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 2002.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity and Related Stockholder 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, the amount of cash distributions declared per common and Class B unit, and the fractional i-unit distribution declared per i-unit. All information has been adjusted to give effect to the two-for-one split of common units and i-units effective August 31, 2001.
Price Range
Cash i-unit High Low Distributio Distributions ------ ------ ------------------------ First Quarter $38.65 $28.60 $0.5900 0.016969 Second Quarter 36.55 30.98 0.6100 0.019596 Third Quarter 33.90 28.00 0.6100 0.020969 Fourth Quarter 35.45 30.15 0.6250 0.018815
First Quarter $31.73 $26.13 $0.5250 (1) Second Quarter 36.70 30.67 0.5250 0.014837 Third Quarter 37.08 30.75 0.5500 0.014738 Fourth Quarter 39.05 34.55 0.5500 0.014818 - ----------
(1)There was no i-unit distribution for the first quarter of 2001. We initially issued i-units in May 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 and i-unit 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 January 31, 2003, there were approximately 109,000 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.
(1)Represents income before extraordinary charge per unit adjusted for the two-for-one split of units 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) Excludes market value of interest rate swaps.
(4)Includes results of operations for the additional 10% interest in the Cochin Pipeline System, Kinder Morgan Materials Services LLC (formerly Laser Materials Services LLC), the 66 2/3% interest in International Marine Terminals, Tejas Gas,
LLC, Milwaukee Bagging Operations, the remaining 33 1/3% interest in Trailblazer Pipeline Company, the Owensboro Gateway Terminal and IC Terminal Holdings Company and Consolidated Subsidiaries since dates of acquisitions. The additional interest in Cochin was acquired on December 31, 2001. Kinder Morgan Materials Services LLC was acquired on January 1, 2002. We acquired a 33 1/3% interest in International Marine Terminals on January 1, 2002 and an additional 33 1/3% interest on February 1, 2002. Tejas Gas, LLC was acquired on January 31, 2002. The Milwaukee Bagging Operations were acquired on May 1, 2002. The remaining interest in Trailblazer was acquired on May 6, 2002. The Owensboro Gateway Terminal and IC Terminal Holdings Company and Subsidiaries were acquired on September 1, 2002.
(5)Includes results of operations for the remaining 50% interest in the Colton Processing Facility, Kinder Morgan Texas Pipeline, 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, Kinder Morgan Texas Pipeline, 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.
(6)Includes results of operations for Kinder Morgan Interstate Gas Transmission, 66 2/3% interest in Trailblazer, 49% interest in Red Cedar, Milwaukee Bulk Terminals, Dakota Bulk Terminal, remaining 80% interest in Kinder Morgan CO2 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. Kinder Morgan Interstate Gas Transmission, 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. The remaining 80% interest in Kinder Morgan CO2 Company, L.P. was acquired April 1, 2000. The Devon Energy carbon dioxide properties were acquired June 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.
(7)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.
(8)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. The Pacific operations' pipeline system was acquired March 6, 1998. 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 results of 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, specifically, in connection with Note 15 to our Consolidated Financial Statements, entitled "Reportable Segments".
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:
o the amounts we report for assets and liabilities;
o our disclosure of contingent assets and liabilities at the date of the financial statements; and
o 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, the fair values used to determine possible asset impairment charges, 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. In December 2002, after a thorough review of any potential environmental issues that could impact our assets or operations and of our need to correctly record all related environmental contingencies, we recognized a $0.3 million non-recurring reduction in environmental expense and in our overall accrued environmental liability, and we included this amount within Other, net in the accompanying Consolidated Statement of Income for 2002. The $0.3 million income item resulted from the necessity of properly adjusting and realigning our environmental expenses and accrued liabilities between our reportable business segments, specifically between our Products Pipelines and our Terminals business segments. The $0.3 million reduction in environmental expense resulted in a $15.7 million non-recurring loss to our Products Pipelines business segment and a $16.0 million non-recurring gain to our Terminals business segment.
With respect to legal proceedings, we are subject to litigation and regulatory proceedings 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 orders, 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. In general, we expense legal costs as incurred. When we identify specific litigation that is expected to continue for a
significant period of time and require substantial expenditures, we identify a range of possible costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement. If no amount within this range is a better estimate than any other amount, we record a liability equal to the low end of the range. Any such liability recorded is revised as better information becomes available.
In addition, effective January 1, 2002, we adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets". SFAS No. 142 eliminates the amortization of goodwill, requires annual impairment testing of goodwill and introduces the concept of indefinite life intangible assets. The new rules also prohibit the amortization of goodwill associated with business combinations that close after June 30, 2001.
These new requirements will impact future period net income by an amount equal to the discontinued goodwill amortization offset by goodwill impairment charges, if any, and adjusted for any differences between the old and new rules for defining intangible assets on future business combinations. An initial impairment test was required in 2002 as of January 1, 2002. We completed this initial transition impairment test in June 2002 and determined that our goodwill was not impaired as of January 1, 2002.
Finally, regarding our pension disclosures, we are required to make assumptions and estimates regarding the accuracy of our pension investment returns. Specifically, these include:
o our investment return assumptions;
o the significant estimates on which those assumptions are based; and
o the potential impact that changes in those assumptions could have on our reported results of operations and cash flows.
We consider our overall pension liability exposure to be minimal in relation to the value of our total consolidated assets and net income. However, in accordance with SFAS No. 87, "Employers' Accounting for Pensions", a component of our net periodic pension cost includes the return on pension plan assets, including both realized and unrealized changes in the fair market value of pension plan assets.
A source of volatility in pension costs comes from this inclusion of unrealized or market value gains and losses on pension assets as part of the components recognized as pension expense. To prevent wide swings in pension expense from occurring because of one-time changes in fund values, SFAS No. 87 allows for the use of an actuarial computed "expected value" of plan asset gains or losses to be the actual element included in the determination of pension expense. The actuarial derived expected return on pension assets not only employs an expected rate of return on plan assets, but also assumes a market-related value of plan assets, which is a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. As required, we disclose the weighted average expected long-run rate of return on our plan assets, which is used to calculate our plan assets' expected return. For more information on our pension disclosures, see Note 10 to our Consolidated Financial Statements, included elsewhere in this report.
Results of Operations
In 2002, we managed to again achieve record levels of revenues, operating income, net income and earnings per unit. The fiscal year ended December 31, 2002 marked the fifth successive year that we have improved on all four of these operating measures since the change in control of our general partner in February 1997. We owe our success primarily to the continuing execution of the same strategy adopted by management in 1997:
o providing, for a fee, transportation, storage and handling services which are core to the energy infrastructure of growing markets;
o increasing utilization of assets while containing costs;
o leveraging economies of scale from incremental acquisitions and expansions; and
o maximizing the benefits of our financial structure.
In 2002, our net income was $608.4 million ($1.96 per diluted unit) on revenues of $4,237.1 million, compared to net income of $442.3 million ($1.56 per diluted unit) on revenues of $2,946.7 million in 2001, and net income of $278.3 million ($1.34 per diluted unit) on revenues of $816.4 million in 2000.
Our total consolidated operating income was $724.3 million in 2002, $563.8 million in 2001 and $315.6 million in 2000. Operating expenses, excluding depreciation, depletion and amortization, general and administrative expenses and taxes, other than income taxes, were $3,170.5 million in 2002, compared with $2,087.5 million in 2001 and $332.2 million in 2000.
The increases in overall revenues, expenses and net income in 2002 compared to 2001 were attributable to both solid internal growth and contributions from acquired assets, especially from our acquisition of Kinder Morgan Tejas, formerly Tejas Gas, LLC, on January 31, 2002. Each of our four business segments reported increased earnings in 2002 over 2001. The increases in overall revenues, expenses and income in 2001 compared to 2000 resulted mainly 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. In addition, in 2001, just as in 2002, each business segment reported increased earnings over the prior year.
Equity earnings, from our investments accounted for under the equity method of accounting, were $83.7 million in 2002, $75.8 million in 2001 and $63.4 million in 2000. These amounts represent equity earnings net of expense from allowable amortization of excess investment costs. Additionally, we declared a record cash distribution of $0.625 per unit for the fourth quarter of 2002 (an annualized rate of $2.50). Our distribution for the fourth quarter of 2002 was 14% higher than the $0.55 per unit distribution we made for the fourth quarter of 2001, and 32% higher than the $0.475 per unit distribution we made for the fourth quarter of 2000.
Products Pipelines
Our Products Pipelines segment reported earnings of $343.9 million on revenues of $576.5 million in 2002. This compared to earnings of $312.5 million on revenues of $605.4 million in 2001 and earnings of $222.7 million on revenues of $420.3 million in 2000. Operating expenses, excluding depreciation and taxes, other than income taxes, were $151.1 million, $222.5 million and $172.4 million for each of the three years ended December 31, 2002, 2001 and 2000, respectively. The $31.4 million (10%) overall increase in segment earnings in 2002 over 2001 includes the $15.7 million non-recurring loss from the adjustment and realignment of our environmental liabilities referred to above in our "Critical Accounting Policies and Estimates". Excluding the non-recurring environmental loss, segment earnings were $359.6 million in 2002. The increase in segment earnings in 2002 over the prior year was primarily related to the strong year-to-year results reported from our CALNEV pipeline operations, our 44.8% ownership interest in the Cochin Pipeline system and our Pacific operations.
The year-to-year $28.9 million (5%) decrease in segment revenues and the $71.4 million (32%) decrease in segment expenses, include reductions of $67.8 million in transmix revenues and $68.6 million in transmix expenses, both resulting from our long-term transmix processing agreement with Duke Energy Merchants. 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.
Partially offsetting the overall decrease in segment revenues was a $14.7 million increase in revenues earned from our CALNEV Pipeline, the result of an almost 2% increase in average pipeline tariff rates in 2002 and the inclusion, in 2002, of a full year of operations versus nine months in 2001. Our proportionate share of revenues from the Cochin Pipeline system increased $12.0 million in 2002 compared to 2001, the increase resulting from higher volumes and tariffs as well as our additional ownership interest. Our Pacific operations reported a $10.6 million (4%) increase in revenues in 2002 compared to 2001. Although mainline delivery volumes remained flat in 2002, compared to the prior year, overall revenues were higher due to a 2% increase in average pipeline tariff rates and higher non-transportation revenues.
For all products pipelines owned or operated at both December 31, 2002 and 2001, total throughput delivery of refined petroleum products, consisting of gasoline, diesel fuel and jet fuel, was up 1.2% in 2002 over 2001. Gasoline delivery volumes were up 4.5% in 2002, compared to 2.6% nationally. Although our total jet fuel delivery volumes were down 3.8% for 2002, reflecting the effects of the September 11, 2001 terrorist attacks, deliveries of jet fuel improved steadily throughout the year.
Excluding the $68.6 million decrease in our transmix cost of sales expense referred to above, the segment's overall expenses remained relatively flat during 2002. Excluding depreciation and taxes, other than income taxes, expenses related to Cochin increased a slight $1.7 million, due to the increase in delivery volumes and our additional ownership interest.
The $89.8 million (40%) increase in segment earnings in 2001 compared to 2000 was mainly attributable to acquisitions we made since December 2000 and to cost savings resulting from our assumption of the operating duties of Plantation Pipe Line Company on December 21, 2000. The $185.1 million (44%) increase in revenues for 2001 compared to 2000 was primarily the result of an incremental $158.5 million in revenues from acquisitions made since the fourth quarter of 2000, $39.4 million in operating reimbursements from Plantation, and a $21.0 million (8%) improvement in our Pacific operations' revenues, primarily resulting from 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 in 2001 include:
o Kinder Morgan Transmix Company, LLC;
o the remaining 50% interest in the Colton Transmix Processing Facility;
o 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
o assets acquired from GATX Corporation, consisting of Central Florida Pipeline LLC, CALNEV Pipe Line LLC and petroleum product and chemical terminals.
The segment's overall increase in revenues was partially offset by a $33.8 million decrease in transmix revenues, the result of entering into our long-term transmix processing agreement with Duke Energy Merchants during the first quarter of 2001, as referred to above. The $50.1 million (29%) increase in expenses, excluding depreciation and taxes, other than income taxes, for our Products Pipelines segment in 2001 compared to 2000, resulted primarily from our acquisitions, costs incurred under our operations agreement with Plantation and higher fuel and power expenses on our Pacific operations' pipelines. This increase was partially offset by a reduction in transmix expenses due to our agreement with Duke Energy Merchants.
Operating income for each of the three years ended December 31, 2002, 2001 and 2000 was $342.4 million, $299.0 million and $195.1 million, respectively. Earnings from our Products Pipelines' equity investments, net of amortization of excess costs, were $25.7 million in 2002, $22.7 million in 2001 and $29.1 million in 2000. The $3.0 million (13%) increase in net equity earnings in 2002 versus 2001 was due to a $2.3 million decrease in expenses from the amortization of excess investment costs and a $0.7 million increase in equity earnings, both related to our 51% ownership interest in Plantation Pipe Line Company. Effective January 1, 2002, we adopted Statement of Financial Accounting Standards No. 142 "Goodwill and Other Intangible Assets" and ceased amortizing the amount of our equity investment costs that exceeded the underlying fair value of net assets. The increase in our proportionate share of Plantation's earnings in 2002 resulted from Plantation's higher revenues and lower operating and interest expenses. The higher revenues resulted from record delivery volumes, the lower operating expenses resulted from lower power costs and the lower interest expenses resulted from lower average borrowing rates. The $6.4 million (22%) 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 to 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.
SFPP, L.P. is the subsidiary limited partnership that owns our Pacific operations, excluding CALNEV Pipe Line LLC and related terminals acquired from GATX Corporation. Tariffs charged by SFPP are subject to certain proceedings at the Federal Energy Regulatory Commission 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. Generally, the interstate rates on our Pacific operations' pipeline systems are "grandfathered" under the Energy Policy Act of 1992 unless "substantially changed circumstances" are found to exist. To the extent "substantially changed circumstances" are found to exist, our Pacific operations may be subject to substantial exposure under these FERC complaints. We currently believe that these FERC complaints seek approximately $197 million in tariff reparations and prospective annual tariff reductions, the aggregate average annual impact of which would be approximately $45 million. However, even if "substantially changed circumstances" are found to exist, we believe that the resolution of these FERC complaints will be for amounts substantially less than the amounts sought.
Natural Gas Pipelines
Our Natural Gas Pipelines segment reported earnings of $276.8 million on revenues of $3,086.2 million in 2002. In 2001, the segment reported earnings of $193.8 million on revenues of $1,869.3 million, and in 2000, reported earnings of $113.1 million on revenues of $174.2 million. Expenses, excluding depreciation charges and taxes, other than income taxes, were $2,770.6 million, $1,656.1 million and $51.3 million for each of the three years ended December 31, 2002, 2001 and 2000, respectively. The segment's significant $83.0 million (43%) increase in year-to-year earnings and its $1,216.9 million (65%) increase in year-to-year revenues in 2002 versus 2001 relate primarily to our January 31, 2002 acquisition of Kinder Morgan Tejas. Kinder Morgan Tejas' operations include a 3,400-mile intrastate natural gas pipeline system that has good access to natural gas supply basins in Texas. The acquisition and subsequent integration of its assets with our pre-existing natural gas pipeline assets in the State of Texas, particularly our Kinder Morgan Texas Pipeline system, has produced a strategic and complementary intrastate pipeline business combination.
Both Kinder Morgan Tejas and KMTP, which together comprise our Texas intrastate natural gas group, purchase and sell significant volumes of natural gas, which is transported through their pipeline systems. Our objective is to match every purchase and sale, thus locking-in the equivalent of a transportation fee. The purchase and sale activity results in considerably higher revenues and operating expenses compared to the interstate natural gas pipeline systems of Kinder Morgan Interstate Gas Transmission and Trailblazer Pipeline Company, which we acquired on December 31, 1999 from KMI. Both KMIGT and Trailblazer charge a transportation fee for gas transmission service but neither system has significant gas purchases and resales.
Together, in 2002, the combination of our two intrastate natural gas pipeline systems earned $117.5 million, generated revenues of $2,830.0 million and incurred $2,679.3 million in expenses, excluding depreciation and taxes, other than income taxes. In 2001, KMTP alone had $48.0 million in earnings, $1,599.3 million in revenues and $1,537.3 million in expenses. Year-over-year operating results from our Trailblazer Pipeline Company also contributed to the segment's increase in earnings and revenues in 2002. In May 2002, we completed a $59 million expansion project that increased transportation capacity on the pipeline by approximately 60%. As a result, Trailblazer realized a 24% increase in natural gas transportation volumes in 2002 compared to 2001. The overall increase in segment revenues in 2002 compared to 2001 was partially offset by a $28.2 million decrease in revenues earned by our Casper and Douglas natural gas gathering and processing system, and by a $16.0 million decrease in revenues earned by KMIGT. Casper and Douglas' revenue decrease was primarily related to a general decline in natural gas prices in and around the Rocky Mountain region since the end of the third quarter of 2001, and KMIGT's revenue decrease was mainly the result of lower operational gas sales and lower fuel recovery rates in 2002.
