members. We do not administer these plans and contribute to them in accordance with the provisions of negotiated labor contracts. Other benefits include a self-insured health and welfare insurance plan and an employee health plan where employees may contribute for their dependents' health care costs. Amounts charged to expense for these plans were $0.6 million for the year ended 2001 and $0.2 million for the year ended 2000. The amount charged from the period of acquisition through December 31, 1998 was $0.5 million.
We assumed River Consulting, Inc.'s (a consolidated affiliate of Kinder Morgan Bulk Terminals) savings plan under Section 401(k) of the Internal Revenue Code. This savings plan allowed eligible employees to contribute up to 10% of their compensation on a pre-tax basis, with us matching 2.5% of the first 5% of the employees' wage. Matching contributions are vested at the time of eligibility, which is one year after employment. Effective January 1, 1999, we merged this savings plan into the retirement savings plan of our general partner (see next paragraph).
Effective July 1, 1997, our general partner established the Kinder Morgan Retirement Savings Plan, a defined contribution 401(k) plan. This plan was subsequently amended and merged to form the Kinder Morgan Savings Plan. The plan now permits all full-time employees of our general partner to contribute 1% to 50% of base compensation, on a pre-tax basis, into participant accounts. In addition to a mandatory contribution equal to 4% of base compensation per year for most plan participants, our general partner may make discretionary contributions in years when specific performance objectives are met. Certain employees' contributions are based on collective bargaining agreements. Our mandatory contributions are made each pay period on behalf of each eligible employee. Any discretionary contributions are made during the first quarter following the performance year. All contributions, including discretionary contributions, are in the form of KMI stock that is immediately convertible into other available investment vehicles at the employee's discretion. In the first quarter of 2002, no discretionary contributions were made to individual accounts for 2001. The total amount charged to expense for our Retirement Savings Plan was $4.6 million during 2001. All contributions, together with earnings thereon, are immediately vested and not subject to forfeiture. Participants may direct the investment of their contributions into a variety of investments. Plan assets are held and distributed pursuant to a trust agreement.
Effective January 1, 2001, employees of our general partner became eligible to participate in a new Cash Balance Retirement Plan. Certain employees continue to accrue benefits through a career-pay formula, "grandfathered" according to age and years of service on December 31, 2000, or collective bargaining arrangements. All other employees will accrue benefits through a personal retirement account in the new Cash Balance Retirement Plan. Employees with prior service and not grandfathered convert to the Cash Balance Retirement Plan and will be credited with the current fair value of any benefits they have previously accrued through the defined benefit plan. We will then begin contributions on behalf of these employees equal to 3% of eligible compensation every pay period. In addition, we may make discretionary contributions to the plan based on our performance. In the first quarter of 2002, an additional 1% discretionary contribution was made to individual accounts based on achieving 2001 financial targets to unitholders. Interest will be credited to the personal retirement accounts at the 30-year U.S. Treasury bond rate in effect each year. Employees will be fully vested in the plan after five years, and they may take a lump sum distribution upon termination of employment or retirement.
11. PARTNERS' CAPITAL
At December 31, 2001, our Partners' capital consisted of 129,855,018 common units, 5,313,400 Class B units and 30,636,363 i-units. Together, these 165,804,781 units represent the limited partners' interest and an effective 98% economic interest in the Partnership, exclusive of our general partner's incentive distribution. Our common unit total consisted of 110,071,392 units held by third parties, 18,059,626 units held by KMI and its consolidated affiliates (excluding our general partner) and 1,724,000 units held by our general partner. Our Class B units were held entirely by KMI and our i-units were held entirely by KMR. At December 31, 2000 and 1999, there were 129,716,218 and 118,274,274 common units outstanding, respectively. The Class B units were issued in December 2000 and the i-units were issued in 2001. Our general partner has an effective 2% interest in the Partnership, excluding the general partner's incentive distribution.
In May 2001, we received net proceeds of approximately $996.9 million from KMR for the issuance of i-units. In accordance with KMR's public offering of limited liability shares, i-units were issued as follows:
- 2,975,000 units to KMI; and
- 26,775,000 units to the public.
We used the proceeds from the i-unit issuance to reduce the debt we incurred in our acquisition of GATX Corporation's domestic pipeline and liquids terminal businesses during the first quarter of 2001. The i-units are a separate class of limited partner interest in the Partnership. All of the i-units will be owned by KMR and will not be publicly traded. KMR's limited liability company agreement provides that the number of all of its outstanding shares, including voting shares owned by our general partner, shall at all times equal the number of i-units that it owns. Through the combined effect of the provisions in our partnership agreement and the provisions of KMR's limited liability company agreement, the number of outstanding KMR shares and the number of i-units will at all times be equal.
KMR, as the owner of the i-units, generally will vote together with the holders of the common units and Class B units as a single class. However, the i-units will vote separately as a class on the following matters:
- amendments to our partnership agreement that would have a material adverse effect on the holders of the i-units in relation to the other classes of units (this kind of an amendment requires the approval of two-thirds of the outstanding i-units, excluding the number of i-units equal to the number of KMR shares owned by KMI and its affiliates); and
- the approval of the withdrawal of our general partner or the transfer to a non-affiliate of all of its interest as our general partner (these matters require the approval of a majority of the outstanding i-units excluding the number of i-units equal to the number of KMR shares owned by KMI and its affiliates).
In all cases, KMR will vote its i-units in proportion to the affirmative and negative votes, abstentions and non-votes of owners of KMR shares. Furthermore, under the terms of our partnership agreement, we agree that we will not, except in liquidation, make a distribution on an i-unit other than in additional i-units or a security that has in all material respects the same rights and privileges as our i-units. Typically, our general partner and owners of common units and Class B units will receive distributions from us in cash, while KMR as the owner of i-units will receive distributions in additional i-units or fractions of i-units. For each outstanding i-unit, a fraction of an i-unit will be issued. The fraction will be determined by dividing the amount of cash being distributed per common unit by the average market price of a KMR share over the ten consecutive trading days preceding the date on which the shares begin to trade ex-dividend under the rules of the principal exchange on which the shares are listed. The cash equivalent of distributions of i-units will be treated as if it had actually been distributed for purposes of determining the distributions to our general partner. We will not distribute the related cash but will retain the cash and use the cash in our business. If additional units are distributed to the holders of our common units, we will issue an equivalent amount of i-units to KMR based on the number of i-units it owns.
For the purposes of maintaining partner capital accounts, our partnership agreement specifies that items of income and loss shall be allocated among the partners, other than owners of i-units, in accordance with their percentage interests. Normal allocations according to percentage interests are made, however, only after giving effect to any priority income allocations in an amount equal to the incentive distributions that are allocated 100% to our general partner.
Incentive distributions allocated to our general partner are determined by the amount quarterly distributions to unitholders exceed certain specified target levels. For the years ended December 31, 2001, 2000 and 1999, we distributed $2.15, $1.7125 and $1.425, respectively, per unit. Our distributions to unitholders for 2001, 2000 and 1999 required incentive distributions to our general partner in the amount of $199.7 million, $107.8 million and $55.0 million, respectively. The increased incentive distributions paid
for 2001 over 2000 and 2000 over 1999 reflect the increase in amounts distributed per unit as well as the issuance of additional units.
On January 16, 2002, we declared a cash distribution for the quarterly period ended December 31, 2001, of $0.55 per unit. This distribution was paid on February 14, 2002, to unitholders of record as of January 31, 2002. Our common unitholders and Class B unitholders received cash. KMR, our sole i-unitholder, received a distribution in the form of additional i-units based on the $0.55 distribution per common unit. The number of i-units distributed was 453,970. For each outstanding i-unit that KMR held, a fraction of an i-unit was issued. The fraction was determined by dividing:
- $0.55, the cash amount distributed per common unit
by
- $37.116, the average of KMR's limited liability shares' closing market prices from January 14-28, 2002, the ten consecutive trading days preceding the date on which the shares began to trade ex-dividend under the rules of the New York Stock Exchange.
This distribution required an incentive distribution to our general partner in the amount of $54.4 million. Since this distribution was declared after the end of the quarter, no amount is shown in the December 31, 2001 balance sheet as a Distribution Payable.
12. RELATED PARTY TRANSACTIONS
GENERAL AND ADMINISTRATIVE EXPENSES
Kinder Morgan Management, LLC, through its wholly owned subsidiary, Kinder Morgan Services LLC provides employees and related centralized payroll and employee benefits services to us, our operating partnerships and subsidiaries, Kinder Morgan G.P., Inc. and KMR (collectively, the "Group"). Employees of Kinder Morgan Services are assigned to work for one or more members of the Group. The direct costs of all compensation, benefits expenses, employer taxes and other employer expenses for these employees are allocated and charged by Kinder Morgan Services LLC to the appropriate members of the Group; and the members of the Group reimburse Kinder Morgan Services for their allocated shares of these direct costs. There is no profit or margin charged by Kinder Morgan Services LLC to the members of the Group. The administrative support necessary to implement these payroll and benefits services is provided by the human resource department of Kinder Morgan, Inc., and the related administrative costs are allocated to members of the Group in accordance with existing expense allocation procedures. The effect of these arrangements is that each member of the Group bears the direct compensation and employee benefits costs of its assigned or partially assigned employees, as the case may be, while also bearing its allocable share of administrative costs. Pursuant to our limited partnership agreement, we reimburse Kinder Morgan Services LLC for our share of these administrative costs and such reimbursements will be accounted for as described above.
The named executive officers of our general partner and KMR and some other employees that provide management or services to both Kinder Morgan, Inc. and the Group are employed by Kinder Morgan, Inc. Additionally, other Kinder Morgan, Inc. employees assist in the operation of Kinder Morgan Energy Partners' Natural Gas Pipeline assets formerly owned by Kinder Morgan, Inc. These Kinder Morgan, Inc. employees' expenses are allocated without a profit component between Kinder Morgan, Inc. and the appropriate members of the Group.
PARTNERSHIP DISTRIBUTIONS
Kinder Morgan G.P., Inc.
Kinder Morgan G.P., Inc. serves as our sole general partner. Pursuant to our partnership agreements, our general partner's interests represent a 1% ownership interest in the Partnership, and a direct 1.0101% ownership interest in each of our five operating partnerships. Collectively, our general partner owns an effective 2% interest in the operating partnerships, excluding incentive distributions:
- its 1.0101% direct general partner ownership interest (accounted for as minority interest in the consolidated financial statements of the Partnership); and
- its 0.9899% ownership interest indirectly owned via its 1% ownership interest in the Partnership.
At December 31, 2001, our general partner owned 1,724,000 common units, representing approximately 1.04% of our outstanding limited partner units. Our partnership agreement requires that we distribute 100% of "Available Cash" (as defined in the partnership agreement) to our partners within 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Available Cash consists generally of all of our cash receipts and net reductions in reserves less cash disbursements and net additions to reserves (including any reserves required under debt instruments for future principal and interest payments) and amounts payable to the former general partner of SFPP, L.P. in respect of its remaining 0.5% special limited partner interest in SFPP, L.P.
Our general partner is granted discretion by our partnership agreement, which discretion has been delegated to KMR, subject to the approval of our general partner in certain cases, to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, rate refunds and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When KMR determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.
Typically, our general partner and owners of our common units and Class B units receive distributions in cash, while KMR, the sole owner of our i-units, receives distributions in additional i-units or fractions of i-units. For each outstanding i-unit, a fraction of an i-unit will be issued. The fraction is calculated by dividing the amount of cash being distributed per common unit by the average market price of KMR's limited liability shares over the ten consecutive trading days preceding the date on which the shares begin to trade ex-dividend under the rules of the New York Stock Exchange. The cash equivalent of distributions of i-units will be treated as if it had actually been distributed, including for purposes of determining the distributions to our general partner and calculating Available Cash for future periods. We will not distribute the related cash but will retain the cash and use the cash in our business.
Available Cash is initially distributed 98% to our limited partners and 2% to our general partner. These distribution percentages are modified to provide for incentive distributions to be paid to our general partner in the event that quarterly distributions to unitholders exceed certain specified targets.
Available Cash for each quarter is distributed as follows;
- first, 98% to the owners of all classes of units pro rata and 2% to our general partner until the owners of all classes of units have received a total of $0.15125 per unit in cash or equivalent i-units for such quarter;
- second, 85% of any Available Cash then remaining to the owners of all classes of units pro rata and 15% to our general partner until the owners of all classes of units have received a total of $0.17875 per unit in cash or equivalent i-units for such quarter;
- third, 75% of any Available Cash then remaining to the owners of all classes of units pro rata and 25% to our general partner until the owners of all classes of units have received a total of $0.23375 per unit in cash or equivalent i-units for such quarter; and
- fourth, 50% of any Available Cash then remaining to the owners of all classes of units pro rata, to owners of common units and Class B units in cash and to KMR in the equivalent number of i-units, and 50% to our general partner in cash.
Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate amount of cash being distributed. Our general partner's declared incentive distributions for the years ended December 31, 2001, 2000 and 1999 were $199.7 million, $107.8 million and $55.0 million, respectively.
Kinder Morgan, Inc.
KMI, through its subsidiary Kinder Morgan (Delaware), Inc., remains the sole stockholder of our general partner. At December 31, 2001, KMI directly owned 13,047,300 common units and 5,313,400 class B units, indirectly owned 6,736,326 common units owned by its consolidated affiliates, including our general partner, and owned 5,956,946 KMR shares, representing an indirect ownership interest of 5,956,946 i-units. These units represent approximately 18.7% of our outstanding limited partner units.
Kinder Morgan Management, LLC
KMR, our general partner's delegate, remains the sole owner of our 30,636,363 i-units.
ASSET ACQUISITIONS
Effective December 31, 1999, we acquired over $935.8 million of assets from KMI. As consideration for the assets, we paid to KMI $330 million and 19,620,000 common units, valued at approximately $406.3 million. In addition, we assumed $40.3 million in debt and approximately $121.6 million in liabilities. We acquired Kinder Morgan Interstate Gas Transmission LLC (formerly K N Interstate Gas Transmission Co.), a 33 1/3% interest in Trailblazer Pipeline Company and a 49% equity interest in Red Cedar Gathering Company. The acquired interest in Trailblazer Pipeline Company, when combined with the interest purchased on November 30, 1999, gave us a 66 2/3% ownership interest.
Effective December 31, 2000, we acquired over $621.7 million of assets from KMI. As consideration for these assets, we paid to KMI $192.7 million in cash and approximately $156.3 million in units, consisting of 1,280,000 common units and 5,313,400 class B units. We also assumed liabilities of approximately $272.7 million. We acquired Kinder Morgan Texas Pipeline, L.P. and MidCon NGL Corp. (both of which were converted to single-member limited liability companies), the Casper and Douglas natural gas gathering and processing systems, a 50% interest in Coyote Gas Treating, LLC and a 25% interest in Thunder Creek Gas Services, LLC. The purchase price for the transaction was determined by the boards of directors of KMI and our general partner based on pricing principles used in the acquisition of similar assets as well as a fairness opinion from the investment banking firm A.G. Edwards & Sons, Inc.
OPERATIONS
KMI or its subsidiaries operate and maintain for us the assets comprising our Natural Gas Pipelines business segment. Natural Gas Pipeline Company of America, a subsidiary of KMI, operates Trailblazer Pipeline Company's assets under a long-term contract pursuant to which Trailblazer Pipeline Company incurs the costs and expenses related to NGPL's operating and maintaining the assets. Trailblazer Pipeline Company provides the funds for capital expenditures. NGPL does not profit from or suffer loss related to its operation of Trailblazer Pipeline Company's assets.
The remaining assets comprising our Natural Gas Pipelines business segment are operated under two separate agreements, one entered into December 31, 1999, between KMI and Kinder Morgan Interstate Gas Transmission LLC, and one entered into December 31, 2000, between KMI and Kinder Morgan Operating L.P. "A". Both agreements have five-year terms and contain automatic five-year extensions. Under these agreements, Kinder Morgan Interstate Gas Transmission LLC and Kinder Morgan Operating L.P. "A" pay KMI a fixed amount as reimbursement for the corporate general and administrative costs incurred in connection with the operation of these assets. The amounts paid to KMI under these agreements for corporate general and administrative costs were $9.5 million for 2001 and $6.1 million for 2000. For 2002, the amount will decrease to $8.6 million. Although we believe the amounts paid to KMI for the services they provided each year fairly reflect the value of the services performed, the determination of these amounts were not the result of arms length negotiations. However, due to the nature of the allocations, these reimbursements may not have exactly matched the actual time and overhead spent. We believe the agreed-upon amounts were, at the time the contracts were entered into, a reasonable estimate of the corporate general and administrative expenses to be incurred by KMI and its
subsidiaries in performing such services. We also reimburse KMI and its subsidiaries for operating and maintenance costs and capital expenditures incurred with respect to these assets.
OTHER
Generally, KMR makes all decisions relating to the management and control of our business. Our general partner owns all of KMR's voting securities and is its sole managing member. KMI, through its wholly owned and controlled subsidiary Kinder Morgan (Delaware), Inc., owns all the common stock of our general partner. Certain conflicts of interest could arise as a result of the relationships among KMR, our general partner, KMI and us. The directors and officers of KMI have fiduciary duties to manage KMI, including selection and management of its investments in its subsidiaries and affiliates, in a manner beneficial to the shareholders of KMI. In general, KMR has a fiduciary duty to manage us in a manner beneficial to our unitholders. The partnership agreements for us and our operating partnerships contain provisions that allow KMR to take into account the interests of parties in addition to us in resolving conflicts of interest, thereby limiting its fiduciary duty to our unitholders, as well as provisions that may restrict the remedies available to unitholders for actions taken that might, without such limitations, constitute breaches of fiduciary duty. The duty of the directors and officers of KMI to the shareholders of KMI may, therefore, come into conflict with the duties of KMR and its directors and officers to our unitholders. The Conflicts and Audit Committee of KMR's board of directors will, at the request of KMR, review (and is one of the means for resolving) conflicts of interest that may arise between KMI or its subsidiaries, on the one hand, and us, on the other hand.