The $1,114.5 million (67%) increase in segment expenses, excluding depreciation and taxes, other than income taxes, in 2002 over 2001 was mainly due to our Kinder Morgan Tejas acquisition, but the overall increase was partially offset by a $26.8 million decrease in expenses incurred by Casper and Douglas, related to the decrease in natural gas prices.
The segment's $80.7 million (71%) increase and $1,695.1 million increase in year-to-year earnings and revenues in 2001 over 2000 relate primarily to the inclusion of assets that we acquired from KMI on December 31, 2000, and
to a strong performance from our pre-existing assets.
Effective on December 31, 2000, we acquired from KMI:
o Kinder Morgan Texas Pipeline, L.P.;
o our Casper and Douglas natural gas gathering and processing systems;
o a 50% interest in Coyote Gas Treating, LLC; and
o a 25% interest in Thunder Creek Gas Services, LLC.
Combined, KMTP and the Casper and Douglas systems earned $64.6 million, produced operating revenues of $1,688.6 million and incurred expenses, excluding depreciation and taxes, other than income taxes, of $1,608.0 million in 2001. The segment's overall increase in revenues in 2001 over 2000 also resulted from a $9.2 million (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 expenses was partially offset by lower expenses on the Trailblazer Pipeline, primarily the result of favorable system imbalance settlements.
Operating income for each of the three years ended December 31, 2002, 2001 and 2000 was $253.5 million, $171.9 million and $97.3 million, respectively. We account for the segment's investments in Red Cedar Gas Gathering Company, Coyote Gas Treating, LLC and Thunder Creek Gas Services, LLC under the equity method of accounting. Earnings from these equity investments, net of amortization of excess costs, were $23.6 million in 2002, $21.2 million in 2001 and $15.0 million in 2000. The $2.4 million (11%) increase in 2002 over 2001 resulted primarily from a $1.1 million increase in earnings from our 49% interest in Red Cedar, mainly due to a $0.9 million decrease in amortization of excess investment costs related to our adoption of SFAS No. 142. The $6.2 million (41%) increase in 2001 over 2000 resulted from the inclusion of $3.5 million of net equity earnings from our investments in Coyote and Thunder Creek and a $2.7 million increase in earnings from our investment in Red Cedar, primarily the result of higher revenues from custom compression projects.
CO2 Pipelines
Our CO2 Pipelines segment consists of Kinder Morgan CO2 Company, L.P. and its consolidated affiliates. In 2002, our CO2 Pipelines segment reported earnings of $101.0 million on revenues of $146.3 million. This compared to earnings of $92.1 million on revenues of $122.1 million in 2001. Expenses, excluding depreciation, depletion, amortization, and taxes, other than income taxes, totaled $42.7 million in 2002 versus $37.4 million in 2001. The $8.9 million (10%) increase in year-to-year earnings was primarily attributable to the $24.2 million (20%) increase in revenues, partially offset by higher depreciation, depletion and operating expenses. The increase in revenues was driven by higher oil production volumes produced at the segment's SACROC Unit, as well as higher carbon dioxide pipeline delivery volumes. Oil production at SACROC, located in the Permian Basin of West Texas, increased 43% in 2002 compared to 2001. Delivery volumes of carbon dioxide, including deliveries on our Central Basin Pipeline and our majority-owned Canyon Reef Carriers Pipeline increased 37% in 2002. Offsetting the revenue increase was an $11.6 million (66%) increase in non-cash depreciation and depletion charges and a $5.3 million (14%) increase in operating and maintenance expenses, both of which related to the higher oil production volumes. Depreciation and depletion charges were also up in 2002 compared to 2001, primarily as a result of the capital expenditures we made since the end of 2001 and a change to a higher unit-of-production depletion rate on January 1, 2002.
The segment reported operating income of $66.6 million in 2002 and $59.6 million in 2001. Earnings from equity investments, net of amortization of excess costs, were $34.3 million in 2002, compared to $32.0 million in 2001. The $2.3 million (7%) increase resulted from higher earnings from the segment's 50% ownership interest in Cortez Pipeline Company, mainly due to lower average debt balances and lower average borrowing rates, partially offset by slightly lower carbon dioxide delivery volumes.
Prior to April 1, 2000, we owned 20% of Kinder Morgan CO2 Company, L.P., formerly Shell CO2 Company, L.P., and we accounted for our investment under the equity method of accounting. After our acquisition of the remaining 80% ownership interest on April 1, 2000, we included the company's financial results in our consolidated
financial statements. Therefore, the segment's 2000 results consist primarily of:
o one quarter of equity earnings from our original 20% interest in Kinder Morgan CO2 Company, L.P.;
o nine months of operations from pre-existing assets owned by the partnership, including its 50% ownership interest in Cortez Pipeline Company; and
o seven months of operations from significant carbon dioxide pipeline assets and oil-producing property interests that were acquired from Devon Energy on June 1, 2000.
For the year 2000, our CO2 Pipelines segment reported $68.1 million of earnings, $26.8 million of expenses, excluding depreciation, depletion, amortization and taxes, other than income taxes, and $89.2 million of revenues. Operating income totaled $48.1 million and equity earnings, net of amortization of excess costs, totaled $19.3 million, representing the $3.6 million from our 20% interest in Kinder Morgan CO2 Company, L.P. and $15.7 million from the segment's interest in Cortez Pipeline Company.
Terminals
Our Terminals segment includes the business portfolio of approximately 50 terminals that transload and store coal, dry-bulk materials and petrochemical-related liquids, as well as more than 60 transload operations in 20 states. The segment reported earnings of $191.6 million on revenues of $428.0 million in 2002. This compared to earnings of $136.2 million on revenues of $349.9 million in 2001 and earnings of $40.2 million on revenues of $132.8 million in 2000. Expenses, excluding depreciation and taxes, other than income taxes, for each of the three years ended December 31, 2002, 2001 and 2000, were $206.1 million, $171.5 million and $81.7 million, respectively. Operating income for each of the three years ended December 31, 2002, 2001 and 2000 was $180.7 million, $142.7 million and $39.5 million, respectively. The $55.4 million (41%) increase in segment earnings in 2002 over 2001 includes the $16.0 million non-recurring gain from the adjustment and realignment of our environmental liabilities referred to above in our "Critical Accounting Policies and Estimates".
Excluding the non-recurring environmental item mentioned in the immediately preceding paragraph, segment earnings totaled $175.6 million in 2002. Most of the growth in segment earnings and revenues in 2002 compared to 2001 was driven by the acquisitions and asset purchases that we have made since the last half of 2001, as well as internal growth. These investments accounted for $25.1 million of segment earnings growth in 2002. Internal growth at existing facilities, primarily driven by expansion projects at various terminals, accounted for $14.3 million of segment earnings growth in 2002 over 2001.
Our acquisitions and additions included:
o the terminal businesses we acquired from Koninklijke Vopak N.V., effective July 10, 2001;
o the terminal businesses we acquired from The Boswell Oil Company, effective August 31, 2001;
o the terminal businesses we acquired from an affiliate of Stolt-Nielsen, Inc. in November 2001;
o Kinder Morgan Materials Services LLC, formerly Laser Materials Services LLC, acquired effective January 1, 2002;
o a 66 2/3% interest in International Marine Terminals Partnership (a 33 1/3% interest acquired effective January 1, 2002 and an additional 33 1/3% interest acquired effective February 1, 2002);
o the Milwaukee Bagging Operations, acquired effective May 1, 2002;
o the Owensboro Gateway Terminal, acquired effective September 1, 2002;
o the St. Gabriel Terminal, acquired effective September 1, 2002; and
o the purchase of four floating cranes at our bulk terminal facility in Port Sulphur, Louisiana in December 2002.
In 2002 compared to 2001, the acquisitions listed above accounted for incremental amounts of $25.1 million in earnings, $88.5 million in revenues and $56.4 million in expenses, excluding depreciation and taxes, other than income taxes. Expansion projects undertaken during 2002 at our Carteret Terminal in New York Harbor and at our Pasadena Terminal on the Houston, Texas Ship Channel contributed to an almost 4% increase in the segment's leaseable capacity of liquids products. In addition, while adding the incremental capacity during 2002, we maintained a strong liquids capacity utilization rate of 97%, the same level reached in 2001. Declines in engineering services and in the volume of transloaded bulk products partially offset the overall increases in segment earnings and revenues in 2002. Including all bulk terminals owned at December 31, 2002, transloading of bulk tonnage decreased 6% in 2002 compared to 2001. The decline was primarily due to lower terminal transfers of petroleum coke, salt tonnage and other dry-bulk materials. Volumes of coal handled at our bulk terminals are expected to continue to decline in 2003 due to the fact that we will no longer operate the LAXT Coal Terminal after the first quarter of 2003 and to the opening of competing terminals during 2003 in the geographic regions served by our Cora and Grand Rivers coal terminals. Volumes at Cora and Grand Rivers are expected to decline by approximately 4 million tons in 2003.
Comparing 2001 to 2000, the year-to-year increases in our Terminals' revenues, expenses and earnings were driven principally by the strategic acquisitions we have made since the end of 2000.
In addition to the investments listed above, these acquisitions include:
o Delta Terminal Services LLC, acquired effective December 1, 2000;
o Kinder Morgan Liquids Terminals LLC, acquired from GATX Corporation effective January 1, 2001; and
o Pinney Dock & Transport LLC, acquired effective March 1, 2001.
In 2001 compared to 2000, the acquisitions and investments we made since the end of 2000 accounted for incremental amounts of $101.6 million in earnings, $203.6 million in revenues and $79.4 million in expenses, excluding depreciation and taxes, other than income taxes. On an aggregate basis, bulk tonnage transfer volumes, including coal and all other bulk materials, increased 22% in 2001 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. The increase in 2001 expenses over 2000 was the result of acquisitions made in 2001 and higher maintenance and operating expenses associated with the transfer of higher volumes.
Other
Items not attributable to any segment include general and administrative expenses, interest income and expense and minority interest. General and administrative expenses totaled $118.9 million in 2002, compared to $109.3 million in 2001 and $64.4 million in 2000. The $9.6 million (9%) increase in general and administrative expenses in 2002 compared to the prior year was primarily due to additional employee benefit, compensation and reimbursement charges, higher insurance related expenses and administrative expenses related to our Kinder Morgan Tejas acquisition. The year-to-year increase in our general and administrative expenses in 2001 compared to 2000 was 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. 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 $176.5 million in 2002, $171.5 million in 2001 and $93.3 million in 2000. The slight $5.0 million (3%) increase in net interest items in 2002 compared to 2001 reflects higher average borrowings during 2002 due to our acquisition and expansion projects. The change in net financing charges was partially offset by a decrease in average borrowing rates that have occurred since the end of 2001. In 2002, we issued $1.5 billion in principal amount of senior notes and we retired a maturing amount of $200 million in principal amount of senior notes. In March 2001, we closed a public offering of $1.0 billion in principal amount of senior
notes. 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.
Minority interest, which includes the 1.0101% general partner interest in our five operating limited partnerships, totaled $9.6 million in 2002, compared to $11.4 million in 2001 and $8.0 million in 2000. The $1.8 million (16%) decrease in 2002 from 2001 resulted primarily from our acquisition of an additional ownership interest in Trailblazer Pipeline Company. In May 2002, we acquired the remaining 33 1/3% ownership interest in Trailblazer that we did not already own, thereby eliminating the minority interest relating to Trailblazer Pipeline Company. The $3.4 million (43%) increase in minority interest 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.
Outlook
We actively pursue a strategy to increase our operating income. We will use a three-pronged approach to accomplish this goal.
o 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 or have assumed operations of since February 1997, including our Pacific operations, Plantation Pipe Line Company, the businesses we acquired from GATX Corporation and Kinder Morgan Tejas. 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.
o Internal Growth. We intend to grow income from our current assets through (a) increased utilization, and (b) internal expansion projects. We operate classic fixed cost businesses with little variable costs. By controlling these variable costs, any increase in utilization of our pipelines and terminals generally results in an increase in income. Increases in utilization are principally driven by increases in demand for gasoline, jet fuel, natural gas and other energy products that we transport and/or handle. Increases in demand for these products are typically driven by demographic growth in markets we serve, including the rapidly growing western and southeastern United States. In addition, we have undertaken a number of expansion projects that management believes will also increase revenues from existing operations, including the following:
o a $223 million investment project to expand our carbon dioxide business. The project includes the construction of the new $40 million Centerline Pipeline that will originate near Denver City, Texas, and transport carbon dioxide to the Snyder, Texas area. The pipeline will consist of 113 miles of 16-inch pipe and will primarily supply the SACROC Unit in the Permian Basin of West Texas, but will also be available for existing and prospective third-party carbon dioxide projects in the Horseshoe Atoll area of the Permian Basin. Construction is expected to be completed by mid-2003. The project also includes the spending of approximately $120 million to add additional infrastructure, including wells, injection and compression facilities, to support the expanding carbon dioxide flooding operations at the SACROC Unit. Based on positive response, by the end of 2002, we committed an additional $63 million to develop SACROC. These expenditures are expected to quadruple carbon dioxide deliveries to the SACROC Unit and triple oil production when compared to 2001 levels of 80 million cubic feet per day of carbon dioxide and 9,000 barrels per day of crude oil;
o a $59 million expansion project on the Trailblazer pipeline. The expansion project began in August 2001 and was completed in May 2002. The expansion project increased transportation capacity on the pipeline by 60% to 846,000 dekatherms per day of natural gas, and the increase has already been fully subscribed by customers. The project included installing two new compressor stations and adding 10,000 additional horsepower at an existing compressor station;
o a $41.5 million investment in our growing terminals business. The investment includes storage expansion and upgrade projects at our liquids terminals located in Carteret, New Jersey, Pasadena, Texas and Dravosburg, Pennsylvania. The major expansion work is taking place at Carteret and Pasadena, and will follow the expansions that were initiated there in 2001. At Carteret, in the New York Harbor area, this expansion project will add an additional 400,000 barrels of petroleum storage capacity and will include the construction of a new 16-inch pipeline that will connect to the Buckeye Pipeline system, a major products pipeline serving the East Coast. The expansion work at our Carteret terminal is expected to be completed in the third quarter of 2003. At Pasadena, on the Houston Ship Channel, the expansion project will increase storage capacity by another 300,000 barrels of petroleum products and is expected to be completed in the second quarter of 2003;
o a $30 million investment project that involves the construction of pipeline, compression and storage facilities to accommodate an additional 6 billion cubic feet of natural gas storage capacity on Kinder Morgan Interstate Gas Transmission LLC's Cheyenne Market Center. The additional service has been fully subscribed under 10-year contracts. The Cheyenne Market Center is a new service offering firm natural gas storage capabilities that will allow for the receipt, storage and subsequent re-delivery of natural gas supplies at applicable points located in the vicinity of the Cheyenne Hub in Weld County, Colorado and our Huntsman storage facility in Cheyenne County, Nebraska. The Cheyenne Market Center is expected to begin service during the summer of 2004;
o a $116 million project to expand the capacity on a 190-mile segment of the Plantation Pipe Line system. The project will entail replacing an existing eight-inch pipeline between Bremen, Georgia and Knoxville, Tennessee with a new 20-inch pipeline. The expansion will double capacity on the segment of the pipeline to approximately 90,000 barrels per day of refined petroleum products. Construction will be initiated only after additional commitments from interested shippers are obtained;
o a $10.7 million investment in a storage expansion project at our liquids terminal located in Perth Amboy, New Jersey. The expansion includes the construction of an additional 300,000 barrels of storage and increases the petroleum capacity at the facility by more than 20%. The expansion accommodates a long-term storage agreement that we entered into with a petroleum customer for storage services in the New York Harbor area. We expect to complete this expansion project by the end of 2003;
o a $16.4 million investment in expansion projects at existing bulk terminal facilities in 2002. The investments include the purchase of four barge-mounted crane units from Stevedoring Services of America for use at our International Marine Terminal located in Port Sulphur, Louisiana, new storage facilities at several bulk terminal sites and continued marine improvements at our Shipyard River Terminal located in Charleston, South Carolina; and
o an $87 million investment project that involves the construction of the 95-mile, 30-inch Mier-Monterrey natural gas pipeline that stretches from South Texas to Monterrey, Mexico, one of Mexico's fastest growing industrial areas. The new pipeline will interconnect with the southern end of the Kinder Morgan Texas Pipeline system in Starr County, Texas, and is designed to initially transport up to 375,000 dekatherms per day of natural gas. We have entered into 15-year contract with Pemex Gas Y Petroquimica Basica, which has subscribed all of the pipeline's capacity. The pipeline will connect to a 1,000-megawatt power plant complex and to the Pemex natural gas transportation system. Construction of the pipeline is expected to be completed during the second quarter of 2003.
For more information related to the financing of our expansion activities, see "Liquidity and Capital Resources - Primary Cash Requirements."
o Strategic Acquisitions. Since January 1, 2002, we have made the following acquisitions:
o Kinder Morgan Materials Services LLC, formerly Laser Materials Services LLC January 1, 2002;
o 33 1/3% interest in International Marine Terminals January 1, 2002;
o Additional 33 1/3% interest in International Marine Terminals February 1, 2002;
o Kinder Morgan Tejas January 31, 2002;
o Milwaukee Bagging Operations bulk terminal assets May 1, 2002;
o Remaining 33 1/3% interest in Trailblazer Pipeline Company May 6, 2002;
o Owensboro Gateway bulk terminal assets September 1, 2002;
o IC Terminal Holdings Company (St. Gabriel Terminal) September 1, 2002; and
o M.J. Rudolph bulk terminal assets January 1, 2003.