13. LEASES AND COMMITMENTS
We have entered into certain operating leases. Including probable elections to exercise renewal options, the remaining terms on our leases range from one to 42 years. Future commitments related to these leases at December 31, 2001 are as follows (in thousands):
We have not reduced our total minimum payments for future minimum sublease rentals aggregating approximately $2.2 million. Total lease and rental expenses, including related variable charges were $41.1 million for 2001, $7.5 million for 2000 and $8.8 million for 1999.
During 1998, we established a common unit option plan, which provides that key personnel are eligible to receive grants of options to acquire common units. The number of common units available under the option plan is 500,000. The option plan terminates in March 2008. As of December 31, 2001, outstanding options for 379,400 common units were granted to certain personnel with a term of seven years at exercise prices equal to the market price of the common units at the grant date. In addition, as of December 31, 2001, outstanding options for 30,000 common units were granted to our three non-employee directors. The options granted generally vest 40% in the first year and 20% each year thereafter.
We apply Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations in accounting for common unit options granted under our common unit option plan. Pro forma information regarding changes in net income and per unit data, if the accounting prescribed by Statement of Financial Accounting Standards No. 123 "Accounting for Stock Based Compensation," had been applied, is not material. No compensation expense has been recorded since the options were granted at exercise prices equal to the market prices at the date of grant.
Effective January 17, 2002, our general partner entered into a retention agreement with C. Park Shaper, an officer of our general partner and its delegate. Pursuant to the terms of the agreement, Mr. Shaper received a $5 million personal loan guaranteed by us. Mr. Shaper was required to purchase KMI common shares and our common units in the open market with the loan proceeds. If he voluntarily leaves us prior to the end of five years, then he must repay the entire loan. After five years, provided Mr. Shaper has continued to be employed by our general partner, we and KMI will assume Mr. Shaper's obligations under the loan. The agreement contains provisions that address termination for cause, death, disability and change of control.
We have an Executive Compensation Plan for certain executive officers of our general partner. We may, at our option and with the approval of our unitholders, pay the participants in units instead of cash. Eligible awards are equal to a percentage of an incentive compensation value, which is equal to a formula based upon the cash distributions paid to our general partner during the four calendar quarters preceding the date of redemption multiplied by eight. The amount of these awards are accrued as compensation expense and adjusted quarterly. Under the plan, no eligible employee may receive a grant in excess of 2% of the incentive compensation value and total awards under the plan may not exceed 10% of the incentive compensation value. The plan terminates January 1, 2007, and any unredeemed awards will be automatically redeemed. At December 31, 2001, there were no outstanding awards granted under our Executive Compensation Plan.
14. RISK MANAGEMENT
HEDGING ACTIVITIES
Our normal business activities expose us to risks associated with changes in the market price of natural gas and associated transportation, natural gas liquids, crude oil and carbon dioxide. Through KMI, we use energy financial instruments to reduce our risk of price changes in the spot and fixed price of natural gas, natural gas liquids and crude oil markets as discussed below. We are exposed to credit-related losses in the event of nonperformance by counterparties to these financial instruments but, given their existing credit ratings, we do not expect any counterparties to fail to meet their obligations. The fair value of these risk management instruments reflects the estimated amounts that we would receive or pay to terminate the contracts at the reporting date, thereby taking into account the current unrealized gains or losses on open contracts. We have available market quotes for substantially all of the financial instruments that we use.
The energy risk management products that we use include:
- commodity futures and options contracts;
- fixed-price swaps; and
- basis swaps.
Pursuant to our management's approved policy, we are to engage in these activities only as a hedging mechanism against price volatility associated with:
- pre-existing or anticipated physical natural gas, natural gas liquids, crude oil and carbon dioxide sales;
- gas purchases; and
- system use and storage.
Our risk management activities are only used in order to protect our profit margins and our risk management policies prohibit us from engaging in speculative trading. Commodity-related activities of our risk management group are monitored by KMI's Risk Management Committee, which is charged with the review and enforcement of our management's risk management policy.
Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" as amended by Statement of Financial Accounting Standards No. 137, "Accounting for Derivative Instruments and Hedging Activities -- Deferral of the Effective Date of FASB Statement No. 133" and No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities". SFAS No. 133 established accounting and reporting standards requiring that every derivative financial instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, SFAS No. 133 allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally designate a derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting. As a result of our adoption of SFAS No. 133, we recorded a cumulative effect adjustment in other comprehensive income of $22.8 million representing the fair value of our derivative financial instruments utilized for hedging activities as of January 1, 2001. During the year ended December 31, 2001, $16.6 million of this initial adjustment was reclassified to earnings as a result of hedged sales and purchases during the period.
Purchases or sales of commodity contracts require a dollar amount to be placed in margin accounts. In addition, through KMI, we are required to post margins with certain over-the-counter swap partners. These margin requirements are determined based upon credit limits and mark-to-market positions. Our margin deposits associated with commodity contract positions were $20.0 million at December 31, 2001 and $7.0 million on December 31, 2000. Our margin deposits associated with over-the-counter swap partners were ($42.1) million on December 31, 2001 and $0.0 on December 31, 2000.
We recognized approximately $1.3 million net in earnings as a loss during 2001 as a result of ineffective hedges, which amount is reported within the caption "Operations and maintenance" in the accompanying Consolidated Statements of Income. We did not exclude any component of the derivative instruments' gain or loss from the assessment of hedge effectiveness.
We reclassify the gains and losses included in accumulated other comprehensive income into earnings as the hedged sales and purchases take place. We expect to reclassify approximately $45.4 million of the accumulated other comprehensive income balance of $63.8 million representing unrecognized net gains on derivative activities at December 31, 2001 into earnings during the next twelve months. During 2001, we did not reclassify any gains or losses into earnings as a result of the discontinuance of cash flow hedges due to a determination that the forecasted transactions will no longer occur by the end of the originally specified time period.
The differences between the current market value and the original physical contracts value associated with hedging activities are primarily reflected as other current assets and accrued other current liabilities in the accompanying consolidated balance sheet at December 31, 2001. At December 31, 2001, our balance of $194.9 million of other current assets includes approximately $163.7 million related to risk management activities, and our balance of $209.9 million of accrued other current liabilities includes approximately $117.8 million related to risk management activities. The remaining differences between the current market value and the original physical contracts value associated with hedging activities are reflected as deferred charges or deferred credits in the accompanying consolidated balance sheet at December 31, 2001. Prior to 2001, we accounted for gain/loss on our over the counter swaps and marked our open futures position to market value. Such items were deferred on the balance sheet and reflected in current receivables, other current assets, accrued other current liabilities, deferred charges or deferred credits in the accompanying consolidated balance sheet at December 31, 2000. These deferrals are offset by the corresponding value of the underlying physical transactions. In the event energy financial instruments are terminated prior to the period of physical delivery of the items being hedged, the gains and losses on the energy financial instruments at the time of termination remain deferred until the period of physical delivery.
Given our portfolio of businesses as of December 31, 2001, our principal uses of derivative financial instruments will be to mitigate the risk associated with market movements in the price of energy commodities. Our short natural gas derivatives position primarily represents our hedging of anticipated future natural gas sales. Our short crude oil derivatives position represents our crude oil derivative sales made to hedge anticipated oil sales. In addition, crude oil contracts have been sold to hedge anticipated carbon dioxide sales that have pricing tied to crude oil prices. Finally, our short natural gas liquids derivatives position reflects the hedging of our forecasted natural gas liquids sales.
As of December 31, 2001, our commodity contracts and over-the-counter swaps and options (in thousands) consisted of the following:
- --------------- (1) A term of reference describing a unit of commodity trading. One natural gas contract equals 10,000 MMBtus. One crude oil or natural gas liquids contract equals 1,000 barrels.
Our over-the-counter swaps and options are with a number of parties, each of which is an investment grade credit. We both owe money and are owed money under these financial instruments. At December 31, 2001, if all parties owing us failed to pay us amounts due under these arrangements, our credit loss would be $23.2 million. At December 31, 2001, our largest credit exposure to a single counterparty was $4.5 million.
During the fourth quarter of 2001, we determined that Enron Corp. was no longer likely to honor the obligations it had to us in conjunction with derivatives we were accounting for as hedges under SFAS No. 133. Upon making that determination, we:
- ceased to account for those derivatives as hedges;
- entered into new derivative transactions with other counterparties to replace our position with Enron;
- designated the replacement derivative positions as hedges of the exposures that had been hedged with the Enron positions; and
- recognized a $6.0 million loss (included with "General and administrative" expenses in the accompanying Consolidated Statement of Operations for 2001) in recognition of the fact that it was unlikely that we would be paid the amounts then owed under the contracts with Enron.
While we enter into derivative transactions only with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that additional losses will result from counterparty credit risk in the future.
INTEREST RATE SWAPS
In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. Since August 1998, we have entered into interest rate swap agreements for the purpose of hedging the interest rate risk associated with our variable rate debt obligations. In the third quarter of 2001, we elected to adjust our mix to be closer to our target ratio of 50% fixed rate debt and 50% variable rate debt. Accordingly, in August 2001, we entered into interest rate swap agreements with a notional principal amount of $750 million for the purpose of hedging the interest rate risk associated with our fixed rate debt obligations. These agreements effectively convert the interest expense associated with the following series of our senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread:
- 8.0% senior notes due March 15, 2005;
- 6.30% senior notes due February 1, 2009; and
- 7.40% senior notes due March 15, 2031.
The swap agreements for our 8.0% senior notes and 6.30% senior notes have terms that correspond to the maturity dates of such series. The swap agreement for our 7.40% senior notes contains mutual cash-out agreements at the then-current economic value every seven years. As of December 31, 2001, we were party to interest rate swap agreements with a total notional principal amount of $900 million.
These swaps have been designated as fair value hedges as defined by SFAS No. 133. These swaps also meet the conditions required to assume no ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them using the "shortcut" method prescribed for fair value hedges by SFAS No. 133. Accordingly, we will adjust the carrying value of each swap to its fair value each quarter, with an offsetting entry to adjust the carrying value of the debt securities whose fair value is being hedged. We will record interest expense equal to the variable rate payments, which will be accrued monthly and paid semi-annually. At December 31, 2001, we recognized a liability of $5.4 million for the net fair value of our swap agreements and we included this amount with Other Long-Term Liabilities and Deferred Credits on the accompanying balance sheet.
15. REPORTABLE SEGMENTS
We compete in four reportable business segments (see Note 1):
- Products Pipelines;
- Natural Gas Pipelines;
- CO(2) Pipelines; and
- Terminals.
Each segment uses the same accounting policies as those described in the summary of significant accounting policies (see Note 2). We evaluate performance based on each segments' earnings, which exclude general and administrative expenses, third-party debt costs, interest income and expense and minority interest. Our reportable segments are strategic business units that offer different products and services. Each segment is managed separately because each segment involves different products and marketing strategies.
Our Products Pipelines segment derives its revenues primarily from the transportation of refined petroleum products, including gasoline, diesel fuel, jet fuel and natural gas liquids. Our Natural Gas Pipelines segment derives its revenues primarily from the gathering and transmission of natural gas. Our CO(2) Pipelines segment derives its revenues primarily from the marketing and transportation of carbon dioxide used as a flooding medium for recovering crude oil from mature oil fields. Our Terminals segment derives its revenues primarily from the transloading and storing of refined petroleum products and dry and liquid bulk products, including coal, petroleum coke, cement, alumina, salt, and chemicals.
Financial information by segment follows (in thousands):
- ---------------
(a) Includes interest and debt expense, general and administrative expenses, minority interest expense, extraordinary charges and other insignificant items.
- ---------------
(a) Includes cash, cash equivalents and certain unallocable deferred charges.
Our total operating revenues are derived from a wide customer base. For the year ended December 31, 2001, one customer accounted for more than 10% of our total consolidated revenues. Total transactions with Reliant Energy, within our Natural Gas Pipelines and Terminals segments, accounted for 20.2% of our total consolidated revenues during 2001. For each of the two years ending December 31, 2000 and 1999, no revenues from transactions with a single external customer amounted to 10% or more of our total consolidated revenues.
16. LITIGATION AND OTHER CONTINGENCIES
The tariffs charged for interstate common carrier pipeline transportation for our pipelines are subject to rate regulation by the Federal Energy Regulatory Commission ("FERC") under the Interstate Commerce Act. The Interstate Commerce Act requires, among other things, that petroleum products pipeline rates be just and reasonable and non-discriminatory. Pursuant to FERC Order No. 561, effective January 1, 1995, petroleum products pipelines are able to change their rates within prescribed ceiling levels that are tied to an inflation index. FERC Order No. 561-A, affirming and clarifying Order No. 561, expands the circumstances under which petroleum products pipelines may employ cost-of-service ratemaking in lieu of the indexing methodology, effective January 1, 1995. For each of the years ended December 31, 2001, 2000 and 1999, the application of the indexing methodology did not significantly affect our tariff rates.
FEDERAL ENERGY REGULATORY COMMISSION PROCEEDINGS
SFPP, L.P.
SFPP, L.P. is the subsidiary limited partnership that owns our Pacific operations, excluding the CALNEV pipeline and related terminals acquired from GATX Corporation. Tariffs charged by SFPP are subject to certain proceedings involving shippers' complaints regarding the interstate rates, as well as practices and the jurisdictional nature of certain facilities and services, on our Pacific operations' pipeline systems. In September 1992, El Paso Refinery, L.P. filed a protest/complaint with the FERC:
- challenging SFPP's East Line rates from El Paso, Texas to Tucson and Phoenix, Arizona;
- challenging SFPP's proration policy; and
- seeking to block the reversal of the direction of flow of SFPP's six-inch pipeline between Phoenix and Tucson.
At various dates following El Paso Refinery's September 1992 filing, other shippers on SFPP's South System filed separate complaints, and/or motions to intervene in the FERC proceeding, challenging SFPP's rates on its East and West Lines. These shippers include:
- Chevron U.S.A. Products Company;
- Navajo Refining Company;
- ARCO Products Company;
- Texaco Refining and Marketing Inc.;
- Refinery Holding Company, L.P. (a partnership formed by El Paso Refinery's long-term secured creditors that purchased its refinery in May 1993);
- Mobil Oil Corporation; and
- Tosco Corporation.
Certain of these parties also claimed that a gathering enhancement charge at SFPP's Watson origin pump station in Carson, California was charged in violation of the Interstate Commerce Act. In subsequent procedural rulings, the FERC consolidated these challenges (Docket Nos. OR92-8-000, et al.) and ruled that they must proceed as a complaint proceeding, with the burden of proof being placed on the complaining parties. These parties must show that SFPP's rates and practices at issue violate the requirements of the Interstate Commerce Act.
Hearings in the FERC proceeding were held in 1996 and an initial decision by the FERC administrative law judge was issued on September 25, 1997. The initial decision upheld SFPP's position that "changed circumstances" were not shown to exist on the West Line, thereby retaining the just and reasonable status of all West Line rates that were "grandfathered" under the Energy Policy Act of 1992. Accordingly, the administrative law judge ruled that these rates are not subject to challenge, either for the past or prospectively, in that proceeding. The administrative law judge's decision specifically excepted from that ruling SFPP's Tariff No. 18 for movement of jet fuel from Los Angeles to Tucson, which was initiated subsequent to the enactment of the Energy Policy Act.
The initial decision also included rulings that were generally adverse to SFPP on such cost of service issues as:
- the capital structure to be used in computing SFPP's 1985 starting rate base under FERC Opinion 154-B;
- the level of income tax allowance; and
- the recoverability of civil and regulatory litigation expense and certain pipeline reconditioning costs.
The administrative law judge also ruled that the gathering enhancement service at SFPP's Watson origin pump station was subject to FERC jurisdiction and ordered that a tariff for that service and supporting cost of service documentation be filed no later than 60 days after a final FERC order on this matter.
On January 13, 1999, the FERC issued its Opinion No. 435, which affirmed in part and modified in part the initial decision. In Opinion No. 435, the FERC ruled that all but one of the West Line rates are "grandfathered" as just and reasonable and that "changed circumstances" had not been shown to satisfy the complainants' threshold burden necessary to challenge those rates. The FERC further held that the one "non-grandfathered" West Line tariff did not require rate reduction. Accordingly, the FERC dismissed all complaints against the West Line rates without any requirement that SFPP reduce, or pay any reparations for, any West Line rate.
With respect to the East Line rates, Opinion No. 435 reversed in part and affirmed in part the initial decision's ruling regarding the methodology for calculating the rate base for the East Line. Opinion No. 435 modified the initial decision concerning the date on which the starting rate base should be calculated and the accumulated deferred income tax and allowable cost of equity used to calculate the rate base. In addition, Opinion No. 435 ruled that SFPP would not owe reparations to any complainant for any period prior to the date on which that complainant's complaint was filed, thus reducing by two years the potential reparations period claimed by most complainants. On January 19, 1999, ARCO filed a petition with the United States Court of Appeals for the District of Columbia Circuit for review of Opinion No. 435. Additional petitions for review were thereafter filed in that court by RHC, Navajo, Chevron and SFPP.
SFPP and certain complainants each sought rehearing of Opinion No. 435 by the FERC, asking that a number of rulings be modified. In compliance with Opinion No. 435, on March 15, 1999, SFPP submitted a compliance filing implementing the rulings made by FERC, establishing the level of rates to be charged by SFPP in the future, and setting forth the amount of reparations owed by SFPP to the complainants under the order. The complainants contested SFPP's compliance filing.
On July 6, 1999, in response to a motion by the FERC, the Court of Appeals held the ARCO and RHC petitions in abeyance pending FERC action on petitions for rehearing of Opinion No. 435 and dismissed the Navajo, Chevron and SFPP petitions as premature because those parties had sought FERC rehearing.
On May 17, 2000, the FERC issued its Opinion No. 435-A, which ruled on the requests for rehearing and modified Opinion No. 435 in certain respects. It denied requests to reverse its prior rulings that SFPP's West Line rates and Watson Station gathering enhancement facilities charge are entitled to be treated as just and reasonable "grandfathered" rates under the Energy Policy Act. It suggested, however, that if SFPP had fully recovered the capital costs of the Watson Station facilities, that might form the basis of an amended "changed circumstances" complaint.