The costs and methods of financing for each of these acquisitions are discussed under "Liquidity and Capital Resources - 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 KMR.
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 assets. We face the possibility that during 2003, property insurance carriers generally may terminate insurance coverage for incidents of sabotage and terrorism or only offer it at prices that we believe are excessive. Recent federal legislation provides an insurance framework that should cause current insurers to continue to provide sabotage and terrorism coverage under standard property insurance policies. Nonetheless, there is no assurance that adequate sabotage and terrorism insurance will be available at reasonable rates throughout 2003. Currently, we do not believe that the increased cost associated with these measures will have a material effect on our operating results.
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 could have a negative impact on our financial performance. As of December 31, 2002, we have not noticed a significant decrease in the volumes of product, other than jet fuel, that we are moving through our operations as a result of the September 11, 2001 attacks. However, our deliveries of jet fuel showed steady improvement throughout 2002.
In addition, recent federal legislation signed into law in December 2002 includes new guidelines for the U.S. DOT and pipeline companies in the areas of testing, education, training and communication. The Pipeline Safety Improvement Act of 2002 provides a consistent set of guidelines for all operators to follow and requires the riskiest 50% of products pipelines and natural gas pipelines in the United States to be inspected within five years of the law's enactment. The pipeline risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its protective coating. The remaining 50% of the natural gas pipelines must be inspected within ten years of the law's enactment. The law requires pipelines to be re-evaluated every seven years thereafter. Compliance with this legislation will increase our operating expenses in the future.
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):
December 31, ---------------------------------- 2002 2001 2000 --------- --------- ----------- Long-term debt, excluding market value of interest rate swaps............... $3,659,533 $2,237,015 $1,255,453 Minority interest....................... 42,033 65,236 58,169 Partners' capital....................... 3,415,929 3,159,034 2,117,067 ---------- ---------- ----------- Total capitalization................. 7,117,495 5,461,285 3,430,689 Short-term debt, less cash and cash equivalents...................... (41,088) 497,417 589,630 ---------- --------- ----------- Total invested capital................ $7,076,407 $5,958,702 $4,020,319 ========== ========== ===========
Capitalization: Long-term debt, excluding market value of interest rate swaps.............. 51.4% 41.0% 36.6% Minority interest..................... 0.6% 1.2% 1.7% Partners' capital..................... 48.0% 57.8% 61.7% ----------- --------- ---------- 100.0% 100.0% 100.0% =========== ========= ==========
Invested Capital: Total debt, less cash and cash equivalents and excluding market value of interest rate swaps......................... 51.1% 45.9% 45.9% Partners' capital and minority interest........................... 48.9% 54.1% 54.1% ----------- -------- ----------- 100.0% 100.0% 100.0% =========== ======== ===========
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):
- -------------
(1)The remaining general partner interests are owned by ExxonMobil Cortez Pipeline, Inc., an indirect wholly-owned subsidiary of Exxon Mobil 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.
For the year ended December 31, 2002, our share of earnings, based on our ownership percentage, before income taxes and amortization of excess investment cost was $28.2 million from Cortez Pipeline Company, $26.4 million from Plantation Pipe Line Company and $19.1 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, issuing short-term commercial paper, long-term notes or additional common units or issuing additional i-units to KMR. In general, we expect to fund:
o cash distributions and sustaining capital expenditures with existing cash and cash flows from operating activities;
o expansion capital expenditures and working capital deficits with cash retained as a result of paying quarterly distributions on i-units in additional i-units, additional borrowings, the issuance of additional common units or the issuance of additional i-units to KMR;
o interest payments from cash flows from operating activities; and
o debt principal payments with additional borrowings as such debt principal payments become due or by the issuance of additional common units or the issuance of additional i-units to KMR.
As a publicly traded limited partnership, our common units are attractive primarily to individual investors. Individual investors represent a small segment of the total equity capital market. We believe institutional investors prefer shares of KMR over our common units due to tax and other regulatory considerations. Thus, KMR makes purchases of i-units issued by us with the proceeds from the sale of KMR shares to institutions.
The scheduled maturities of our outstanding debt, excluding market value of interest rate swaps, at December 31, 2002, are summarized as follows (in thousands):
2003........... $264,937 2004........... 5,018 2005........... 204,836 2006........... 45,019 2007........... 254,863 Thereafter..... 2,884,860 ---------- Total.......... $3,659,533 ==========
Of the $264.9 million scheduled to mature in 2003, we intend and have the ability to refinance the entire amount on a long-term basis under our existing credit facilities. Accordingly, this amount has been classified as long-term debt in our accompanying consolidated balance sheet at December 31, 2002. Currently, we do not anticipate any liquidity problems.
At December 31, 2002, our current commitments for sustaining capital expenditures were approximately $94.9 million. This amount has been committed primarily for the purchase of plant and equipment and is based on the payments we expect to need for our 2003 sustaining capital expenditure plan. All of our capital expenditures, with the exception of sustaining capital expenditures, are discretionary.
In addition, during the first quarter of 2003, we will need approximately $3 million to complete our acquisitions of assets from M.J. Rudolph Corporation and Stevedoring Services of America. The Rudolph acquisition includes long-term lease contracts used to operate four bulk terminal facilities at major ports along the East Coast and in the southeastern United States. The acquisition also includes the purchase of certain assets that provide stevedoring services at these locations. For more information, see Items 1 and 2 "Business and Properties -- Recent Developments" and Note 3 to our Consolidated Financial Statements. The purchase of assets from Stevedoring Services of America represents a barge-mounted floating crane that we currently lease at our bulk terminal facility in Port Sulphur, Louisiana. We expect to fund the completion of these investments with borrowings under our commercial paper program.
Some of our customers are experiencing severe financial problems that have had a significant impact on their creditworthiness. We are working to implement, to the extent allowable under applicable laws and regulations, prepayments and other security requirements such as letters of credit to enhance our credit position relating to amounts owed from these customers. We cannot assure that one or more of our financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position or future results of operations.
Operating Activities
Net cash provided by operating activities was $869.7 million in 2002 versus $581.2 million in 2001. The $288.5 million increase in 2002 resulted mainly from a $188.1 million increase in cash earnings, reflecting the strong performance and growth that occurred across our business portfolio during 2002. Also contributing to the overall increase in cash provided by operating activities was a $134.3 million increase relative to net changes in working capital items and a $8.9 million increase in the amount of distributions we received from our equity investments. The favorable working capital change was primarily the result of timing differences in the collection on and payments of our current accounts. The increase in equity distributions related to higher distributions from our 51% equity interest in Plantation Pipe Line Company and from our 50% equity interest in Coyote Gas Treating, LLC. The year-to-year overall increase in operating cash flows was partially reduced by higher payments made in 2002 under certain settlement agreements, primarily tariff-related agreements between shippers and our Products Pipelines, and environmental settlement agreements.
Investing Activities
Net cash used in investing activities was $1,450.9 million for the year ended December 31, 2002, compared to $1,818.9 million for the prior year. The $368.0 million decrease in funds utilized in investing activities was mainly attributable to higher expenditures made for strategic acquisitions in 2001. Outlays for acquisition of assets, new businesses and investments totaled $910.3 million in 2002, versus $1,523.5 million in 2001.
Our expenditures in 2002 included:
o $721.6 million for Kinder Morgan Tejas;
o $80.1 million for the remaining 33 1/3% ownership interest in Trailblazer Pipeline Company and a contingent interest in Trailblazer from CIG Trailblazer Gas Company;
o $29.9 million on December 31 for bulk terminal assets previously owned by M.J. Rudolph Corporation; and
o $29.0 million for an additional 10% ownership interest in the Cochin Pipeline system, which was made effective December 31, 2001.
Our expenditures in 2001 included:
o $982.7 million for the acquisition of GATX Corporation's domestic pipelines and terminals business, including Kinder Morgan Liquids Terminals LLC, CALNEV Pipe Line LLC and Central Florida Pipeline LLC;
o $359.1 million for KM Texas Pipeline, L.P.;
o $44.8 million for liquids terminals acquired from an affiliate of Stolt-Nielsen, Inc.;
o $43.6 million for bulk terminal LLC's acquired from Koninklijke Vopak N.V.;
o $41.7 million for Pinney Dock & Transport LLC; and
o $18.0 million for bulk and liquids terminal assets acquired from The Boswell Oil Company.
We continue to invest significantly in strategic acquisitions in order to fuel future growth and increase unitholder value. Partially offsetting the overall decline in funds used in investing activities in 2002 compared to 2001was a $247.1 million increase in funds used for capital expenditures and a $8.0 million increase in contributions to equity investments. Including expansion and maintenance projects, our capital expenditures were a record $542.2 million in 2002. We spent $295.1 million for capital expenditures in 2001. The $247.1 million increase was primarily due to continued investment in our Natural Gas Pipelines, CO2 Pipelines and Terminals business segments. We continue to expand and grow our existing businesses and have current projects in place that will significantly add storage and throughput capacity to our terminaling, natural gas transmission and carbon dioxide flooding operations. Our sustaining capital expenditures were $77.0 million for 2002, compared to $56.1 million for 2001. The $8.0 million increase in investment contributions was due to higher investments made to the natural gas gathering operations of Thunder Creek Gas Services, LLC and the carbon dioxide operations of MKM Partners, L.P.
Financing Activities
Net cash provided by financing activities amounted to $559.5 million in 2002, compared to $1,241.2 million in 2001. This decrease of $681.7 million from the prior year was chiefly due to lower cash inflows from equity financing activities. In May 2001, we received $996.9 million as proceeds from our initial sale of 29,750,000 i-units to KMR. In August 2002, we raised $331.2 million from our sale of an additional 12,478,900 i-units to KMR. The overall decrease in funds provided by financing activities also resulted from a $108.9 million increase in distributions to our partners in 2002 versus 2001. Cash distributions to all partners, including KMI, increased to $582.1 million in 2002 compared to $473.2 million in 2001. The increase in distributions was due to:
o an increase in the per unit cash distributions paid;
o an increase in the number of units outstanding; and
o 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.
The overall decrease in funds provided by financing activities was partly offset by a $105.6 million increase from overall debt financing activities. During each of the years 2001 and 2002, we purchased the pipeline and terminal businesses we acquired primarily with borrowings under our commercial paper program. We then raised funds by completing public and private debt offerings of senior notes and by issuing additional i-units. We then used the proceeds from these debt and equity issuances to reduce our borrowings under our commercial paper program. In 2002, we closed a public offering of $750 million in principal amount of senior notes, completed a private placement of $750 million in principal amount of senior notes to qualified institutional buyers (we then exchanged these notes with substantially identical notes that are registered under the Securities Act of 1933 in the fourth quarter of 2002) and retired a maturing amount of $200 million in principal amount of senior notes. In comparison, in 2001, we closed a public offering of $1.0 billion in principal amount of senior notes.
We paid distributions of $2.36 per unit in 2002 compared to $2.08 per unit in 2001. The 13% increase in paid distributions per unit resulted from favorable operating results in 2002.
We also distributed 2,538,785 i-units in quarterly distributions during 2002 to KMR, our sole i-unitholder. In 2001, we distributed 886,361 i-units in quarterly distributions to KMR. The amount of i-units distributed in each quarter was based upon the amount of cash we distributed to the owners of our common and Class B units during that quarter of 2002 and 2001. For each outstanding i-unit that KMR held, a fraction of an i-unit was issued. The fraction was determined by dividing:
o the cash amount distributed per common unit
by
o the average of KMR'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. Available cash consists generally of all of our cash receipts, including cash received by our operating partnerships, 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.
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. For 2002, 2001 and 2000, we distributed 97.6%, 100% and 102%, of the total of cash receipts less cash disbursements, respectively (calculations assume that KMR unitholders received cash). 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 KMR, 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 KMR'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 do not distribute cash to i-unit owners but 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:
o 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;
o 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;
o 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
o 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 value of cash and i-units being distributed. The general partner's incentive distribution that we declared for 2002 was $267.4 million, while the incentive distribution paid to our general partner during 2002 was $249.3 million. The difference between declared and paid distributions is due to the fact that the partnership distributions for the fourth quarter of each year are declared and paid in the first quarter of the following year.
On February 14, 2003, we paid a quarterly distribution of $0.625 per unit for the fourth quarter of 2002. This distribution was 14% greater than the $0.55 distribution per unit we paid for the fourth quarter of 2001 and 6% greater than the $0.59 distribution per unit we paid for the first quarter of 2002. We paid this distribution in cash to our common unitholders and to our Class B unitholders. KMR, our sole i-unitholder, received additional i-units based on the $0.625 cash distribution per common unit.
Debt and Credit Facilities
Our debt and credit facilities as of December 31, 2002, consisted primarily of:
o a $530 million unsecured 364-day credit facility due October 14, 2003;
o a $445 million unsecured three-year credit facility due October 15, 2005;
o $37.1 million of Series F First Mortgage Notes due December 2004 (our subsidiary, SFPP, L.P. is the obligor on the notes);
o $200 million of 8.00% Senior Notes due March 15, 2005;
o $40 million of Plaquemines, Louisiana Port, Harbor, and Terminal District Revenue Bonds due March 15, 2006 (our 66 2/3% owned subsidiary, International Marine Terminals, is the obligor on the bonds);
o $250 million of 5.35% Senior Notes due August 15, 2007;
o $30 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);
o $250 million of 6.30% Senior Notes due February 1, 2009;
o $250 million of 7.50% Senior Notes due November 1, 2010;
o $700 million of 6.75% Senior Notes due March 15, 2011;
o $450 million of 7.125% Senior Notes due March 15, 2012;
o $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);
o $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);
o $23.7 million of tax-exempt bonds due 2024 (our subsidiary, Kinder Morgan Operating L.P. "B", is the obligor on the bonds);
o $300 million of 7.40% Senior Notes due March 15, 2031;
o $300 million of 7.75% Senior Notes due March 15, 2032;
o $500 million of 7.30% Senior Notes due August 15, 2033; and
o a $975 million short-term commercial paper program (supported by our credit facilities, the amount available for borrowing under our credit facilities is reduced by our outstanding commercial paper borrowings).
None of our debt or credit facilities are subject to payment acceleration as a result of any change to our credit ratings. However, the margin that we pay with respect to LIBOR based borrowings under our credit facilities is tied to our credit ratings.
Our outstanding short-term debt at December 31, 2002, consisted of:
o $220 million of commercial paper borrowings;
o $37.1 million under the SFPP, L.P. 10.7% First Mortgage Notes;
o $5 million under the Central Florida Pipeline LLC Notes; and
o $2.8 million in other borrowings.
We intend and have the ability to refinance our $264.9 million of short-term debt on a long-term basis under our unsecured long-term credit facility. Accordingly, such amounts have been classified as long-term debt in our accompanying consolidated balance sheet. Currently, we do not anticipate any liquidity problems. The weighted average interest rate on all of our borrowings was approximately 5.015% during 2002 and 6.965% during 2001.
Credit Facilities
On December 31, 2000, we had two credit facilities, a $300 million unsecured five-year credit facility expiring on September 29, 2004, and a $600 million unsecured 364-day credit facility expiring on October 25, 2001. On December 31, 2000, the outstanding balance under our five-year credit facility was $207.6 million and the outstanding balance under our 364-day credit facility was $582 million.
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 credit facility was used to support the increase in our commercial paper program to $1.7 billion for our acquisition of the GATX businesses. 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 this $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 expiring on October 23, 2002. The terms of this credit facility were substantially similar to the terms of the expired facility. There were no borrowings under either credit facility at December 31, 2001.
On February 21, 2002, we obtained a third unsecured 364-day credit facility, in the amount of $750 million, expiring on February 20, 2003. The credit facility was used to support the increase in our commercial paper program to $1.8 billion for our acquisition of Tejas Gas, LLC, and the terms of this credit facility were substantially similar to the terms of our other two credit facilities. Upon issuance of additional senior notes in March 2002, this short-term credit facility was reduced to $200 million.
In August 2002, upon the completion of our i-unit equity sale, we terminated, under the terms of the agreement, our $200 million unsecured 364-day credit facility that was due February 20, 2003. On October 16, 2002, we successfully renegotiated our bank credit facilities by replacing our $750 million unsecured 364-day credit facility due October 23, 2002 and our $300 million unsecured five-year credit facility due September 29, 2004 with two new credit facilities. Our current facilities include:
o a $530 million unsecured 364-day credit facility due October 14, 2003; and
o a $445 million unsecured three-year credit facility due October 15, 2005.
Our credit facilities are with a syndicate of financial institutions. Wachovia Bank, National Association is the administrative agent under both credit facilities. The terms of our two credit facilities are substantially similar to the terms of our previous credit facilities. Interest on the two credit facilities accrues at our option at a floating rate equal to either:
o the administrative agent's base rate (but not less than the Federal Funds Rate, plus 0.5%); or
o LIBOR, plus a margin, which varies depending upon the credit rating of our long-term senior unsecured debt.