Opinion No. 435-A granted a request by Chevron and Navajo to require that SFPP's December 1988 partnership capital structure be used to compute the starting rate base from December 1983 forward, as well as a request by SFPP to vacate a ruling that would have required the elimination of approximately $125 million from the rate base used to determine capital structure. It also granted two clarifications sought by Navajo, to the effect that SFPP's return on its starting rate base should be based on SFPP's capital structure in each given year (rather than a single capital structure from the outset) and that the return on deferred equity should also vary with the capital structure for each year. Opinion No. 435-A denied the request of Chevron and Navajo that no income tax allowance be recognized for the limited partnership interests held by SFPP's corporate parent, as well as SFPP's request that the tax allowance should include interests owned by certain non-corporate entities. However, it granted Navajo's request to make the computation of interest expense for tax allowance purposes the same as the computation for debt return.
Opinion No. 435-A reaffirmed that SFPP may recover certain litigation costs incurred in defense of its rates (amortized over five years), but reversed a ruling that those expenses may include the costs of certain civil litigation between SFPP and Navajo and El Paso. It also reversed a prior decision that litigation costs should be allocated between the East and West Lines based on throughput, and instead adopted SFPP's position that such expenses should be split equally between the two systems.
As to reparations, Opinion No. 435-A held that no reparations would be awarded to West Line shippers and that only Navajo was eligible to recover reparations on the East Line. It reaffirmed that a 1989 settlement with SFPP barred Navajo from obtaining reparations prior to November 23, 1993, but allowed Navajo reparations for a one-month period prior to the filing of its December 23, 1993 complaint. Opinion No. 435-A also confirmed that FERC's indexing methodology should be used in determining rates for reparations purposes and made certain clarifications sought by Navajo.
Opinion No. 435-A denied Chevron's request for modification of SFPP's prorationing policy. This policy requires customers to demonstrate a need for additional capacity if a shortage of available pipeline space exits.
Finally, Opinion No. 435-A directed SFPP to revise its initial compliance filings to reflect the modified rulings. It eliminated the refund obligation for the compliance tariff containing the Watson Station gathering enhancement charge, but required SFPP to pay refunds to the extent that the compliance tariff East Line rates are higher than the rates produced under Opinion No. 435-A.
In June 2000, several parties filed requests for rehearing of certain rulings made in Opinion No. 435-A. Chevron and RHC both sought reconsideration of the FERC's ruling that only Navajo is entitled to reparations for East Line shipments. SFPP sought rehearing of the FERC's:
- decision to require use of the December 1988 partnership capital structure for the period 1994-98 in computing the starting rate base;
- elimination of civil litigation costs;
- refusal to allow any recovery of civil litigation settlement payments; and
- failure to provide any allowance for regulatory expenses in prospective rates.
ARCO, Chevron, Navajo, RHC, Texaco and SFPP sought judicial review of Opinion No. 435-A in the United States Court of Appeals for the District of Columbia Circuit. The FERC moved to:
- consolidate those petitions with prior ARCO and RHC petitions to review Opinion No. 435;
- dismiss the Chevron, RHC and SFPP petitions; and
- hold the other petitions in abeyance pending ruling on the requests for rehearing of Opinion No. 435-A.
On July 17, 2000, SFPP submitted a compliance filing implementing the rulings made in Opinion No. 435-A, together with a calculation of reparations due to Navajo and refunds due to other East Line shippers. SFPP also filed a tariff containing East Line rates based on those rulings. On August 16, 2000, the FERC directed SFPP to supplement its compliance filing by providing certain underlying workpapers and information; SFPP responded to that order on August 31, 2000.
On September 19, 2000, the Court of Appeals dismissed Chevron's petition for lack of prosecution, and the court in an order issued January 19, 2001 denied a November 2, 2000 motion by Chevron for reconsideration of that dismissal. On October 20, 2000, the court dismissed the petitions for review filed by SFPP and RHC as premature in light of their pending requests for FERC rehearing, consolidated the ARCO, Navajo and Texaco petitions for review with the petitions for review of Opinion No. 435, and ordered that proceedings be held in abeyance until after FERC action on the rehearing requests.
Pursuant to the Court's orders, the FERC has filed quarterly reports regarding the status of the proceedings pending before the Commission. On May 14, 2001, ARCO filed an Answer and Protest to the
FERC's May 4, 2001 status report, requesting the Court of Appeals to reactivate the petitions for review that are being held in abeyance and to initiate a briefing schedule. On May 24, 2001, the FERC filed an opposition to that motion.
On July 6, 2001, ARCO, Chevron, Mobil, Navajo, RHC and Texaco filed a joint motion asking the FERC to expedite its action on their requests for rehearing, correction and clarification of Opinion No. 435-A and on SFPP's compliance filing and related protests. Ultramar filed a similar motion on July 10, 2001. On July 30, 2001, the Court of Appeals issued an order denying ARCO's motion without prejudice and directing the FERC to advise the Court in its next status report as to when the FERC expects to take final action with respect to the proceedings on rehearing. On August 2, 2001, the FERC filed a status report advising the Court that it intended to present the pending requests for rehearing of Opinion No. 435-A for consideration at the FERC's meeting scheduled for September 12, 2001.
On September 13, 2001, the FERC issued Opinion No. 435-B ("Opinion on Rehearing and Directing Revised Compliance Filing"), which ruled on pending requests for rehearing and comments on SFPP's compliance filing implementing Opinion No. 435-A. Based on those rulings, the FERC directed SFPP to submit a revised compliance filing, including revised tariffs and revised estimates of reparations and refunds, by November 12, 2001.
Opinion No. 435-B denied SFPP's requests for rehearing, which involved the capital structure to be used in computing starting rate base, SFPP's ability to recover litigation and settlement costs incurred in connection with the Navajo and El Paso civil litigation and the need for provision for regulatory costs in prospective rates. The decision also made modifications to the Commission's prior rulings on several other issues. In particular, Opinion No. 435-B reversed Opinion No. 435-A's ruling that Navajo was the sole party entitled to reparations, holding instead that Chevron, RHC, Tosco and Mobil are also eligible to recover reparations for East Line shipments. However, Opinion No. 435-B held that Ultramar is not eligible for reparations in the proceedings in which Opinions No. 435, 435-A and 435-B were issued.
The decision also changed prior FERC rulings permitting SFPP to apply certain litigation, environmental and pipeline rehabilitation costs that were not recovered through the prescribed rates to offset overearnings (and potential reparations) and to recover any such costs that remained by means of a surcharge to shippers. In Opinion No. 435-B, the FERC required SFPP to pay reparations to each complainant without any offset for unrecovered costs. It went on to require that SFPP subtract from the total 1995-1998 supplemental costs allowed under Opinion No. 435-A any overearnings that are not paid out as reparations, and allowed SFPP to recover any remaining costs from shippers by means of a five-year surcharge beginning on August 1, 2000. Opinion No. 435-B also ruled that SFPP would only be permitted to recover certain regulatory litigation costs through the surcharge and that the surcharge could not recover environmental or pipeline rehabilitation costs.
Opinion No. 435-B granted requests for late intervention as to the compliance filing review by Texaco, ARCO, Ultramar and Tosco; in addition, Navajo had made a timely intervention. On review, the FERC directed SFPP to make several changes in its revised compliance filing, including requiring SFPP to:
- use a remaining useful life of 16.8 years in amortizing its starting rate base, instead of the 20.6 year period previously used;
- remove the starting rate base component from its base rates as of August 1, 2001;
- amortize its accumulated deferred income tax balance beginning in 1992, rather than 1988;
- list the corporate unitholders that were the basis for the income tax allowance claimed in its compliance filing and certify that those companies are not Subchapter S corporations; and
- "clearly exclude" civil litigation costs from its compliance filing and explain how it has limited litigation costs to FERC-related expenses and assigned them to appropriate periods in making reparations calculations.
On October 15, 2001, Chevron and RHC filed petitions for rehearing of Opinion No. 435-B. Chevron's petition asks the FERC to clarify:
- the period for which Chevron is entitled to reparations; and
- whether East Line shippers that have received the benefit of Commission-prescribed rates for 1994 and subsequent years must show that there has been a substantial divergence between the cost of service and the change in the Commission's rate index in order to have standing to challenge SFPP rates for those years in pending or subsequent proceedings.
RHC's petition contends that Opinion No. 435-B erred, and should be modified on rehearing, to the extent it:
- suggests that a "substantial divergence" standard applies to complaint proceedings, subsequent to those that led to Opinion No. 435-B, challenging the total level of SFPP's East Line rates;
- requires a substantial divergence to be shown between SFPP's cost of service and the change in the FERC oil pipeline index in such subsequent complaint proceedings, rather than a substantial divergence between the cost of service and SFPP's revenues; and
- permits SFPP to recover 1993 rate case litigation expenses through a surcharge mechanism.
ARCO, Ultramar and SFPP filed petitions seeking judicial review of Opinion No. 435-B (and in SFPP's case, Opinion Nos. 435 and 435-A) in the U.S. Court of Appeals for the District of Columbia Circuit. The Court has consolidated the Ultramar and SFPP petitions with the consolidated cases that had been held in abeyance and has ordered that the consolidated cases be returned to its active docket. On October 24, 2001, the FERC filed a motion asking the court to consolidate ARCO's petition for review of Opinion No. 435-B as well and to hold the consolidated cases in abeyance pending FERC action on the Chevron and RHC petitions for rehearing.
On November 7, 2001, the FERC issued an order ruling on the Chevron and RHC petitions for rehearing of Opinion No. 435-B. The Commission held that Chevron's eligibility for reparations should be measured from August 3, 1993, rather than September 23, 1992, as Chevron had sought. The Commission also clarified its prior ruling with respect to the "substantial divergence" test, holding that in order to be considered on the merits, complaints challenging the SFPP rates set by applying the Commission's indexing regulations to the 1994 cost of service derived under the Opinion No. 435 series of orders must demonstrate a substantial divergence between the indexed rates and the pipeline's actual cost of service. Finally, the FERC granted rehearing to hold that SFPP's 1993 regulatory costs should not be included in the surcharge permitted for the recovery of supplemental costs.
On December 7, 2001, Chevron filed a petition for rehearing of the FERC's November 7, 2001 order. The petition requested the Commission to specify whether Chevron would be entitled to reparations for the two year period prior to the August 3, 1993 filing of its complaint.
On January 7, 2002, SFPP and RHC filed petitions in the U.S. Court of Appeals for the District of Columbia Circuit for review of the FERC's November 7, 2001 order. On January 8, 2002, the Court consolidated those petitions with the petitions for review of Opinion Nos. 435, 435-A and 435-B. On January 24, 2002, the Court of Appeals ordered the consolidated proceedings to be held in abeyance until the FERC acts on the pending request for rehearing of the November 7, 2001 order.
SFPP submitted its compliance filing and tariffs implementing Opinion No. 435-B and the Commission's November 7, 2001 order on November 20, 2001. Motions to intervene and protest were subsequently filed by ARCO, Mobil (which now submits filings under the name ExxonMobil), RHC, Navajo and Chevron, alleging that SFPP:
- should have calculated the supplemental cost surcharge differently;
- did not provide adequate information on the taxpaying status of its unitholders; and
- failed to estimate potential reparations for ARCO.
On December 10, 2001, SFPP filed a response to those claims, explaining that it had computed the surcharge consistent with the Commission's rulings, provided all unitholder tax status information requested by Opinion No. 435-B and calculated estimated reparations for all complainants for which the FERC had directed it to do so. On December 14, 2001, SFPP filed a revised compliance filing and new tariff correcting an error that had resulted in understating the proper surcharge and tariff rates.
On December 20, 2001, the FERC's Director of the Division of Tariffs and Rates Central issued two letter orders rejecting SFPP's November 20, 2001 and December 14, 2001 tariff filings because they were not made effective retroactive to August 1, 2000. On January 11, 2002, SFPP filed a request for rehearing of those orders by the Commission, on the ground that the FERC has no authority to require retroactive reductions to rates filed pursuant to its orders in complaint proceedings. On February 15, 2002, the FERC denied the motion for rehearing. SFPP is currently preparing a motion for reclarification of the order denying rehearing.
Motions to intervene and protest the December 14, 2001 corrected submission were filed by Navajo, ARCO and Mobil. Ultramar requested leave to file an out-of-time intervention and protest of both the November 20, 2001 and December 14, 2001 submissions. On January 14, 2002, SFPP responded to those filings to the extent they were not mooted by the orders rejecting the tariffs in question.
In December 1995, Texaco filed an additional FERC complaint, which involves the question of whether a tariff filing was required for movements on SFPP's Sepulveda Lines, which are upstream of its Watson, California station origin point, and, if so, whether those rates may be set in that proceeding and what those rates should be. Several other West Line shippers have filed similar complaints and/or motions to intervene in this proceeding, all of which have been consolidated into Docket Nos. OR96-2-000, et al. Hearings before an administrative law judge were held in December 1996 and the parties completed the filing of final post-hearing briefs in January 1997.
On March 28, 1997, the administrative law judge issued an initial decision holding that the movements on the Sepulveda Lines are not subject to FERC jurisdiction. On August 5, 1997, the FERC reversed that decision and found the Sepulveda Lines to be subject to the jurisdiction of the FERC. The FERC ordered SFPP to make a tariff filing within 60 days to establish an initial rate for these facilities. The FERC reserved decision on reparations until it ruled on the newly-filed rates. On October 6, 1997, SFPP filed a tariff establishing the initial interstate rate for movements on the Sepulveda Lines from Sepulveda Junction to Watson Station at the preexisting rate of five cents per barrel, along with supporting cost of service documentation. Subsequently, several shippers filed protests and motions to intervene at the FERC challenging that rate. On December 24, 1997, FERC denied SFPP's request for rehearing of the August 5, 1997 decision. On December 31, 1997, SFPP filed an application for market power determination, which, if granted, will enable it to charge market-based rates for this service. Several parties protested SFPP's application. On September 30, 1998, the FERC issued an order finding that, based on SFPP's application, SFPP lacks market power in the Watson Station destination market served by the Sepulveda Lines. The FERC found that SFPP appeared to lack market power in the origin market served by the Sepulveda Lines as well, but established a hearing to permit the protesting parties to substantiate allegations that SFPP possesses market power in the origin market. Hearings before a FERC administrative law judge on this limited issue were held in February 2000.
On December 21, 2000, the FERC administrative law judge issued his initial decision finding that SFPP possesses market power over the Sepulveda Lines origin market. SFPP and other parties have filed briefs opposing and supporting the initial decision with the FERC. The ultimate disposition of SFPP's market rate application is pending before the FERC.
Following the issuance of the initial decision in the Sepulveda case, the FERC judge indicated an intention to proceed to consideration of the justness and reasonableness of the existing rate for service on the Sepulveda Lines. SFPP sought clarification from FERC on the proper disposition of that issue in light of the pendency of its market rate application and prior deferral of consideration of SFPP's tariff filing. On February 22, 2001, the FERC granted SFPP's motion and deferred consideration of the pending complaints against the Sepulveda Lines rate until after its final disposition of SFPP's market rate application.
On October 22, 1997, ARCO, Mobil and Texaco filed another complaint at the FERC (Docket No. OR98-1-000) challenging the justness and reasonableness of all of SFPP's interstate rates. The complaint again challenges SFPP's East and West Line rates and raises many of the same issues, including a renewed challenge to the grandfathered status of West Line rates, that have been at issue in Docket Nos. OR92-8-000, et al. The complaint includes an assertion that the acquisition of SFPP and the cost savings anticipated to result from the acquisition constitute "substantially changed circumstances" that provide a basis for terminating the "grandfathered" status of SFPP's otherwise protected rates. The complaint also seeks to establish that SFPP's grandfathered interstate rates from the San Francisco Bay area to Reno, Nevada and from Portland to Eugene, Oregon are also subject to "substantially changed circumstances" and, therefore, are subject to challenge. In November 1997, Ultramar Diamond Shamrock Corporation filed a similar complaint at the FERC (Docket No. OR98-2-000, et al.). The shippers are seeking both reparations and prospective rate reductions for movements on all of the lines.
SFPP filed answers to both complaints, and on January 20, 1998, the FERC issued an order accepting the complaints and consolidating both complaints into one proceeding, but holding them in abeyance pending a FERC decision on review of the initial decision in Docket Nos. OR92-8-000, et al. In July 1998, some complainants amended their complaints to incorporate updated financial and operational data on SFPP. SFPP answered the amended complaints. In a companion order to Opinion No. 435, the FERC directed the complainants to amend their complaints, as may be appropriate, consistent with the terms and conditions of its orders, including Opinion No. 435. On January 10 and 11, 2000, the complainants again amended their complaints to incorporate further updated financial and operational data on SFPP. SFPP filed an answer to these amended complaints on February 15, 2000. On May 17, 2000, the FERC issued an order finding that the various complaining parties had alleged sufficient grounds for their complaints against SFPP's interstate rates to go forward to a hearing. At such hearing, the administrative law judge will assess whether any of the challenged rates that are grandfathered under the Energy Policy Act will continue to have such status and, if the grandfathered status of any rate is not upheld, whether the existing rate is just and reasonable.
A hearing in this new proceeding commenced in October 2001 and continues. An initial decision by the administrative law judge is expected in the latter half of 2002.
In August 2000, Navajo and RHC filed new complaints against SFPP's East Line rates and Ultramar filed an additional complaint updating its pre-existing challenges to SFPP's interstate pipeline rates. SFPP answered the complaints, and on September 22, 2000, the FERC issued an order accepting these new complaints and consolidating them with the ongoing proceeding in Docket No. OR96-2-000, et al.
The complainants have alleged a variety of grounds for finding "substantially changed circumstances," including the acquisition of SFPP and cost savings achieved subsequent to the acquisition. Applicable rules and regulations in this field are vague, relevant factual issues are complex and there is little precedent available regarding the factors to be considered or the method of analysis to be employed in making a determination of "substantially changed circumstances," which is the showing necessary to make "grandfathered" rates subject to challenge. Given the newness of the grandfathering standard under the Energy Policy Act and limited precedent, we cannot predict how these allegations will be viewed by the FERC.