Our credit facilities include the following restrictive covenants as of December 31, 2002:
o requirements to maintain certain financial ratios:
o total debt divided by earnings before interest, income taxes, depreciation and amortization for the preceding four quarters may not exceed 5.0;
o total indebtedness of all consolidated subsidiaries shall at no time exceed 15% of consolidated indebtedness;
o tangible net worth as of the last day of any fiscal quarter shall not be less than $2,100,000,000; and
o consolidated indebtedness shall at no time exceed 62.5% of total capitalization;
o limitations on entering into mergers, consolidations and sales of assets;
o limitations on granting liens; and
o prohibitions on making any distribution to holders of units if an event of default exists or would exist upon making such distribution.
There were no borrowings under either credit facility at December 31, 2002. The amount available for borrowing under our credit facilities is reduced by:
o a $23.7 million letter of credit that supports Kinder Morgan Operating L.P. "B"'s tax-exempt bonds;
o a $28 million letter of credit entered into on December 23, 2002 that supports Nassau County, Florida Ocean Highway and Port Authority tax exempt bonds (associated with the operations of our bulk terminal facility
located at Fernandina Beach, Florida); and
o our outstanding commercial paper borrowings.
Our new three-year credit facility also permits us to obtain bids for fixed rate loans from members of the lending syndicate.
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 long-term debt securities as of December 31, 2002, consist of the following:
o $250 million in principal amount of 6.3% senior notes due February 1, 2009. These notes were issued on January 29, 1999. 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;
o $200 million of 8.0% notes due March 15, 2005. These notes were issued on March 22, 2000. In the offering, we received proceeds, net of underwriting discounts and commissions of approximately $197.9 million. We used the proceeds to reduce outstanding commercial paper;
o $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;
o $700 million of 6.75% notes due March 15, 2011 and $300 million of 7.40% notes due March 15, 2031. These notes were issued March 12, 2001. 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;
o $450 million of 7.125% notes due March 15, 2012 and $300 million of 7.75% notes due March 15, 2032. These notes were issued March 14, 2002. In the offering, we received proceeds, net of underwriting discounts and commissions of approximately $740.9 million. We used the proceeds to reduce our outstanding balance on our commercial paper borrowings; and
o $500 million of 7.30% notes due August 15, 2033 and $250 million of 5.35% notes due August 15, 2007. These notes were issued August 23, 2002. In the offering, we received proceeds, net of underwriting discounts and commissions of approximately $743.0 million. We used the proceeds to reduce our outstanding balance on our 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.
On March 22, 2002, we paid $200 million to retire the principal amount of our Floating Rate senior notes that matured on that date. We borrowed the necessary funds under our commercial paper program.
At December 31, 2002, our unamortized liability balance due on the various series of our senior notes was as follows (in millions):
8.0% senior notes due March 15, 2005 $ 199.8 5.35% senior notes due August 15, 2007 249.8 6.3% senior notes due February 1, 2009 249.5 7.5% senior notes due November 1, 2010 248.8 6.75% senior notes due March 15, 2011 698.3 7.125% senior notes due March 15, 2012 448.1 7.4% senior notes due March 15, 2031 299.3 7.75% senior notes due March 15, 2032 298.5 7.3% senior notes due August 15, 2033 499.0 ---------- Total $ 3,191.1 ==========
Commercial Paper Program
On December 31, 2000, our commercial paper program provided for the issuance of up to $600 million of commercial paper. On that date, we had $52 million of commercial paper outstanding with an interest rate of 7.02%. 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. We entered into a $1.1 billion unsecured 364-day credit facility to support this increase in our commercial paper program, and we used the program's increase in available funds to close on the GATX acquisition.
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 representing limited liability company interests with limited voting rights to the public in an initial public offering. Its shares were issued at a price of $35.21 per share, less commissions and underwriting expenses, and it used substantially all of the net proceeds from that offering to purchase i-units from us. After commissions and underwriting expenses, we received net proceeds of approximately $996.9 million for the issuance of 29,750,000 i-units to KMR. We used the proceeds from the i-unit issuance to reduce the borrowings under our commercial paper program.
Also during the second quarter of 2001, after the issuance of additional senior notes on March 12, 2001 and the issuance of i-units in May 2001, we decreased our commercial paper program back to $600 million. On October 17, 2001, we increased our commercial paper program to $900 million. As of December 31, 2001, we had $590.5 million of commercial paper outstanding with an interest rate of 2.6585%.
On February 21, 2002, our commercial paper program increased to provide for the issuance of up to $1.8 billion of commercial paper. We entered into a $750 million unsecured 364-day credit facility to support this increase in our commercial paper program, and we used the program's increase in available funds to close on the Tejas acquisition. After the issuance of additional senior notes on March 14, 2002, we reduced our commercial paper program to $1.25 billion.
On August 6, 2002, KMR issued in a public offering, an additional 12,478,900 of its shares, including 478,900 shares upon exercise by the underwriters of an over-allotment option, at a price of $27.50 per share, less commissions and underwriting expenses. The net proceeds from the offering were used to buy i-units from us. After commissions and underwriting expenses, we received net proceeds of approximately $331.2 million for the issuance of 12,478,900 i-units. We used the proceeds from the i-unit issuance to reduce the borrowings under our commercial paper program and, in conjunction with our issuance of additional i-units and as previously agreed upon under the terms of our credit facilities, we reduced our commercial paper program to provide for the issuance of up to $975 million of commercial paper as of December 31, 2002. On December 31, 2002, we had $220.0 million of commercial paper outstanding with an average interest rate of 1.58%.
The borrowings under our commercial paper program were used to finance acquisitions made during 2001 and 2002. The borrowings under our commercial paper program reduce the borrowings allowed under our credit facilities.
SFPP, L.P. Debt
At December 31, 2002, the outstanding balance under SFPP, L.P.'s Series F notes was $37.1 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 repaid $31.5 million and $29.5 million in 1999 and 2000, respectively, under the Series F notes prior to maturity as a result of SFPP, L.P. taking advantage of certain optional prepayment provisions without penalty. We expect to pay the remaining $37.1 million balance in December 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 collateralized 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. 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:
o 4.1 million of 7.30% New Jersey Industrial Revenue Bonds due September 1, 2019;
o $59.5 million of 6.95% Texas Industrial Revenue Bonds due February 1, 2022;
o $7.4 million of 6.65% New Jersey Industrial Revenue Bonds due September 1, 2022;
o $13.3 million of 7.00% Louisiana Industrial Revenue Bonds due March 1, 2023; and
o $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. These 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, 2002, the interest rate was 1.05%. 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. 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% with repayments 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, 2002, Central Florida's outstanding balance under the Senior Notes was $30.0 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.
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, and 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, provided for loans of up to $85.2 million and had a maturity date of June 29, 2003. The agreement provided for an interest rate of LIBOR plus a margin as determined by certain financial ratios. Pursuant to the terms of the revolving credit facility, Trailblazer Pipeline Company partnership distributions were restricted by certain financial covenants. 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%. In July 2002, we paid the $31.0 million outstanding balance under Trailblazer's revolving credit facility and terminated the facility.
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 2002, the weighted-average interest rate on these bonds was 1.39% per annum, and at December 31, 2002, the interest rate was 1.59%. We have an outstanding letter of credit issued under our credit facilities that supports our tax-exempt bonds. The letter of credit reduces the amount available for borrowing under our credit facilities.
International Marine Terminals Debt
As of February 1, 2002, we owned a 66 2/3% interest in International Marine Terminals partnership. The principal assets owned by IMT are dock and wharf facilities financed by the Plaquemines Port, Harbor and Terminal District (Louisiana) $40,000,000 Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds (International Marine Terminals Project) Series 1984A and 1984B. The bonds mature on March 15, 2006. The bonds are backed by two letters of credit issued by KBC Bank N.V. On March 19, 2002, an Amended and Restated Letter of Credit Reimbursement Agreement relating to the letters of credit in the amount of $45.5 million was entered into by IMT and KBC Bank. In connection with that agreement, we agreed to guarantee the obligations of IMT in proportion to our ownership interest. Our obligation is approximately $30.3 million for principal, plus interest and other fees.
Cortez Pipeline Company Debt
Pursuant to a certain Throughput and Deficiency Agreement, the owners of Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% owner; a subsidiary of Exxon Mobil Corporation - 37% owner; and Cortez Vickers Pipeline Company - 13% owner) are required, on a percentage ownership basis, to contribute capital to Cortez Pipeline Company in the event of a cash deficiency. The Throughput and Deficiency Agreement contractually supports the borrowings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by obligating the owners of Cortez Pipeline Company to fund cash deficiencies at Cortez Pipeline Company, including cash deficiencies relating to the repayment of principal and interest on borrowings by Cortez Capital Corporation. Parent companies of the respective Cortez Pipeline Company owners further severally guarantee, on a percentage basis, the obligations of the Cortez Pipeline Company owners under the Throughput and Deficiency Agreement.
Due to our indirect ownership of Cortez Pipeline Company through Kinder Morgan CO2 Company, L.P., 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 Capital Corporation's debt programs in place as of April 1, 2000.
At December 31, 2002, the debt facilities of Cortez Capital Corporation consisted of:
o $115.7 million of Series D notes due May 15, 2013;
o a $175 million short-term commercial paper program; and
o a $175 million committed revolving credit facility due December 26, 2003 (to support the above-mentioned $175 million commercial paper program).
At December 31, 2002, Cortez Capital Corporation had $140.6 million of commercial paper outstanding with an interest rate of 1.39%, the average interest rate on the Series D notes was 6.9322% and there were no borrowings under the credit facility.
Capital Requirements for Recent Transactions
During 2002, our cash outlays for the acquisitions of assets and equity investments totaled $910.3 million. We utilized our short-term credit facilities to fund these acquisitions and then reduced our short-term borrowings with the proceeds from our August 2002 issuance of i-units and our March and August 2002 issuances of long-term senior notes. We intend to refinance the remainder of our current short-term debt and any additional short-term debt incurred during 2003 through a combination of long-term debt, equity and the issuance of additional commercial paper to replace maturing commercial paper borrowings.
Cochin Pipeline. Effective December 31, 2001, we acquired an additional 10% ownership interest in the Cochin Pipeline system for approximately $29.0 million in cash. We made the payment in January 2002 and we borrowed the necessary funds under our commercial paper program.
Kinder Morgan Materials Services LLC. Effective January 1, 2002, we acquired Kinder Morgan Materials Services LLC, formerly Laser Materials Services LLC, for approximately $12.2 million in aggregate consideration, consisting of $8.9 million in cash, $0.4 million in assumed debt and $2.9 million in assumed liabilities. We borrowed the necessary funds under our commercial paper program.
International Marine Terminals. Effective January 1, 2002, we acquired 33 1/3% of International Marine Terminals, and effective February 1, 2002, we acquired an additional 33 1/3% ownership interest. For the two interests combined, our purchase price totaled approximately $40.5 million, consisting of $40.0 million in assumed debt, $4.3 million in assumed liabilities and an offset of $3.8 million for cash received.
Kinder Morgan Tejas. Effective January 31, 2002, we acquired Tejas Gas, LLC for approximately $881.5 million in aggregate consideration, consisting of $727.1 million in cash and $154.4 million in assumed liabilities. We borrowed the necessary funds under our commercial paper program.
Milwaukee Bagging Operations. Effective May 1, 2002, we acquired certain bulk terminal assets for approximately $8.5 million in cash. We borrowed the necessary funds under our commercial paper program.
Trailblazer Pipeline Company. Effective May 6, 2002, we acquired the remaining 33 1/3% of Trailblazer Pipeline Company that we did not already own for approximately $80.1 million in cash. We borrowed the necessary funds under our commercial paper program.
Owensboro Gateway Terminal. Effective September 1, 2002, we acquired certain bulk and terminal assets from Lanham River Terminal, LLC for approximately $7.7 million in aggregate consideration, consisting of $7.2 million in cash and $0.5 million in a short-term liability. We borrowed the necessary funds under our commercial paper program.
IC Terminal Holdings Company (St. Gabriel Terminal). Effective September 1, 2002, we acquired all of the shares of the capital stock of IC Terminal Holdings Company from the Canadian National Railroad for approximately $17.8 million in aggregate consideration, consisting of $17.6 million in cash and $0.2 million in assumed liabilities. We borrowed the necessary funds under our commercial paper program.
M.J. Rudolph. Effective January 1, 2003, we acquired certain bulk terminal assets from M.J Rudolph Corporation for approximately $31.3 million in cash. We paid $29.9 million on December 31, 2002 and we borrowed the necessary funds under our commercial paper program.
New Accounting Pronouncements
On January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations". SFAS No. 143 requires companies to record a liability relating to the retirement and removal of assets used in their business. The liability is initially recorded at its fair 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. With respect to our Natural Gas Pipelines and Products Pipelines business segments, we have certain surface facilities that are required to be dismantled and removed, with certain site reclamation to be performed. While, in general, our right-of-way agreements do no require us to remove pipe or otherwise perform remediation upon taking the pipeline permanently out of service, some right-of-way agreements do provide for these actions. With respect to our CO2 Pipelines business segment, we generally are required to plug our oil production wells when removed from service and we anticipate recording a liability for such obligation. Our Terminals business segment has entered into certain facility leases which require removal of improvements upon expiration of the lease term. We anticipate recording a liability for such obligation. For the Natural Gas Pipelines and Products Pipelines business segments, we expect that we will be unable to reasonably estimate and record liabilities for the majority of our obligations that fall under the provisions of this statement because we cannot reasonably estimate when such obligations would be settled. For the CO2 Pipelines and Terminals business segments, the effect of adopting SFAS No. 143 is not material to the consolidated financial statements.
In April 2002, the Financial Accounting Standards Board issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." This Statement eliminates the current requirement that gains and losses on debt extinguishment must be classified as extraordinary items in the income statement. Instead, such gains and losses will be classified as extraordinary items only if they are deemed to be unusual and infrequent, in accordance with the current GAAP criteria for extraordinary classification. In addition, SFAS No. 145 eliminates an inconsistency in lease accounting by requiring that modifications of capital leases that result in reclassification as operating leases be accounted for consistent with sale-leaseback accounting rules. This Statement also contains other nonsubstantive corrections to authoritative accounting literature. The changes related to debt extinguishment will be effective for fiscal years beginning after May 15, 2002, and the changes related to lease accounting will be effective for transactions occurring after May 15,
2002. Adoption of this Statement will not have any immediate effect on our consolidated financial statements. We will apply this guidance prospectively.
In June 2002, the Financial Accounting Standards Board issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally Emerging Issues Task Force Issue No. 94-3. We will adopt the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of the company's commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized.
In November 2002, the Financial Accounting Standards Board issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others". This interpretation of Financial Accounting Standards Board Statements No. 5, 57 and 107, and rescission of Financial Accounting Standards Board Interpretation No. 34 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. This interpretation incorporates, without change, the guidance in Financial Accounting Standards Board Interpretation No. 34, "Disclosure of Indirect Guarantees of Indebtedness of Others", which is being superceded. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements in this interpretation are effective for financial statements of interim or annual periods after December 15, 2002. The interpretive guidance incorporated from Interpretation No. 34 continues to be required for financial statements for fiscal years ending after June 15, 1981.
In December 2002, the Financial Accounting Standards Board issued SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure". This amendment to SFAS No. 123, "Accounting for Stock-Based Compensation", provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this statement amends the disclosure requirements of SFAS No. 123 to require disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The provisions of this statement are effective for financial statements of interim or annual periods after December 15, 2002. Early application of the disclosure provisions is encouraged, and earlier application of the transition provisions is permitted, provided that financial statements for the 2002 fiscal year have not been issued as of the date the statement was issued.
Information Regarding Forward-Looking Statements
This filing includes forward-looking statements. 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 actions, conditions or events, 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. Future actions, conditions or events and future results of 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:
o 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;
o economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand;
o changes in our tariff rates implemented by the Federal Energy Regulatory Commission or the California Public Utilities Commission;
o our ability to integrate any acquired operations into our existing operations;
o our ability to acquire new businesses and assets and to make expansions to our facilities;
o difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to our terminals or pipelines;
o our ability to successfully identify and close acquisitions and make cost-saving changes in operations;
o shut-downs or cutbacks at major refineries, petrochemical or chemical plants, ports, utilities, military bases or other businesses that use or supply our services;
o 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;
o our ability to offer and sell equity securities and debt securities or obtain debt financing in sufficient amounts to implement that portion of our business plan that contemplates growth through acquisitions of operating businesses and assets and expansions of our facilities;
o our indebtedness could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantages compared to our competitors that have less debt or have other adverse consequences;
o interruptions of electric power supply to our facilities due to natural disasters, power shortages, strikes, riots, terrorism, war or other causes;
o acts of sabotage, terrorism or other similar acts causing damage greater than our insurance coverage limits;
o the condition of the capital markets and equity markets in the United States;
o the political and economic stability of the oil producing nations of the world;
o national, international, regional and local economic, competitive and regulatory conditions and developments;
o the ability to achieve cost savings and revenue growth;
o rates of inflation;
o interest rates;
o the pace of deregulation of retail natural gas and electricity;
o the timing and extent of changes in commodity prices for oil, natural gas, electricity and certain agricultural products; and
o the timing and success of business development efforts.