If "substantially changed circumstances" are found, SFPP rates previously "grandfathered" under the Energy Policy Act may lose their "grandfathered" status. If these rates are found to be unjust and unreasonable, shippers may be entitled to a prospective rate reduction and a complainant may be entitled to reparations for periods from the date of its complaint to the date of the implementation of the new rates.
In June 2001, ARCO and others protested SFPP's adjustment to its interstate rates in compliance with the Commission's indexing regulations. Following submissions by the protestants and SFPP, the Commission issued an order in September 2001 dismissing the protests and finding that SFPP had complied with the Commission's indexing regulations.
We are not able to predict with certainty the final outcome of the FERC proceedings, should they be carried through to their conclusion, or whether we can reach a settlement with some or all of the complainants. Although it is possible that current or future proceedings could be resolved in a manner adverse to us, we believe that the resolution of such matters will not have a material adverse effect on our business, financial position or results of operations.
CALNEV PIPE LINE LLC
We acquired CALNEV Pipe Line LLC in March 2001. CALNEV provides interstate and intrastate transportation from an interconnection with SFPP at Colton, California to destinations in and around Las Vegas, Nevada. On June 1, 2001, CALNEV filed to adjust its interstate rates upward pursuant to the FERC's indexing regulations. ARCO, ExxonMobil, Ultramar Diamond Shamrock and Ultramar, Inc. protested this adjustment. On June 29, 2001, the FERC accepted and suspended the rate adjustment and permitted it to go into effect subject to refund. The FERC withheld ruling on the protests pending submission by CALNEV of its FERC Form No. 6 annual report and responses from the protestants to data contained therein. In September 2001, following submission by CALNEV of its Form No. 6 annual report and further submissions by ARCO and CALNEV, the Commission dismissed the protests, finding that CALNEV's rate adjustment comported with the Commission's indexing regulations.
In August 2001, ARCO filed a complaint against CALNEV's interstate rates alleging that they were unjust and unreasonable. Tosco and Ultramar filed interventions. In an October 15, 2001 order, the Commission set this claim for investigation and hearing. The matter has, however, first been referred to a settlement judge and such settlement process is currently ongoing. On November 14, 2001, CALNEV filed a motion for rehearing or, in the alternative, clarification of the Commission's October 15, 2001 order. CALNEV asserted that the Commission should have dismissed ARCO's complaint because it did not meet the standards of the Commission's regulations or, in the alternative, that the Commission should clarify the standards of pleading and proof applicable to ARCO's complaint.
On January 14, 2002 Tosco Corporation filed a complaint claiming that CALNEV's rates are unjust and unreasonable and asking that its complaint be consolidated with the ARCO complaints for hearing. Ultramar filed a similar complaint on January 18, 2002. CALNEV answered both of these complaints on February 4, 2002. At a settlement conference on January 17, 2002 the parties made substantial progress toward reaching a settlement. They have agreed to a "standstill" in the litigation while they attempt to reach a comprehensive written settlement. The settlement judge has indicated that he anticipates that the parties will be able to submit a settlement agreement to the Commission on or before April 30, 2002.
We are not able to predict with certainty the final outcome of this FERC proceeding, should it be carried through to its conclusion, or whether we can reach a settlement with the complainant. Although it is possible that current or future proceedings could be resolved in a manner adverse to us, we believe that the resolution of such matters will not have a material adverse effect on our business, financial position or results of operations.
California Public Utilities Commission Proceeding
ARCO, Mobil and Texaco filed a complaint against SFPP with the California Public Utilities Commission on April 7, 1997. The complaint challenges rates charged by SFPP for intrastate transportation of refined petroleum products through its pipeline system in the State of California and requests prospective rate adjustments. On October 1, 1997, the complainants filed testimony seeking prospective rate reductions aggregating approximately $15 million per year.
On August 6, 1998, the CPUC issued its decision dismissing the complainants' challenge to SFPP's intrastate rates. On June 24, 1999, the CPUC granted limited rehearing of its August 1998 decision for the purpose of addressing the proper ratemaking treatment for partnership tax expenses, the calculation of environmental costs and the public utility status of SFPP's Sepulveda Line and its Watson Station gathering enhancement facilities. In pursuing these rehearing issues, complainants seek prospective rate reductions aggregating approximately $10 million per year.
On March 16, 2000, SFPP filed an application with the CPUC seeking authority to justify its rates for intrastate transportation of refined petroleum products on competitive, market-based conditions rather than on traditional, cost-of-service analysis.
On April 10, 2000, ARCO and Mobil filed a new complaint with the CPUC asserting that SFPP's California intrastate rates are not just and reasonable based on a 1998 test year and requesting the CPUC to reduce SFPP's rates prospectively. The amount of the reduction in SFPP rates sought by the complainants is not discernible from the complaint.
The rehearing complaint was heard by the CPUC in October 2000 and the April 2000 complaint and SFPP's market-based application were heard by the CPUC in February 2001. All three matters stand submitted as of April 13, 2001, and a decision addressing the submitted matters is expected at any time.
We believe that the resolution of such matters will not have a material adverse effect on our business, financial position or results of operations.
SOUTHERN PACIFIC TRANSPORTATION COMPANY EASEMENTS
SFPP and Southern Pacific Transportation Company are engaged in a judicial reference proceeding to determine the extent, if any, to which the rent payable by SFPP for the use of pipeline easements on rights-of-way held by SPTC should be adjusted pursuant to existing contractual arrangements (Southern Pacific Transportation Company vs. Santa Fe Pacific Corporation, SFP Properties, Inc., Santa Fe Pacific Pipelines, Inc., SFPP, L.P., et al., Superior Court of the State of California for the County of San Francisco, filed August 31, 1994). Although SFPP received a favorable ruling from the trial court in May 1997, in September 1999, the California Court of Appeals remanded the case back to the trial court for further proceeding. SFPP is accruing amounts for payment of the rental for the subject rights-of-way consistent with our expectations of the ultimate outcome of the proceeding. We expect this matter to go to trial during the second quarter of 2002.
FERC ORDER 637
Kinder Morgan Interstate Gas Transmission LLC
On June 15, 2000, Kinder Morgan Interstate Gas Transmission LLC made its filing to comply with FERC's Orders 637 and 637-A. That filing contained KMIGT's compliance plan to implement the changes required by FERC dealing with the way business is conducted on interstate natural gas pipelines. All interstate natural gas pipelines were required to make such compliance filings, according to a schedule established by FERC. From October 2000 through June 2001, KMIGT held a series of technical and phone conferences to identify issues, obtain input, and modify its Order 637 compliance plan, based on comments received from FERC Staff and other interested parties and shippers. On June 19, 2001, KMIGT received a letter from FERC encouraging it to file revised pro-forma tariff sheets, which reflected the latest discussions and input from parties into its Order 637 compliance plan. KMIGT made such a revised Order 637 compliance filing on July 13, 2001. The July 13, 2001 filing contained little substantive change from the original pro-forma tariff sheets that KMIGT originally proposed on June 15, 2000. On October 19, 2001, KMIGT received an order from FERC, addressing its July 13, 2001 Order 637 compliance plan. In this Order addressing the July 13, 2001 compliance plan, KMIGT's plan was accepted, but KMIGT was directed to make several changes to its tariff, and in doing so, was directed that it could not place the revised tariff into effect until further order of the Commission. KMIGT filed its compliance filing with the October 19, 2001 Order on November 19, 2001 and also filed a request for rehearing/clarification of the FERC's October 19, 2001 Order on November 19, 2001. The November 19, 2001 Compliance filing has been protested by several parties. KMIGT filed responses to those protests on December 14, 2001. At this time, it is unknown when this proceeding will be finally resolved. KMIGT currently expects that it may not have a fully compliant Order 637 tariff approved and in effect until sometime in the first or second quarter of 2002. The full impact of implementation of Order 637 on the KMIGT system is under evaluation. We believe that these matters will not have a material adverse effect on our business, financial position or results of operations.
Separately, numerous petitioners, including KMIGT, have filed appeals of Order 637 in the D.C. Circuit, potentially raising a wide array of issues related to Order 637 compliance. Initial briefs were filed on April 6, 2001, addressing issues contested by industry participants. Oral arguments on the appeals were held before the courts in December 2001 and final action is pending.
Trailblazer Pipeline Company
On August 15, 2000, Trailblazer Pipeline Company made a filing to comply with FERC's Order Nos. 637 and 637-A. Trailblazer Pipeline Company's compliance filing reflected changes in:
- segmentation;
- scheduling for capacity release transactions;
- receipt and delivery point rights;
- treatment of system imbalances;
- operational flow orders;
- penalty revenue crediting; and
- right of first refusal language.
On October 15, 2001, FERC issued its order on Trailblazer Pipeline Company's Order No. 637 compliance filing. FERC approved Trailblazer Pipeline Company's proposed language regarding operational flow orders and the right of first refusal, but is requiring Trailblazer Pipeline Company to make changes to its tariff related to the other issues listed above. Most of the tariff provisions will have an effective date of January 1, 2002, with the exception of language related to scheduling and segmentation, which will become effective at a future date dependent on when KMIGT's Order No. 637 provisions go into effect. Trailblazer Pipeline Company anticipates no adverse impact on its business as a result of the implementation of Order No. 637.
On November 14, 2001, Trailblazer Pipeline Company made its compliance filing pursuant to the FERC order of October 15, 2001. That compliance filing has been protested. Separately, also on November 14, 2001, Trailblazer Pipeline Company filed for rehearing of that FERC order. These pleadings are pending FERC action.
STANDARDS OF CONDUCT RULEMAKING
On September 27, 2001, FERC issued a Notice of Proposed Rulemaking in Docket No. RM01-10 in which it proposed new rules governing the interaction between an interstate natural gas pipeline and its affiliates. If adopted as proposed, the Notice of Proposed Rulemaking could be read to limit communications between KMIGT, Trailblazer Pipeline Company and their respective affiliates. In addition, the Notice could be read to require separate staffing of KMIGT and its affiliates, and Trailblazer and its affiliates. Comments on the Notice of Proposed Rulemaking were due December 20, 2001. We believe that these matters, as finally adopted, will not have a material adverse effect on our business, financial position or results of operations.
CARBON DIOXIDE LITIGATION
Kinder Morgan CO(2) Company, L.P. directly or indirectly through its ownership interest in the Cortez Pipeline Company, along with other entities, is a defendant in several actions in which the plaintiffs allege that the defendants undervalued carbon dioxide produced from the McElmo Dome field and overcharged for transportation costs, thereby allegedly underpaying royalties and severance tax payments. The plaintiffs, who are seeking monetary damages and injunctive relief, are comprised of royalty, overriding royalty and small share working interest owners who claim that they were underpaid by the defendants. These cases are: CO(2) Claims Coalition, LLC v. Shell Oil Co., et al., No. 96-Z-2451 (U.S.D.C. Colo. filed 8/22/96); Rutter & Wilbanks et al. v. Shell Oil Co., et al., No. 00-Z-1854 (U.S.D.C. Colo. filed 9/22/00);
Watson v. Shell Oil Co., et al., No. 00-Z-1855 (U.S.D.C. Colo. filed 9/22/00); Ainsworth et al. v. Shell Oil Co., et al., No. 00-Z-1856 (U.S.D.C. Colo. file 9/22/00); United States ex rel. Crowley v. Shell Oil Company, et al., No. 00-Z-1220 (U.S.D.C. Colo. filed 6/13/00); Ptasynski et al. v. Shell Western E&P Inc., et al., No. 99-11049 (U.S. Ct. App. 5th Cir. filed 5/21/97 ); Shell Western E&P Inc. v. Bailey, et al., No. 98-28630 (215th Dist. Ct. Harris County, Tex. filed 6/17/98); Shores, et al. v. Mobil Oil Corporation, et al., No. GC-99-01184 (Texas Probate Court, Denton County filed 12/22/99); First State Bank of Denton v. Mobil Oil Corporation, et al., No. PR-8552-01 (Texas Probate Court, Denton County filed 3/29/01); and Celeste C. Grynberg v. Shell Oil Company, et al., No. 98-CV-43 (Colo. Dist. Ct. Montezuma County filed 3/21/98).
RSM Production Company et al. v. Kinder Morgan Energy Partners, L.P. et al.
Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial District. On October 15, 2001, Kinder Morgan Energy Partners, L.P. was served with the First Supplemental Petition filed by RSM Production Corporation on behalf of the County of Zapata, State of Texas and Zapata County Independent School District as plaintiffs. Kinder Morgan Energy Partners, L.P. was sued in addition to 15 other defendants, including two other Kinder Morgan affiliates. The Petition alleges that these taxing units relied on the reported volume and analyzed heating content of natural gas produced from the wells located within the appropriate taxing jurisdiction in order to properly assess the value of mineral interests in place. The suit further alleges that the defendants undermeasured the volume and heating content of that natural gas produced from privately owned wells in Zapata County, Texas. The Petition further alleges that the County and School District were deprived of ad valorem tax revenues as a result of the alleged undermeasurement of the natural gas by the defendants. Defendants have sought an extension of time to answer, and have not yet responded to the Petition. There are no further pretrial proceedings at this time.
Quinque Operating Company, et al. v. Gas Pipelines, et al.
Cause No. 99-1390-CM, United States District Court for the District of Kansas. This action was originally filed in Kansas state court in Stevens County, Kansas as a class action against approximately 245 pipeline companies and their affiliates, including certain Kinder Morgan entities. The plaintiffs in the case seek to have the Court certify the case as a class action. The plaintiffs are natural gas producers and fee royalty owners who allege that they have been subject to systematic mismeasurement of natural gas by the defendants for more than 25 years. Among other things, the plaintiffs allege a conspiracy among the pipeline industry to under-measure natural gas and have asserted joint and several liability against the defendants. Subsequently, one of the defendants removed the action to Kansas Federal District Court. Thereafter, we filed a motion with the Judicial Panel for Multidistrict Litigation to consolidate this action for pretrial purposes with the Grynberg False Claim Act, styled as United States of America, ex rel., Jack J. Grynberg v. K N Energy, Civil Action No. 97-D-1233, filed in the United States District Court, District of Colorado, because of common factual questions. On April 10, 2000, the Multidistrict Litigation Panel ordered that this case be consolidated with the Grynberg federal False Claims Act cases. On January 12, 2001, the Federal District Court of Wyoming issued an oral ruling remanding the case back to the State Court in Stevens County, Kansas. A case management conference recently occurred in State Court in Stevens County, and a briefing schedule was established for preliminary matters. Personal jurisdiction discovery has commenced. Merits discovery has not commenced.
Although no assurances can be given, we believe that we have meritorious defenses to all of these actions, that we have established an adequate reserve to cover potential liability, and that these matters will not have a material adverse effect on our business, financial position or results of operations.
ENVIRONMENTAL MATTERS
We are subject to environmental cleanup and enforcement actions from time to time. In particular, the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) generally imposes joint and several liability for cleanup and enforcement costs on current or predecessor owners and operators of a site, without regard to fault or the legality of the original conduct. Our
operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental regulations, risks of additional costs and liabilities are inherent in pipeline and terminal operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.
We are currently involved in the following governmental proceedings related to compliance with environmental regulations associated with our assets:
- one cleanup ordered by the United States Environmental Protection Agency related to ground water contamination in the vicinity of SFPP's storage facilities and truck loading terminal at Sparks, Nevada;
- several ground water hydrocarbon remediation efforts under administrative orders issued by the California Regional Water Quality Control Board and two other state agencies; and
- groundwater and soil remediation efforts under administrative orders issued by various regulatory agencies on those assets purchased from GATX Corporation, comprising Kinder Morgan Liquids Terminals LLC, CALNEV Pipe Line LLC and Central Florida Pipeline LLC.
In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, natural gas liquids, natural gas and carbon dioxide.
Review of assets related to Kinder Morgan Interstate Gas Transmission LLC includes the environmental impacts from petroleum and used oil releases to the soil and groundwater at nine sites. Additionally, review of assets related to Kinder Morgan Texas Pipeline includes the environmental impacts from petroleum releases to the soil and groundwater at six sites. Further delineation and remediation of these impacts will be conducted. Reserves have been established to address the closure of these issues.
On October 2, 2001, the jury rendered a verdict in the case of Walter Chandler v. Plantation Pipe Line Company. The jury awarded the plaintiffs a total of $43.8 million. The verdict was divided with the following award of damages:
- $0.3 million compensatory damages for property damage to the Evelyn Chandler Trust;
- $5 million compensatory damages to Walter (Buster) Chandler;
- $1.5 million compensatory damages to Clay Chandler; and
- $37 million punitive damages.
Plantation has filed post judgment motions and appeal of the verdict. The appeal of this case will be directly heard by the Alabama Supreme Court. It is anticipated that a decision by the Alabama Supreme Court will be received within the next twelve to eighteen months.
This case was filed in April 1997 by the landowner (Evelyn Chandler Trust) and two residents of the property (Buster Chandler and his son, Clay Chandler). The suit was filed against Chevron, Plantation and two individuals. The two individuals were later dismissed from the suit. Chevron settled with the plaintiffs in December 2000. The property and residences are directly across the street from the location of a former Chevron products terminal. The Plantation pipeline system traverses the Chevron terminal property. The suit alleges that gasoline released from the terminal and pipeline contaminated the groundwater under the plaintiffs' property. A current remediation effort is taking place between Chevron, Plantation and Alabama Department of Environmental Management.
Although no assurance can be given, we believe that the ultimate resolution of all these environmental matters set forth in this note will not have a material adverse effect on our business, financial position or
results of operations. We have recorded a total reserve for environmental claims in the amount of $75.8 million at December 31, 2001.
OTHER
We are a defendant in various lawsuits arising from the day-to-day operations of our businesses. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position or results of operations.
17. QUARTERLY FINANCIAL DATA (UNAUDITED)
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.
KINDER MORGAN ENERGY PARTNERS, L.P. (A Delaware Limited Partnership)
By: KINDER MORGAN G.P., INC., its General Partner
By: KINDER MORGAN MANAGEMENT, LLC, its Delegate
By: /s/ JOSEPH LISTENGART ---------------------------------- Joseph Listengart, Vice President, General Counsel and Secretary
Date: February 18, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.
INDEX TO EXHIBITS
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* Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith, except as noted otherwise.