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.
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 or commodity prices. 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 or commodity prices and the timing of transactions.
Energy Financial Instruments
We use energy financial instruments to reduce our risks associated with changes in the market price of natural gas, natural gas liquids, crude oil and carbon dioxide. 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, 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.
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:
o ceased to account for those derivatives as hedges;
o entered into new derivative transactions on substantially similar terms with other counterparties to replace our positions with Enron;
o designated the replacement derivative positions as hedges of the exposures that had been hedged with the Enron positions; and
o recognized a $6.0 million loss (included with General and administrative expenses in the accompanying Consolidated Statement of Income 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. The credit ratings of the primary parties from whom we purchase financial instruments are as follows:
Credit Rating J. Aron & Company / Goldman Sachs A+ Morgan Stanley.................. A+ Deutsche Bank................... AA-
Pursuant to our management's approved policy, we are to engage in these activities only as a hedging mechanism against price volatility associated with:
o pre-existing or anticipated physical natural gas, natural gas liquids, crude oil and carbon dioxide sales;
o natural gas purchases; and
o 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 our 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 occurred. 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 No. 137 and SFAS No. 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. Our adoption of SFAS No. 133 has resulted in $45.3 million of deferred net loss being reported as Accumulated other comprehensive income in the accompanying Balance Sheet at December 31, 2002, and $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. For each of the years ended December 31, 2002 and 2001, Value-at-Risk reached a high of $12.8 million and $19.9 million, respectively, and a low of $11.6 million and $12.8 million, respectively. Value-at-Risk at December 31, 2002, was $12.8 million and averaged $11.9 million for 2002. 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 of 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. In addition, as discussed preceding, we enter into these derivatives solely for the purpose of mitigating the risks that accompany certain of our business activities and, therefore, the change in the market value of our portfolio of derivatives is, with the exception of a minor amount of hedging inefficiency, offset by changes in the value of the underlying physical transactions.
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.
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, 2002 and 2001, the carrying values of our long-term fixed rate debt were approximately $3,346.1 million and $1,900.6 million, respectively, compared to fair values of $4,161.6 million and $2,197.9 million, respectively. The increase in the excess of fair value over carrying value is primarily due to the decrease in interest rates during 2002. 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 2002 and 2001, respectively, would result in changes of approximately $195.1 million and $77.4 million, respectively, in the fair values of these instruments.
The carrying value and fair value of our variable rate debt, including associated accrued interest and excluding market value of interest rate swaps, was $293.4 million as of December 31, 2002 and $890.9 million as of December 31, 2001. 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 $1.6 million and $6.2 million in our 2002 and 2001 annualized pre-tax earnings, respectively.
As of December 31, 2002, we were party to interest rate swap agreements with a notional principal amount of $1.95 billion for the purpose of hedging the interest rate risk associated with our fixed and variable 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 in 2002 or 2001. 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, 2002, 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 89.
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 KMR 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. Kinder Morgan (Delaware), Inc. is a wholly owned subsidiary of KMI. 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 was a director of the delegate until its resignation in January 2003.
Name Age Position with our General Partner and the Delegate --------------- ---- -------------------------------------------------- Richard D. Kinder... 58 Director, Chairman and Chief Executive Officer Michael C. Morgan... 34 President C. Park Shaper...... 34 Director, Vice President, Treasurer and Chief Financial Officer Edward O. Gaylord... 71 Director Gary L. Hultquist... 59 Director Perry M. Waughtal... 67 Director Thomas A. Bannigan.. 49 President, Products Pipelines R. Tim Bradley...... 47 President, CO2 Pipelines David D. Kinder..... 28 Vice President, Corporate Development Joseph Listengart... 34 Vice President, General Counsel and Secretary Deborah A. Macdonald 51 President, Natural Gas Pipelines Thomas B. Stanley... 52 President, Terminals James E. Street..... 46 Vice President, Human Resources and Administration
Richard D. Kinder is Director, Chairman and Chief Executive Officer of KMR, Kinder Morgan G.P., Inc. and KMI. Mr. Kinder has served as Director, Chairman and Chief Executive Officer of KMR 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 Baker Hughes Incorporated. Mr. Kinder is the uncle of David Kinder, Vice President, Corporate Development of KMR, Kinder Morgan G.P., Inc. and KMI.
Michael C. Morgan is President of KMR, Kinder Morgan G.P., Inc. and KMI. Mr. Morgan was elected to each of these positions in July 2001. He was also elected Director of KMI in January 2003. Mr. Morgan served as Vice President-Strategy and Investor Relations of KMR 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.
C. Park Shaper is Director, Vice President, Treasurer and Chief Financial Officer of KMR and Kinder Morgan G.P., Inc. and Vice President, Treasurer and Chief Financial Officer of KMI. Mr. Shaper was elected Director of KMR and Kinder Morgan G.P., Inc. in January 2003. He was elected Vice President, Treasurer and Chief Financial Officer of KMR 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.
Edward O. Gaylord is a Director of KMR and Kinder Morgan G.P., Inc. Mr. Gaylord was elected Director of KMR 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. Mr. Gaylord currently serves as the chairman of the compensation and audit committees of KMR and our general partner.
Gary L. Hultquist is a Director of KMR and Kinder Morgan G.P., Inc. Mr. Hultquist was elected Director of KMR 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 KMR and Kinder Morgan G.P., Inc. Mr. Waughtal was elected Director of KMR 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.
Thomas A. Bannigan is President, Products Pipelines of KMR and Kinder Morgan G.P., Inc. and President and Chief Executive Officer of Plantation Pipe Line Company. Mr. Bannigan was elected President, Products Pipelines of KMR 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, CO2 Pipelines of KMR and of Kinder Morgan G.P., Inc. and President of Kinder Morgan CO2 Company, L.P. Mr. Bradley was elected President, CO2 Pipelines of KMR and Vice President (President, CO2 Pipelines) of Kinder Morgan G.P., Inc. in April 2001. Mr. Bradley has been President of Kinder Morgan CO2 Company, L.P. (which name changed from Shell CO2 Company, Ltd. in April 2000) since March 1998. From May 1996 to March 1998, Mr. Bradley was Manager of CO2 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 D. Kinder is Vice President, Corporate Development of KMR, Kinder Morgan G.P., Inc. and KMI. Mr. Kinder was elected Vice President, Corporate Development of KMR, Kinder Morgan G.P., Inc. and KMI in October 2002. He served as manager of corporate development for KMI and Kinder Morgan G.P., Inc. from January 2000 to October 2002. He served as an associate in the corporate development group of KMI and Kinder Morgan G.P., Inc. from February 1999 to January 2000. From June 1996 to February 1999, Mr. Kinder was in the analyst and associate program at Enron Corp. Mr. Kinder graduated cum laude with a Bachelors degree in Finance from Texas Christian University in 1996. Mr. Kinder is the nephew of Richard D. Kinder.
Joseph Listengart is Vice President, General Counsel and Secretary of KMR, Kinder Morgan G.P., Inc. and KMI. Mr. Listengart was elected Vice President, General Counsel and Secretary of KMR 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.
Deborah A. Macdonald is President, Natural Gas Pipelines of KMR, Kinder Morgan G.P., Inc. and KMI. She was elected as President, Natural Gas Pipelines in June 2002. She also holds the title of President of Natural Gas Pipeline Company of America, KMI's largest subsidiary. Ms. Macdonald has served as President of NGPL since the merger of KMI in October 1999. Prior to joining Kinder Morgan, Ms. Macdonald worked as Senior Vice President of legal affairs for Aquila Energy Company from January 1999 to October 1999, and was engaged in a private energy consulting practice from June 1996 to December 1999. Ms. Macdonald received her Juris Doctor, summa cum laude, from Creighton University in May 1980 and received a Bachelors degree, magna cum laude, from Creighton University in December 1972.
Thomas B. Stanley is President, Terminals of KMR 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 KMR 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 KMR, Kinder Morgan G.P., Inc. and KMI. Mr. Street was elected Vice President, Human Resources and Administration of KMR 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.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16 of the Exchange Act requires our directors and officers, and persons who own more than 10% of a registered class of our equity securities, to file initial reports of ownership and reports of changes in ownership with the Securities and Exchange Commission. Such persons are required by SEC regulation to furnish us with copies of all Section 16(a) forms they file.
Based solely on our review of the copies of such forms furnished to us and written representations from our executive officers and directors, we believe that all Section 16(a) filing requirements were met during 2002, except for a failure to file three reports by Mr. Richard D. Kinder covering eight transactions for the purchase of a total of 756 common units acquired unintentionally by Mr. Kinder's spouse under a distribution reinvestment program implemented by her broker without Mr. Kinder's knowledge.
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 our general partner, 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 KMR, the management and control of our business and affairs to the maximum extent permitted by our partnership agreement and Delaware law, subject to our general partner's right to approve certain actions by KMR. The executive officers and directors of Kinder Morgan G.P., Inc. serve in the same capacities for KMR. 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., KMR, KMI and their respective affiliates.
(1) Amounts earned in year shown and paid the following year.
(2)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.
(3)For 2000, amounts represent our general partner's contributions to the Kinder Morgan 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 the Kinder Morgan Savings Plan, value of group-term life insurance exceeding $50,000, parking subsidy and a $50 cash payment. For 2002, amounts represent contributions to the Kinder Morgan Savings Plan, value of group-term life insurance exceeding $50,000 and taxable parking subsidy. Ms. Macdonald's amounts include additions in 2000 and 2001 resulting from relocation expenses.
(4)Does not include $7,010,000 paid to Mr. Morgan under our Executive Compensation Plan. The payment made in 2000 was the last payment Mr. Morgan is 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."
(5)The 150,000 options to purchase KMI shares were granted and became fully vested on April 20, 2000. The options were granted to Mr. Morgan in connection with the execution of his employment agreement. The options have an exercise price of $33.125 per share. See "-- Employment Agreement."
(6)The 100,000 options to purchase KMI shares were granted on January 16, 2002 with an exercise price of $56.99 per share and vest at the rate of twenty-five percent on each of the first four anniversaries after the date of grant.
(7)The year 2000 options to purchase KMI shares include 25,000 options that were granted in 2001, but relate to performance in 2000. These options were granted and became fully vested on January 17, 2001 with an exercise price of $49.875 per share. The remaining 125,000 options were granted on January 20, 2000 with an exercise price of $24.75 per share. These options vest at the rate of twenty-five percent on each of the first four anniversaries after the date of grant.
(8)The 6,300 options to purchase KMI shares were granted in 2001, but relate to performance in 2000. The options were granted and became fully vested on January 17, 2001 with an exercise price of $49.875 per share.
(9)The 50,000 options to purchase KMI shares were granted on January 16, 2002 with an exercise price of $56.99 per share and vest at the rate of 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 by eight (less a participant adjustment factor, if any). Under the plan, no eligible employee may receive a grant in excess of two percent of the incentive compensation value, and total awards under the plan may not exceed ten percent of the incentive compensation value. 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 an award totaling two percent of the incentive compensation value to Mr. Michael Morgan. Originally, 50 percent of such award was to vest on each of January 1, 2000 and January 1, 2002. No awards have been granted since July 1997.
On January 4, 1999, the award granted to Mr. Morgan was amended to provide for the immediate vesting and pay-out of 50 percent of his award, or one percent of the incentive compensation value. On April 28, 2000, the award granted to Mr. Morgan was amended to provide for the immediate vesting and pay-out of the remaining 50 percent of his award, or one percent of the incentive compensation value. The board of directors of our general partner believes that accelerating the vesting and pay-out of the award was in our best interest because it capped the total payment Mr. Morgan was entitled to receive with respect to his award. The payment made in 2000 was the last payment Mr. Morgan is to receive under our Executive Compensation Plan. We do not intend to compensate any employees providing service to us under the Executive Compensation Plan on a going-forward basis.
Kinder Morgan 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 KMGP Services Company, Inc. to contribute one percent to 50 percent of base compensation, on a pre-tax basis, into participant accounts. In addition to a mandatory contribution equal to four 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. During the first quarter of 2003, we do not believe that we will make any discretionary contributions to individual accounts for 2002. 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, 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, 2002, outstanding options to purchase 261,600 common units had been granted to 84 former Kinder Morgan G.P., Inc. employees who are now employees of Kinder Morgan, Inc. or KMGP Services Company, Inc. Forty percent of such options will vest on the first anniversary of the date of grant and 20 percent on each of the next three anniversaries. The options expire seven years from the date of grant.
The option plan also granted to each of our then non-employee directors as of April 1, 1998, an option to purchase 10,000 common units at an exercise price equal to the fair market value of the common units at the end of the trading day on such date. In addition, each new non-employee director is granted 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, 2002, outstanding options to purchase 20,000 common units had been granted to two of Kinder Morgan G.P., Inc.'s three non-employee directors. Forty percent of all such options will vest on the first anniversary of the date of grant and 20 percent on each of the next three anniversaries. The non-employee director options will expire seven years from the date of grant.
No options to purchase common units were granted during 2002 to any of the individuals named in the Summary Compensation Table above. The following table sets forth certain information at December 31, 2002 with respect to common unit options previously granted to the individuals named in the Summary Compensation Table above. Mr. Listengart was the only person named in the Summary Compensation Table who was granted common unit options. No common unit options were granted at an option price below the fair market value on the date of grant.
Aggregated Common Unit Option Exercises in 2002, and 2002 Year-End Common
(1)Calculated on the basis of the fair market value of the underlying common units at year-end 2002, minus the exercise price.
KMI Option Plan. Under KMI's stock option plan, employees of KMI and its affiliates, including employees of KMI's direct and indirect subsidiaries, like KMGP Services Company, Inc., 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 KMI, KMGP Services Company, Inc. 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, 2002 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. Shaper and Ms. Macdonald are the only persons named in the Summary Compensation Table who were granted KMI stock options during 2002. 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 on January 16, 2002 and vest at twenty-five percent on each of the first four anniversaries after the date of grant. The options expire 10 years after the date of grant.
(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 $92.83 and $147.82, 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 2002 and 2002 Year-End KMI Stock Option Values
(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 KMGP Services Company, Inc. and KMI are eligible to participate in a 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 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 three percent of eligible compensation every pay period. In addition, discretionary contributions are made to the plan based on our and KMI's performance. In the first quarter of 2002, an additional one percent discretionary contribution was made to individual accounts. No additional contributions were made for 2002 performance. 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.
The following table sets forth the estimated annual benefits payable under normal retirement at age sixty-five, assuming current remuneration levels without any salary projection, and participation until normal retirement at age sixty-five, with respect to the named executive officers under the provisions of the Kinder Morgan Cash Balance Retirement Plan.
Estimated Estimated Current Credited Current Annual Credited Years Compensation Benefit Years of Service Age as of Covered by Upon Name of Service at Age 65 Jan. 1, 2003 Plans Retirement(1) ---- ---------- ---------- ------------ ------------ ------------ Richard D. Kinder 2 8.8 58.2 $ 1 $ - Michael C. Morgan 2 32.6 34.4 200,000 62,686 C. Park Shaper 2 32.6 34.4 200,000 62,686 Joseph Listengart 2 32.4 34.6 200,000 61,928 Deborah A. MacDonald 2 15.8 51.2 200,000 15,875 - ----------
(1)The estimated annual benefits payable are based on the straight-life annuity form.
Compensation Committee Interlocks and Insider Participation. We do not have a separate compensation committee. KMR'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. C. Park Shaper, who are executive officers of KMR, participate in the deliberations of the KMR compensation committee concerning executive officer compensation. Mr. Kinder receives $1.00 annually in total salary compensation for services to KMI, KMR and us.
Directors Fees. During 2002, each of the three non-employee members of the boards of directors of KMR and our general partner was paid $10,000 in the aggregate for each quarter in 2002 in which they served on such boards of directors. Under the current plan, each is to receive $10,000 for each quarter in 2003 in which they serve. In addition, the director who serves as chairman of KMR's audit committee will be paid an additional $2,500 for each quarter in 2003. Directors are reimbursed for reasonable expenses in connection with board meetings. Consistent with the current plan, each director received $10,000 in cash compensation with respect to board service for the first quarter of 2003; however, we plan to implement a phantom unit option plan for non-employee directors, which will serve as the sole compensation for non-employee directors for the remainder of 2003, other than the $2,500 which will be paid in cash each quarter to the audit committee chairman.
Employment Agreement. In April 2000, Mr. Michael C. Morgan entered into a four-year employment agreement with KMI and our general partner. Under the employment agreement, Mr. Morgan receives an annual base salary of $200,000 and bonuses at the discretion of the compensation committee of KMR. In connection with the execution of the employment agreement, Mr. Morgan no longer participates under our Executive Compensation Plan. In addition, he is prevented from competing with KMI and us for a period of four years from the date of the agreement, 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 Mr. C. Park Shaper, an officer of KMI, our general partner and its delegate. Pursuant to the terms of the agreement, Mr. Shaper obtained 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. We have agreed to guarantee potential borrowings under lines of credit available from Wachovia Bank, National Association to Messrs. Listengart, Shaper and Ms. Macdonald. Each of these officers is primarily liable for any borrowing on his line of credit, and if we make any payment with respect to an outstanding loan, the officer on behalf of whom payment is made must surrender a percentage of his or her KMI stock options. To date, we have made no payment with respect to these lines of credit. Furthermore, the lines of credit and our related guaranty expire in October 2003 and will not be renewed.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The following table sets forth information as of January 31, 2003, regarding (a) the beneficial ownership of (i) our common and Class B units, (ii) the common stock of KMI, the parent company of our general partner, and (iii) KMR 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 and Class B units or shares of KMR by all persons known by our general partner to own beneficially more than five percent of our common and Class B units and KMR shares. 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 and Class B units and to the number of KMR shares have been restated to reflect the effect of the two-for-one splits of our outstanding common and Class B units and KMR shares that occurred on August 31, 2001.
Amount and Nature of Beneficial Ownership(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, 2003, we had 129,971,518 common units issued and outstanding.
(3) As of January 31, 2003, we had 5,313,400 Class B units issued and outstanding.
(4) Represent the limited liability company shares of KMR. As of January 31, 2003, there were 45,654,048 issued and outstanding KMR 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 KMR shares. Through the provisions in our partnership agreement and KMR's limited liability company agreement, the number of outstanding KMR shares, including voting shares owned by our general partner, and the number of our i-units will at all times be equal.
(5) As of January 31, 2003, KMI had a total of 121,933,618 shares of issued and outstanding voting common stock, which excludes 8,099,868 shares held in treasury.
(6) Includes (a) 7,856 common units owned by Mr. Kinder's spouse, (b) 5,156 KMI shares held by Mr. Kinder's spouse and (c) 250 KMI shares held by Mr. Kinder in a custodial account for his nephew. Mr. Kinder disclaims any and all beneficial or pecuniary interest in these units and shares.
(7) Includes options to purchase 275,000 KMI shares exercisable within 60 days of January 31, 2003, and includes 12,500 shares of restricted KMI stock.
(8) Includes options to purchase 143,750 KMI shares exercisable within 60 days of January 31, 2003, and includes 12,500 shares of restricted KMI stock.
(9) Includes options to purchase 8,000 common units exercisable within 60 days of January 31, 2003.
(10)Includes options to purchase 6,000 common units exercisable within 60 days of January 31, 2003.
(11)Includes options to purchase 10,000 common units and 88,800 KMI shares exercisable within 60 days of January 31, 2003, and includes 12,500 shares of restricted KMI stock.
(12)Includes options to purchase 62,500 KMI shares exercisable within 60 days of January 31, 2003, and includes 12,500 shares of restricted KMI stock.
(13)Includes options to purchase 47,200 common units and 897,925 KMI shares exercisable within 60 days of January 31, 2003, and includes 75,450 shares of restricted KMI stock.
(14)Includes common units owned by KMI and its consolidated subsidiaries, including 1,724,000 common units owned by Kinder Morgan G.P., Inc.
(15)As reported on the Schedule 13G/A filed February 14, 2003 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 3,967,893 common units, sole disposition power over 2,000,000 common units and shared disposition power over 5,019,652 common units. Mr. Sarofim is a director of KMI. Fayez Sarofim & Co.'s and Mr. Sarofim's address is 2907 Two Houston Center, Houston, Texas 77010.
(16)As reported on the Schedule 13G/A filed February 11, 2003 by Capital Group International, Inc. and Capital Guardian Trust Company. Capital Group International, Inc. and Capital Guardian Trust Company report that in regard to KMR shares, they have sole voting power over 3,373,010 shares, shared voting power over 0 shares, sole disposition power over 4,543,590 shares and shared disposition power over 0 shares. Capital Group International, Inc.'s and Capital Guardian Trust Company's address is 11100 Santa Monica Blvd., Los Angeles, California 90025.
(17)As reported on the Schedule 13G filed February 12, 2003 by Oppenheimer Funds, Inc. and Oppenheimer Capital Income Fund. Oppenheimer Funds, Inc. reports that in regard to KMR shares, it has sole voting power over 0 shares, shared voting power over 0 shares, sole disposition power over 0 shares and shared disposition power over 3,827,803 shares. Of these 3,827,803 KMR shares, Oppenheimer Capital Income Fund has sole voting power over 2,425,000 shares, shared voting power over 0 shares, sole disposition power over 0 shares and shared disposition power over 2,425,000 shares. Oppenheimer Funds, Inc.'s address is 498 Seventh Avenue, New York, New York 10018, and Oppenheimer Capital Income Fund's address is 6803 Tucson Way, Englewood, Colorado 80112.
Equity Compensation Plan Information
The following table sets forth information regarding our equity compensation plans as of January 31, 2003. Specifically, the table refers to information regarding our Common Unit Option Plan described in Item 11. "Executive Compensation" as of January 31, 2003.
Item 13.
Item 13. Certain Relationships and Related Transactions.
Odessa Lateral
We have proposed the purchase of a certain 13-mile, 6-inch carbon dioxide pipeline lateral, referred to herein as the Odessa Lateral, from Morgan Associates Proprietary, LP for approximately $700,000. The Odessa Lateral connects to Kinder Morgan CO2 Company, L.P.'s Central Basin carbon dioxide pipeline and serves, solely, the Emmons and South Cowden carbon dioxide flooding projects located in the Permian Basin and operated by ConocoPhillips. Morgan Associates is a limited partnership controlled by Mr. William V. Morgan and his wife, Sara. Mr. and Mrs. Morgan are the parents of Michael C. Morgan, the president of our general partner and KMR. Mr. William V. Morgan was Director and Vice Chairman of our general partner and its delegate, KMR, at the time of his retirement in January 2003.
Mr. William V. Morgan, through Morgan Associates and otherwise, has been an active investor in carbon dioxide pipeline infrastructure since the mid-1980s. In 1996, prior to our current management's acquisition of our general partner in February 1997, Morgan Associates constructed the Odessa Lateral for approximately $1.3 million, entered into a long-term transportation agreement with KMCO2's ultimate predecessor in interest to transport carbon dioxide via the Odessa Lateral and entered into an operating agreement with KMCO2's ultimate predecessor in interest. Subsidiaries of Shell Oil Company and Mobil Corporation initially provided the carbon dioxide that was ultimately sold to the South Cowden and Emmons projects. Currently, KMCO2 sells to ConocoPhillips carbon dioxide used in the Emmons and South Cowden carbon dioxide flooding projects.
In 1998, we contributed our Central Basin Pipeline, our operator's interest under the operating agreement and our rights and obligations under the transportation agreement to Shell CO2 Company, Ltd., a joint venture owned 80% by Shell Oil Company and 20% by us. In April 2000, Shell Oil Company elected to sell its 80% interest in Shell CO2 Company, Ltd. and we successfully won the bid and acquired such interest. We renamed Shell CO2 Company, Ltd. as Kinder Morgan CO2 Company, L.P., and we own a 98.9899% limited partner interest in KMCO2 and our general partner owns a direct 1.0101% general partner interest. KMCO2 operates and transports carbon dioxide via the Odessa Lateral, and following our acquisition of Shell's joint-venture interest, our relationship with Morgan Associates in respect of the Odessa Lateral has returned to the 1998 pre-joint venture level.
In late 2002, ConocoPhillips approached KMCO2 to discuss transferring some volumes that it was obligated to take or pay for from KMCO2 at Emmons to another carbon dioxide flooding project it had in the Permian Basin. KMCO2 was receptive to the proposal. However, any such transfer of volumes required the approval of Morgan Associates. In the first quarter of 2003, following Mr. Morgan's retirement, KMCO2 approached Morgan Associates regarding such consent and the need to compensate Morgan Associates for any volumes transferred off of the Odessa Lateral. The two parties agreed to pursue compensating Morgan Associates by having KMCO2 acquire the Odessa Lateral from Morgan Associates.
The estimated purchase price was arrived at as follows: Pursuant to the transportation agreement, KMCO2 is obligated to pay to Morgan Associates a demand fee, plus a fee on volumes transported (or a minimum transport or pay amount in the event the fee to be received for transported volumes does not exceed such minimum amount) through the Odessa Lateral to the Emmons and South Cowden carbon dioxide flooding projects. Accordingly, the estimated purchase price was arrived at by discounting back, using a commercially reasonable discount rate, the remaining demand fees, plus the remaining minimum transport or pay amounts under Morgan Associates' transportation contracts with KMCO2 on the Odessa Lateral.
Mr. Michael C. Morgan abstained from all negotiations related to the Odessa Lateral. The transaction is subject to the approval of the Boards of Directors of our general partner and KMR. We expect the transaction to close by the end of March 2003.
For more information on our related party transactions, see Note 12 of the Notes to the Consolidated Financial Statements included elsewhere in this report.
Item 14.
Item 14. Controls and Procedures.
Within the 90-day period prior to the filing of this report, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-14(c) under the Securities Exchange Act of 1934. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective. No significant changes were made in our internal controls or in other factors that could significantly affect these controls and procedures subsequent to the date of their evaluation.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a)(1) and (2) Financial Statements and Financial Statement Schedules
See "Index to Financial Statements" set forth on page 89.
(a)(3) Exhibits
*2.1 -- Purchase and Sale Agreement between Intergen (North America), Inc. and Kinder Morgan Energy Partners, L.P. dated December 15, 2001 (filed as Exhibit 2.1 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed on March 15, 2002). *2.2 -- First Supplement to Purchase and Sale Agreement between Intergen (North America), Inc. and Kinder Morgan Energy Partners, L.P. dated February 28, 2002 (filed as Exhibit 2.2 to Kindger Morgan Energy Partners, L.P. Form 8-K, filed on March 15, 2002). *3.1 -- Third Amended and Restated Agreement of Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2001, filed on August 9, 2001). *4.1 -- Specimen Certificate evidencing Common Units representing Limited Partner Interests (filed as Exhibit 4.1 to Amendment No. 1 to Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4, file No. 333-44519, filed on February 4, 1998). *4.2 -- Indenture dated as of January 29, 1999 among Kinder Morgan Energy Partners, L.P., the guarantors listed on the signature page thereto and U.S. Trust Company of Texas, N.A., as trustee, relating to Senior Debt Securities (filed as Exhibit 4.1 to the Partnership's Current Report on Form 8-K filed February 16, 1999 (the "February 16, 1999 Form 8-K")). *4.3 -- First Supplemental Indenture dated as of January 29, 1999 among Kinder Morgan Energy Partners, L.P., the subsidiary guarantors listed on the signature page thereto and U.S. Trust Company of Texas, N.A., as trustee, relating to $250,000,000 of 6.30% Senior Notes due February 1, 2009 (filed as Exhibit 4.2 to the February 16, 1999 Form 8-K). *4.4 -- Second Supplemental Indenture dated as of September 30, 1999 among Kinder Morgan Energy Partners, L.P. and U.S. Trust Company of Texas, N.A., as trustee, relating to release of subsidiary guarantors under the $250,000,000 of 6.30% Senior Notes due February 1, 2009 (filed as Exhibit 4.4 to the Partnership's Form 10-Q for the quarter ended September 30, 1999 (the "1999 Third Quarter Form 10-Q")). *4.5 -- Indenture dated March 22, 2000 between Kinder Morgan Energy Partners, L.P. and First Union National Bank, as Trustee (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4 (file no. 333-35112) filed on April 19, 2000 (the "April 2000 Form S-4")). *4.6 -- Form of 8% Note (contained in the Indenture filed as Exhibit 4.1 to the April 2000 Form S-4). *4.7 -- Indenture dated November 8, 2000 between Kinder Morgan Energy Partners, L.P. and First Union National Bank, as Trustee (filed as Exhibit 4.8 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2001). *4.8 -- Form of 7.50% Notes due November 1, 2010 (contained in the Indenture filed as Exhibit 4.8 to the Kinder Morgan Energy Partners, L.P. Form 10-K for 2001). *4.9 -- Indenture dated January 2, 2001 between Kinder Morgan Energy Partners and First Union National Bank, as trustee, relating to Senior Debt Securities (including form of Senior Debt Securities) (filed as Exhibit 4.11 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2000). *4.10 -- Indenture dated January 2, 2001 between Kinder Morgan Energy Partners and First Union National Bank, as trustee, relating to Subordinated Debt Securities (including form of Subordinated Debt Securities) (filed as Exhibit 4.12 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2000). *4.11 -- Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 6.75% Notes due March 15, 2011 and the 7.40% Notes due March 15, 2031 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed on March 14, 2001). *4.12 -- Specimen of 6.75% Notes due March 15, 2011 in book-entry form (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed on March 14, 2001).
*4.13 -- Specimen of 7.40% Notes due March 15, 2031 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed on March 14, 2001). *4.14 -- Certificate of Vice President and Chief Financial Officer of Kinder Morgan Energy Partners, L.P. establishing the terms of the 7.125% Notes due March 15, 2012 and the 7.750% Notes due March 15, 2032 (filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended March 31, 2002, filed on May 10, 2002). *4.15 -- Specimen of 7.125% Notes due March 15, 2012 in book-entry form (filed as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended March 31, 2002, filed on May 10, 2002). *4.16 -- Specimen of 7.750% Notes due March 15, 2032 in book-entry form (filed as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended March 31, 2002, filed on May 10, 2002). *4.17 -- Form of Indenture dated August 19, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to the Kinder Morgan Energy Partners, L.P.'s Registration Statement on Form S-4 (Registration No. 333-100346) filed on October 4, 2002 (the "October 4, 2002 Form S-4")). *4.18 -- Form of First Supplemental Indenture to Indenture dated August 19, 2002, dated August 23, 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.2 to the October 4, 2002 Form S-4). *4.19 -- Form of 5.35% Note and Form of 7.30% Note (contained in the Indenture filed as Exhibit 4.1 to the October 4, 2002 Form S-4). 4.20 -- Certain instruments with respect to long-term debt of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries which relate to debt that does not exceed 10% of the total assets of Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. sec.229.601. Kinder Morgan Energy Partners, L.P. hereby agrees to furnish supplementally to the Securities and Exchange Commission a copy of each such instrument upon request. *4.21 -- Form of Senior Indenture between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association (filed as Exhibit 4.2 to the Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-3 (Registration No. 333-102961) filed on February 4, 2003 (the "February 4, 2003 Form S-3")). *4.22 -- Form of Senior Note of Kinder Morgan Energy Partners, L.P. (included in the Form of Senior Indenture filed as Exhibit 4.2 to the February 4, 2003 Form S-3). *4.23 -- Form of Subordinated Indenture between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National Association (filed as Exhibit 4.4 to the February 4, 2003 Form S-3). *4.24 -- Form of Subordinated Note of Kinder Morgan Energy Partners, L.P. (included in the Form of Subordinated Indenture filed as Exhibit 4.4 to the February 4, 2003 Form S-3). *10.1 -- Kinder Morgan Energy Partners, L.P. Common Unit Option Plan (filed as Exhibit 10.6 to the Kinder Morgan Energy Partners, L.P. 1997 Form 10-K). *10.2 -- Kinder Morgan Energy Partners, L.P. Executive Compensation Plan (filed as Exhibit 10 to the Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 1997). *10.3 -- Employment Agreement dated April 20, 2000, by and among Kinder Morgan, Inc., Kinder Morgan G.P., Inc. and Michael C. Morgan (filed as Exhibit 10(b) to Kinder Morgan, Inc.'s Form 10-Q for the quarter ended March 31, 2000). *10.4 -- Delegation of Control Agreement among Kinder Morgan Management, LLC, Kinder Morgan G.P., Inc. and Kinder Morgan Energy Partners, L.P. and its operating partnerships (filed as Exhibit 10.1 to the Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2001). *10.5 -- Retention Agreement dated January 17, 2002, by and between Kinder Morgan, Inc. and C. Park Shaper (filed as Exhibit 10(l) to Kinder Morgan, Inc.'s Annual Report on Form 10-K for the period ending December 31, 2001). 10.6 -- 364-day Credit Agreement dated as of October 15, 2002 among Kinder Morgan Energy Partners, L.P., the lenders party thereto and Wachovia Bank, National Association as Administrative Agent. 10.7 -- Modification of 364-day Credit Agreement Commitment dated effective as of December 12, 2002 among Kinder Morgan Energy Partners, L.P., Credit Suisse First Boston and Wachovia Bank, National Association, as Administrative Agent. 11.1 -- Statement re: computation of per share earnings. 21.1 -- List of Subsidiaries. 23.1 -- Consent of PricewaterhouseCoopers LLP. 99.1 -- Chief Executive Officer Certification.
99.2 -- Chief Financial Officer Certification. - ----------
* 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 dated October 28, 2002 on Form 8-K was filed on October 28, 2002, pursuant to Item 9 of that form. We provided notice that we, along with Kinder Morgan, Inc., 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 presentations during the week of October 28, 2002 at various meetings with investors, analysts and others to discuss the third quarter 2002 and year-to-date third quarter 2002 financial results, business plans and objectives of us, Kinder Morgan, Inc. and Kinder Morgan Management, LLC. Notice was also given that interested parties would be able to view the materials presented at the meetings by visiting Kinder Morgan, Inc.'s website at: http://www.kindermorgan.com/investor_relations/presentations/.
Page ---- KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
Report of Independent Accountants................................... 90
Consolidated Statements of Income for the years ended December 31, 2002, 2001, and 2000.................................. 91
Consolidated Statements of Comprehensive Income for the years ended December 31, 2002, 2001, and 2000............................ 92
Consolidated Balance Sheets as of December 31, 2002 and 2001....... 93
Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001, and 2000.................................. 94
Consolidated Statements of Partners' Capital for the years ended December 31, 2002, 2001, and 2000.................................. 95
Notes to Consolidated Financial Statements.......................... 96
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, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management; our responsibility is to express an opinion on these financial statements 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 8 to the consolidated financial statements, the Partnership changed its method of accounting for goodwill and other intangible assets effective January 1, 2002.
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.
PricewaterhouseCoopers LLP
Houston, Texas February 21, 2003
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31, 2002 2001 2000 ------- -------- -------- (In thousands except per unit amounts) Revenues Natural gas sales................. $2,740,518 $1,627,037 $ 10,196 Services.......................... 1,272,640 1,161,643 726,462 Product sales and other........... 223,899 157,996 79,784 ---------- ---------- ---------- 4,237,057 2,946,676 816,442 ---------- ---------- ---------- Costs and Expenses Gas purchases and other costs of sales........................... 2,704,295 1,657,689 124,641 Operations and maintenance........ 379,827 356,654 164,379 Fuel and power.................... 86,413 73,188 43,216 Depreciation and amortization..... 172,041 142,077 82,630 General and administrative........ 118,857 109,293 64,427 Taxes, other than income taxes.... 51,326 43,947 21,588 ---------- --------- ---------- 3,512,759 2,382,848 500,881 ---------- --------- ----------
Operating Income.................... 724,298 563,828 315,561
Other Income (Expense) Earnings from equity investments.. 89,258 84,834 71,603 Amortization of excess cost of equity investments.............. (5,575) (9,011) (8,195) Interest, net..................... (176,460) (171,457) (93,284) Other, net........................ 1,698 1,962 14,584 Minority Interest................... (9,559) (11,440) (7,987) --------- ---------- -----------
Income Before Income Taxes.......... 623,660 458,716 292,282 Income Taxes........................ 15,283 16,373 13,934 --------- ---------- -----------
Net Income.......................... $608,377 $442,343 $278,348 ========= ========= ==========
Calculation of Limited Partners' Interest in Net Income: Net Income.......................... $608,377 $442,343 $278,348 Less: General Partner's interest in Net Income.......................... (270,816) (202,095) (109,470) --------- --------- --------- Limited Partners' interest in Net Income.............................. $337,561 $240,248 $168,878 ========= ========= =========
Basic Limited Partners' Net Income per Unit:........................... $ 1.96 $ 1.56 $ 1.34 ========= ========= =========
Diluted Limited Partners' Net Income per Unit:........................... $ 1.96 $ 1.56 $ 1.34 ========= ========= ========= Weighted Average Number of Units used in Computation of Limited Partners' Net Income per Unit: Basic............................. 172,017 153,901 126,212 ========= ========= =========
Diluted........................... 172,186 154,110 126,300 ========= ========= =========
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
Year Ended December 31, 2002 2001 2000 ------- ------- ------ (In thousands)
Net Income............................... $608,377 $442,343 $ 278,348 Cumulative effect transition adjustment.. -- (22,797) -- Change in fair value of derivatives used for hedging purposes................. (116,560) 35,162 -- Reclassification of change in fair value of derivatives to net income......... 7,477 51,461 -- --------- --------- --------- Comprehensive Income..................... $499,294 $ 506,169 $ 278,348 ======== ========== =========
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, -------------------------- 2002 2001 --------- ---------- (Dollars in thousands)
ASSETS Current Assets Cash and cash equivalents............. $ 41,088 $ 62,802 Accounts and notes receivable Trade.............................. 457,583 215,860 Related parties.................... 17,907 52,607 Inventories Products........................... 4,722 2,197 Materials and supplies............. 7,094 6,212 Gas imbalances........................ 25,488 15,265 Gas in underground storage............ 11,029 18,214 Other current assets.................. 104,479 194,886 ----------- ---------- 669,390 568,043 ------- ---------- Property, Plant and Equipment, net...... 6,244,242 5,082,612 Investments............................. 311,044 440,518 Notes receivable........................ 3,823 3,095 Goodwill................................ 856,940 546,734 Other intangibles, net.................. 17,324 16,663 Deferred charges and other assets....... 250,813 75,001 ---------- ----------- TOTAL ASSETS............................ $8,353,576 $6,732,666 ========== ===========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities Accounts payable Trade................................. $ 373,368 $ 111,853 Related parties....................... 43,742 9,235 Current portion of long-term debt........ - 560,219 Accrued interest......................... 52,500 34,099 Deferred revenues........................ 4,914 2,786 Gas imbalances........................... 40,092 34,660 Accrued other liabilities................ 298,711 209,852 ---------- ----------- 813,327 962,704 ---------- ----------- Long-Term Liabilities and Deferred Credits Long-term debt Outstanding........................... 3,659,533 2,237,015 Market value of interest rate swaps 166,956 (5,441) ---------- ----------- 3,826,489 2,231,574 Deferred revenues........................ 25,740 29,110 Deferred income taxes.................... 30,262 38,544 Other long-term liabilities and deferred credits....................... 199,796 246,464 ---------- ---------- 4,082,287 2,545,692 ---------- ---------- Commitments and Contingencies (Notes 13 and 16) Minority Interest.......................... 42,033 65,236 ---------- ---------- Partners' Capital Common Units (129,943,218 and 129,855,018 units issued and outstanding at December 31, 2002 and 2001, respectively)............................ 1,844,553 1,894,677
Class B Units (5,313,400 and 5,313,400 units issued and outstanding at December 31, 2002 and 2001, respectively)............................. 123,635 125,750
i-Units (45,654,048 and 30,636,363 units issued and outstanding at December 31, 2002 and 2001, respectively)............................. 1,420,898 1,020,153 General Partner........................... 72,100 54,628 Accumulated other comprehensive income.... (45,257) 63,826 ----------- ---------- 3,415,929 3,159,034 TOTAL LIABILITIES AND PARTNERS' CAPITAL. $8,353,576 $6,732,666 =========== ==========
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
Year Ended December 31, ---------------------------------- 2002 2001 2000 -------- -------- -------- (In thousands) Cash Flows From Operating Activities Net income............................ $ 608,377 $ 442,343 $ 278,348 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization....... 172,041 142,077 82,630 Amortization of excess cost of equity investments................. 5,575 9,011 8,195 Earnings from equity investments.... (89,258) (84,834) (71,603) Distributions from equity investments 77,735 68,832 47,512 Changes in components of working capital: Accounts receivable............... (177,240) 174,098 6,791 Other current assets.............. (7,583) 22,033 (6,872) Inventories....................... (1,713) 22,535 (1,376) Accounts payable.................. 288,712 (183,179) (8,374) Accrued liabilities............... 26,232 (47,692) 26,479 Accrued taxes..................... 2,379 8,679 (1,302) Rate refunds settlement............. (100) (100) (52,467) Other, net.......................... (35,462) 7,358 (6,394) ----------- ----------- ----------- Net Cash Provided by Operating Activities........................... 869,695 581,161 301,567 ----------- ----------- ----------- Cash Flows From Investing Activities Acquisitions of assets.............. (908,511) (1,523,454) (1,008,648) Additions to property, plant and equipment for expansion and maintenance projects............... (542,235) (295,088) (125,523) Sale of investments, property, plant and equipment, net of removal costs.............................. 13,912 9,043 13,412 Acquisitions of investments......... (1,785) -- (79,388) Contributions to equity investments. (10,841) (2,797) (375) Other............................... (1,420) (6,597) 2,956 ----------- ----------- ----------- Net Cash Used in Investing Activities. (1,450,880) (1,818,893) (1,197,566) ----------- ----------- ----------- Cash Flows From Financing Activities Issuance of debt.................... 3,803,414 4,053,734 2,928,304 Payment of debt..................... (2,985,322) (3,324,161) (1,894,904) Loans to related party.............. -- (17,100) -- Debt issue costs.................... (17,006) (8,008) (4,298) Proceeds from issuance of common units.............................. 1,586 4,113 171,433 Proceeds from issuance of i-units... 331,159 996,869 -- Contributions from General Partner.. 3,353 11,716 7,434 Distributions to partners: Common units...................... (306,590) (268,644) (194,691) Class B units..................... (12,540) (8,501) -- General Partner................... (253,344) (181,198) (91,366) Minority interest................. (9,668) (14,827) (7,533) Other, net.......................... 4,429 (2,778) 887 ----------- ----------- ----------- Net Cash Provided by Financing Activities........................... 559,471 1,241,215 915,266 ----------- ----------- ----------- Increase (Decrease) in Cash and Cash Equivalents.......................... (21,714) 3,483 19,267 Cash and Cash Equivalents, beginning of period............................ 62,802 59,319 40,052 ----------- ----------- ----------- Cash and Cash Equivalents, end of period............................... $41,088 $62,802 $59,319 =========== =========== =========== Noncash Investing and Financing Activities: Assets acquired by the issuance of $ -- $ -- $ 179,623 units.............................. Assets acquired by the assumption of liabilities........................ 213,861 293,871 333,301 Supplemental disclosures of cash flow information: Cash paid during the year for Interest (net of capitalized interest).......................... 161,840 165,357 88,821 Income taxes........................ 1,464 2,168 1,806
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization
General
Kinder Morgan Energy Partners, L.P., the "Partnership", is a Delaware limited partnership formed in August 1992. We own and manage a diversified portfolio of energy transportation and storage assets. We provide services to our customers and create value for our unitholders primarily through the following activities:
o transporting, storing and processing refined petroleum products;
o transporting, storing and selling natural gas;
o transporting and selling carbon dioxide for use in, and selling crude oil produced from, enhanced oil recovery operations; and
o 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 tax benefits of 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:
o Products Pipelines;
o Natural Gas Pipelines;
o CO2 Pipelines; and
o Terminals.
For more information on our reportable business segments, see Note 15.
Kinder Morgan, Inc.
Kinder Morgan, Inc., a Kansas corporation, is the sole stockholder of Kinder Morgan (Delaware), Inc. Kinder Morgan (Delaware), Inc., a Delaware corporation, is the sole stockholder of our general partner, Kinder Morgan G.P., Inc. Kinder Morgan, Inc. 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 energy transportation and storage companies in the United States, operating, either for itself or on our behalf, more than 30,000 miles of natural gas and products pipelines. It also has significant retail distribution, electric generation and terminal assets. At December 31, 2002, KMI and its consolidated subsidiaries owned, through its general and limited partner interests, an approximate 19.2% interest in us. As a result of owning this significant interest in us, KMI receives a substantial portion of its earnings from returns on this investment.
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 and, pursuant to a 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 KMR cannot take certain specified actions without the approval of our general partner. Under
the delegation of control agreement, KMR manages and controls our business and affairs and the business and affairs of our operating limited partnerships and their subsidiaries. Furthermore, in accordance with its limited liability company agreement, KMR's activities are limited to being a limited partner in, and managing and controlling the business and affairs of us, our operating limited partnerships and their subsidiaries.
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 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. At December 31, 2002, KMR and its consolidated subsidiary owned approximately 25.2% of our outstanding limited partner units. KMR receives all of its earnings from returns on this investment.
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.
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:
o the amounts we report for assets and liabilities;
o our disclosure of contingent assets and liabilities at the date of the financial statements; and
o 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, the fair values used to determine possible asset impairment charges, 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.
Cash Equivalents
We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less.
Accounts Receivables
Our policy for determining an appropriate allowance for doubtful accounts varies according to the type of business being conducted and the customers being served. An allowance for doubtful accounts is charged to expense monthly, generally using a percentage of revenue or receivables, based on a historical analysis of uncollected amounts, adjusted as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. The following tables show the balance in the allowance for doubtful accounts and activity for the years ended December 31, 2002, 2001 and 2000.
Valuation and Qualifying Accounts (In thousands)
Year Ended December 31, 2002 ---------------------------------------------------------------- Additions Additions Balance at charged to charged to Balance at beginning costs and other end of of Period expenses accounts(1) Deductions(2) period ---------- ---------- ----------- ------------- ---------- Allowance for Doubtful Accounts..... $ 7,556 $ 822 $ 4 $ (290) $ 8,092 - ----------
(1)Additions represent the allowance recognized when we acquired IC Terminal Holdings Company and Consolidated Subsidiaries.
(2)Deductions represent the write-off of receivables and the revaluation of the allowance account.
Year Ended December 31, 2001 ---------------------------------------------------------------- Additions Additions Balance at charged to charged to Balance at beginning costs and other end of of Period expenses accounts(1) Deductions(2) period ---------- ---------- ----------- ------------- ---------- Allowance for Doubtful Accounts..... $ 4,151 $ 3,641 $ 1,362 $(1,598) $ 7,556 - ----------
(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.
Year Ended December 31, 2000 ---------------------------------------------------------------- Additions Additions Balance at charged to charged to Balance at beginning costs and other end of of Period expenses accounts(1) Deductions(2) period ---------- ---------- ----------- ------------- ---------- Allowance for Doubtful Accounts..... $ 6,717 $ -- $ 2,718 $(5,284) $ 4,151 - ----------
(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.
In addition, at December 31, 2002, our balance of Accrued other current liabilities in the accompanying consolidated balance sheet included approximately $38.7 million related to customer prepayments.
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.
Our exploration and production activities are accounted for under the successful efforts method of accounting. Under this method, costs of productive wells and development dry holes, both tangible and intangible, as well as productive acreage are capitalized and amortized on the unit-of-production method. 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 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.
On January 1, 2002, we adopted Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" and we now evaluate the impairment of our long-lived assets in accordance with this Statement. This statement retains the requirements of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of", 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. 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.
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
Effective January 1, 2002, we adopted SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets". 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 cost over the 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. In addition, 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.
SFAS No. 142 supercedes Accounting Principles Board Opinion No. 17 and requires that goodwill no longer be amortized, but instead 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 or as changes in circumstances require. 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. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets". An intangible asset with an indefinite useful life can no longer be amortized until its useful life becomes determinable. In addition, 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.
These accounting pronouncements required that we prospectively cease amortization of all intangible assets having indefinite useful economic lives. Such assets, including goodwill, are not to be amortized until their lives are determined to be finite. In addition, a recognized intangible asset with an indefinite useful life and goodwill should be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We completed this initial transition impairment test in June 2002 and determined that our goodwill and such intangible assets were not impaired as of January 1, 2002.
Prior to January 1, 2002, we amortized the excess cost over the underlying net asset book value of our 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 "Business Combinations". 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 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 in consolidated affiliates was approximately $716.6 million as of December 31, 2002 and $546.7 million as of December 31, 2001. Such amounts are included within goodwill on our accompanying consolidated balance sheets. Our total unamortized excess cost over underlying fair value of net assets accounted for under the equity method was approximately $140.3 million as of December 31, 2002 and December 31, 2001. Per our adoption of SFAS No. 142, the December 31, 2002 balance is included within goodwill on our accompanying consolidated balance sheet and the December 31, 2001 balance is included within investments on our accompanying consolidated balance sheet.
In addition to our annual impairment test, 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 in accordance with Accounting Principles Board Opinion No. 18 "The Equity Method of Accounting for Investments in Common Stock". At December 31, 2002, we believed no such impairment had occurred and no reduction in estimated useful lives was warranted.
For more information on our acquisitions, see Note 3. For more information on our investments, see Note 7.
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 liquids terminal tank rental revenue ratably over the contract period. We recognize liquids terminal through-put revenue based on volumes received or volumes delivered depending on the customer contract. Liquids 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.
Capitalized Interest
We capitalize interest expense during the new construction or upgrade of qualifying assets. Interest expense
capitalized in 2002, 2001 and 2000 was $5.8 million, $3.1 million and $2.5 million, respectively.
Unit-Based Compensation
SFAS No. 123, "Accounting for Stock-Based Compensation", encourages, but does not require, entities to adopt the fair value method of accounting for stock or unit-based compensation plans. As allowed under SFAS No. 123, 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. Accordingly, compensation expense is not recognized for common unit options unless the options are granted at an exercise price lower than the market price on the grant date. Pro forma information regarding changes in net income and per unit data, if the accounting prescribed by SFAS No. 123 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. For more information on unit-based compensation, see Note 13.
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, which do not contribute to current or future revenue generation. We do not discount environmental liabilities to a 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 recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action.
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. In December 2002, after a thorough review of any potential environmental issues that could impact our assets or operations and of our need to correctly record all related environmental contingencies, we recognized a $0.3 million non-recurring reduction in environmental expense and in our overall accrued environmental liability, and we included this amount within Other, net in the accompanying Consolidated Statement of Income for 2002. The $0.3 million income item resulted from the necessity of properly adjusting and realigning our environmental expenses and accrued liabilities between our reportable business segments, specifically between our Products Pipelines and our Terminals business segments. The $0.3 million reduction in environmental expense resulted in a $15.7 million non-recurring loss to our Products Pipelines business segment and a $16.0 million non-recurring gain to our Terminals business segment.
Legal
We are subject to litigation and regulatory proceedings 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 orders, 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. In general, we expense legal costs as incurred. When we identify specific litigation that is expected to continue for a significant period of time and require substantial expenditures, we identify a range of possible costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement. If no amount within this range is a better estimate than any other amount, we record a liability equal to the low end of the range. Any such liability recorded is revised as better information becomes available.
Pension
We are required to make assumptions and estimates regarding the accuracy of our pension investment returns. Specifically, these include:
o our investment return assumptions;
o the significant estimates on which those assumptions are based; and
o the potential impact that changes in those assumptions could have on our reported results of operations and cash flows.
We consider our overall pension liability exposure to be minimal in relation to the value of our total consolidated assets and net income. However, in accordance with SFAS No. 87, "Employers' Accounting for Pensions", a component of our net periodic pension cost includes the return on pension plan assets, including both realized and unrealized changes in the fair market value of pension plan assets.
A source of volatility in pension costs comes from this inclusion of unrealized or market value gains and losses on pension assets as part of the components recognized as pension expense. To prevent wide swings in pension expense from occurring because of one-time changes in fund values, SFAS No. 87 allows for the use of an actuarial computed "expected value" of plan asset gains or losses to be the actual element included in the determination of pension expense. The actuarial derived expected return on pension assets not only employs an expected rate of return on plan assets, but also assumes a market-related value of plan assets, which is a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. As required, we disclose the weighted average expected long-run rate of return on our plan assets, which is used to calculate our plan assets' expected return. For more information on our pension disclosures, see Note 10.
Gas Imbalances and Gas Purchase Contracts
We value gas imbalances due to or due from interconnecting pipelines at the lower of cost or market. Gas imbalances represent the difference between customer nominations and actual gas receipts from and gas deliveries to our interconnecting pipelines under various Operational Balancing Agreements. Natural gas imbalances are settled in cash or made up in-kind subject to the pipelines' various terms.
Minority Interest
As of December 31, 2002, minority interest consists of the following:
o the 1.0101% general partner interest in our operating partnerships;
o the 0.5% special limited partner interest in SFPP, L.P.;
o the 50% interest in Globalplex Partners, a Louisiana joint venture owned 50% and controlled by Kinder Morgan Bulk Terminals, Inc.;
o 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; and
o the 33 1/3% interest in International Marine Terminals, a Louisiana partnership owned 66 2/3% and controlled by Kinder Morgan Operating L.P. "C".
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 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 each of the years ended December 31, 2002 and 2001, the only difference between our net income and our comprehensive income was the unrealized gain or loss on derivatives utilized for hedging purposes. There was no difference between our net income and our comprehensive income for the year ended December 31, 2000. For more information on our risk management activities, see Note 14.
Net Income Per Unit
We compute Basic Limited Partners' Net Income per Unit by dividing Limited Partners' 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.
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.
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.
Effective January 1, 2001, we adopted SFAS No. 133, as amended by SFAS 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.
Furthermore, if the derivative transaction qualifies for and is designated as a normal purchase and sale, it is exempted from the fair value accounting requirements of SFAS No. 133 and is accounted for using traditional accrual accounting. Our derivatives that hedge our commodity price risks involve our normal business activities, which include the sale of natural gas, natural gas liquids, oil and carbon dioxide, and these derivatives have been designated as cash flow hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives that hedge
exposure to variable cash flows of forecasted transactions as cash flow hedges and the effective portion of the derivative's gain or loss is initially reported as a component of other comprehensive income (outside earnings) and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of the gain or loss is reported in earnings immediately. See Note 14 for more information on our risk management activities.
3. Acquisitions and Joint Ventures
During 2000, 2001 and 2002, 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 results of operations from these acquisitions are included in our consolidated financial statements from the date of acquisition.
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, bulk de-icing salt and fertilizer. The Dakota terminal, located in St. Paul, Minnesota, primarily handles bulk de-icing salt and grain products.
Our purchase price and our allocation to assets acquired and liabilities assumed was as follows (in thousands):
Purchase price: Common units issued.................... $23,319 Cash paid, including transaction costs 757 Liabilities assumed.................... 6,960 ------- Total purchase price................... $31,036 ======= Allocation of purchase price: Current assets......................... $ 1,764 Property, plant and equipment.......... 15,201 Goodwill............................... 14,071 ------- $31,036 =======
Kinder Morgan CO2 Company, L.P.
Effective April 1, 2000, we acquired the remaining 78% limited partner interest and the 2% general partner interest in Shell CO2 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 CO2 Company, L.P., and going forward from April 1, 2000, we have included its results as part of our consolidated financial statements under our CO2 Pipelines business segment. As is the case with all of our operating partnerships, we own a 98.9899% limited partner interest in KMCO2 and our general partner owns a direct 1.0101% general partner interest.
Our purchase price and our allocation to assets acquired and liabilities assumed was as follows (in thousands):
Purchase price: Cash paid, including transaction costs $212,081 Liabilities assumed................... 37,080 -------- Total purchase price.................. $249,161 ======== Allocation of purchase price: Current assets........................ $ 51,870 Property, plant and equipment......... 230,332 Goodwill.............................. 45,751 Equity investments.................... (79,693)(a) Deferred charges and other assets..... 901 -------- $249,161 ========
(a) Represents reclassification of our original 20% equity investment in Shell CO2 Company, L.P. of ($86.7) million and our allocation of purchase price to the equity investment purchased in our acquisition of Shell CO2 Company, L.P. of $7.0 million.
Devon Energy
Effective June 1, 2000, KMCO2 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 CO2 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 our allocation to assets acquired and liabilities assumed was as follows (in thousands):
Purchase price: Cash paid, including transaction costs $53,435 ------- Total purchase price.................. $53,435 ======= Allocation of purchase price: Property, plant and equipment......... $53,435 ------- $53,435 =======
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 our allocation to assets acquired and liabilities assumed was as follows (in thousands):
Purchase price: Cash paid, including transaction costs $45,696 Liabilities assumed................... 11,462 ------- Total purchase price.................. $57,158 ======= Allocation of purchase price: Current assets........................ $19,862 Property, plant and equipment......... 37,289 Deferred charges and other assets..... 7 ------- $57,158 =======
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 from Shell Canada Limited for approximately $8.1 million. In January 2002, we purchased an additional 10% ownership interest from NOVA Chemicals Corporation for approximately $29 million. The January 2002 transaction was made effective December 31, 2001. We now own approximately 44.8% of the Cochin Pipeline System and the remaining interests are owned by subsidiaries of BP Amoco and ConocoPhillips. We record our proportional share of joint venture revenues and expenses and cost of joint venture assets with respect to the Cochin Pipeline System as part of our Products Pipelines business segment.
Our purchase price and our allocation to assets acquired and liabilities assumed was as follows (in thousands):
Purchase price: Cash paid, including transaction costs $157,613 -------- Total purchase price.................. $157,613 ======== Allocation of purchase price: Property, plant and equipment......... $157,613 -------- $157,613 ========
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 $118.1 million and the assumption of approximately $18.0 million of liabilities. The acquisition includes two liquid bulk storage terminals in New Orleans, Louisiana and Cincinnati, Ohio.
Our purchase price and our allocation to assets acquired and liabilities assumed was as follows (in thousands):
Purchase price: Cash paid, including transaction costs $118,112 Liabilities assumed................... 17,976 -------- Total purchase price.................. $136,088 ======== Allocation of purchase price: Current assets........................ $ 1,137 Property, plant and equipment......... 70,610 Goodwill.............................. 64,304 Deferred charges and other assets..... 37 -------- $136,088 ========
MKM Partners, L.P.
On December 28, 2000, we announced that KMCO2 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 KMCO2 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 our allocation to assets acquired and liabilities assumed was as follows (in thousands):
Purchase price: Cash paid, including transaction costs $34,163 ------- Total purchase price.................. $34,163 ======= Allocation of purchase price: Equity investments.................... $34,163 ------- $34,163 =======
2000 Kinder Morgan, Inc. Asset Contributions
Effective December 31, 2000, we acquired $621.7 million of assets from KMI. 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. 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. 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. This transaction was approved unanimously by the independent directors of our general partner, with the benefit of advice of independent legal and financial advisors, including a fairness opinion from the investment banking firm A.G. Edwards & Sons, Inc.
Our purchase price and our allocation to assets acquired and liabilities assumed was as follows (in thousands):
Purchase price: Common and Class B units issued....... $156,305 Cash paid, including transaction costs 192,677 Liabilities assumed................... 272,718 -------- Total purchase price.................. $621,700 ======== Allocation of purchase price: Current assets........................ $255,320 Property, plant and equipment......... 137,145 Intangible-leasehold Value............ 179,390 Equity investments.................... 45,225 Deferred charges and other assets..... 4,620 -------- $621,700 ========
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 our allocation to assets acquired and liabilities assumed was as follows (in thousands):
Purchase price: Cash paid, including transaction costs $11,233 Liabilities assumed................... 1,788 ------- Total purchase price.................. $13,021 ======= Allocation of purchase price: Current assets........................ $ 4,465 Property, plant and equipment......... 8,556 ------- $13,021 =======
Domestic Pipelines and Terminals Businesses from GATX
During the first quarter of 2001, we acquired GATX Corporation's domestic pipeline and terminal businesses. The acquisition included:
o Kinder Morgan Liquids Terminals LLC (formerly GATX Terminals Corporation), effective January 1, 2001;
o Central Florida Pipeline LLC (formerly Central Florida Pipeline Company), effective January 1, 2001; and
o CALNEV Pipe Line LLC (formerly CALNEV Pipe Line Company), effective March 30, 2001.
KMLT's assets then included 12 terminals, located across the United States, which stored 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 $1,233.4 million, consisting of $975.4 million in cash, $134.8 million in assumed debt and $123.2 million in assumed liabilities.
Our purchase price and our allocation to assets acquired and liabilities assumed was as follows (in thousands):
Purchase price: Cash paid, including transaction costs $ 975,428 Debt assumed.......................... 134,746 Liabilities assumed................... 123,246 ---------- Total purchase price.................. $1,233,420 ========== Allocation of purchase price: Current assets........................ $ 32,364 Property, plant and equipment........ 928,736 Deferred charges and other assets.... 4,785 Goodwill............................. 267,535 ---------- $1,233,420 ==========
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 $51.7 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 $10.0 million in assumed liabilities.
Our purchase price and our allocation to assets acquired and liabilities assumed was as follows (in thousands):
Purchase price: Cash paid, including transaction costs $41,674 Liabilities assumed................... 10,055 ------- Total purchase price.................. $51,729 ======= Allocation of purchase price: Current assets........................ $ 1,970 Property, plant and equipment......... 32,467 Deferred charges and other assets..... 487 Goodwill.............................. 16,805 ------- $51,729 =======
Bulk Terminals from 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 our allocation to assets acquired and liabilities assumed was as follows (in thousands):
Purchase price: Cash paid, including transaction costs $43,622 Liabilities assumed................... 700 ------- Total purchase price.................. $44,322 ======= Allocation of purchase price: Property, plant and equipment......... $44,322 =======
Kinder Morgan Texas Pipeline
Effective July 18, 2001, we acquired, from an affiliate of Occidental Petroleum Corporation, K M Texas Pipeline, L.P., a partnership that owned 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. We merged K M Texas Pipeline, L.P. into Kinder Morgan Texas Pipeline, L.P. on August 1, 2002.
Our purchase price and our allocation to assets acquired and liabilities assumed was as follows (in thousands):
Purchase price: Cash paid, including transaction costs $359,059 Release SFAS No. 13 deferred credit previously held...................... (32,918) --------- Total purchase price................. $326,141 ======== Allocation of purchase price: Property, plant and equipment........ $326,141 -------- $326,141
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 $22.4 million, consisting of approximately $18.0 million in cash, a $3.0 million one-year note payable and approximately $1.4 million in assumed liabilities.
Our purchase price and our allocation to assets acquired and liabilities assumed was as follows (in thousands):
Purchase price: Cash paid, including transaction costs $18,035 Note payable.......................... 3,000 Liabilities assumed................... 1,364 ------- Total purchase price.................. $22,399 ======= Allocation of purchase price: Current assets........................ $ 1,658 Property, plant and equipment......... 9,867 Intangibles-Contract Rights........... 4,000 Goodwill.............................. 6,874 ------- $22,399 =======
The $6.9 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes.
Liquids Terminals from 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 $70.8 million, consisting of approximately $44.8 million in cash, $25.0 million in assumed debt and $1.0 million in assumed liabilities.
Our purchase price and our allocation to assets acquired and liabilities assumed was as follows (in thousands):
Purchase price: Cash paid, including transaction costs $44,838 Debt assumed.......................... 25,000 Liabilities assumed................... 1,000 ------- Total purchase price.................. $70,838 ======= Allocation of purchase price: Property, plant and equipment......... $70,763 Goodwill.............................. 75 ------- $70,838 =======
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.
Interests in Snyder and Diamond M Plants
On November 14, 2001, we announced that KMCO2 had purchased Mission Resources Corporation's interests in the Snyder Gasoline Plant and Diamond M Gas Plant. In December 2001, KMCO2 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. We paid approximately $20.9 million for these interests. All of these assets are located in the Permian Basin of West Texas. As a result of the acquisition, we increased our ownership interests in both plants, each of which process gas produced by the SACROC unit. The acquisition expanded our carbon dioxide-related operations and complemented our working interests in oil-producing fields located in West Texas. Currently, we own an approximate 22% ownership interest in the Snyder Gasoline Plant and a 51% ownership interest in the Diamond M Gas Plant. The acquired interests are included as part of our CO2 Pipelines business segment.
Our purchase price and our allocation to assets acquired and liabilities assumed was as follows (in thousands):
Purchase price: Cash paid, including transaction costs $20,872 ------- Total purchase price.................. $20,872 ======= Allocation of purchase price: Property, plant and equipment......... $20,872 ------- $20,872 =======
Kinder Morgan Materials Services LLC
Effective January 1, 2002, we acquired all of the equity interests of Kinder Morgan Materials Services LLC for approximately $8.9 million and the assumption of approximately $3.3 million of liabilities, including long-term debt of $0.4 million. Kinder Morgan Materials Services LLC currently operates more than 60 transload facilities in 20 states. The facilities handle dry-bulk products, including aggregates, plastics and liquid chemicals. The acquisition of Kinder Morgan Materials Services LLC expanded our growing terminal operations and is part of our Terminals business segment.
Our purchase price and our allocation to assets acquired and liabilities assumed was as follows (in thousands):
Purchase price: Cash paid, including transaction costs $ 8,916 Debt assumed.......................... 357 Liabilities assumed................... 2,967 ------- Total purchase price.................. $12,240 ======= Allocation of purchase price: Current assets........................ $ 879 Property, plant and equipment......... 11,361 ------- $12,240 =======
66 2/3% Interest in International Marine Terminals
Effective January 1, 2002, we acquired a 33 1/3% interest in International Marine Terminals, referred to herein as IMT, from Marine Terminals Incorporated. Effective February 1, 2002, we acquired an additional 33 1/3% interest in IMT from Glenn Springs Holdings, Inc. Our combined purchase price was approximately $40.5 million, including the assumption of $40 million of long-term debt. IMT is a partnership that operates a bulk terminal site in Port Sulphur, Louisiana. This terminal is a multi-purpose import and export facility, which handles approximately 8 million tons annually of bulk products including coal, petroleum coke, iron ore and barite. The acquisition complements our existing bulk terminal assets. IMT is part of our Terminals business segment.
Our purchase price and our allocation to assets acquired, liabilities assumed and minority interest was as follows (in thousands):
Purchase price: Cash received, net of transaction costs $(3,781) Debt assumed........................... 40,000 Liabilities assumed.................... 4,249 -------- Total purchase price................... $40,468 ======== Allocation of purchase price: Current assets......................... $6,600 Property, plant and equipment.......... 31,781 Deferred charges and other assets...... 139 Minority interest...................... 1,948 ------- $40,468 =======
Kinder Morgan Tejas
Effective January 31, 2002, we acquired all of the equity interests of Tejas Gas, LLC, a wholly-owned subsidiary of InterGen (North America), Inc., for an aggregate consideration of approximately $881.5 million, consisting of $727.1 million in cash and the assumption of $154.4 million of liabilities. Tejas Gas, LLC consists primarily of 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. The acquisition expands our natural gas operations within the State of Texas. The acquired assets are referred to as Kinder Morgan Tejas in this report and are included in our Natural Gas Pipelines business segment.
The allocation of our purchase price to the assets and liabilities of Kinder Morgan Tejas is preliminary, pending final purchase price adjustments that should be made in the first quarter of 2003. The total purchase price increased $49.0 million in the fourth quarter of 2002 due to adjustments in the amount of assumed liabilities related primarily to gas purchase contracts. Due to the seasonality of certain gas purchase activities, we were not able to determine the fair value of these contracts until the fourth quarter of 2002. This pre-acquisition contingency was appropriately recorded during the allocation period specified by SFAS No. 141, "Business Combinations". The allocation of our purchase price was based on an independent appraisal of fair market values as follows (in thousands):
Purchase price: Cash paid, including transaction costs $727,094 Liabilities assumed................... 154,455 -------- Total purchase price.................. $881,549 ======== Allocation of purchase price: Current assets........................ $ 56,496 Property, plant and equipment, including cushion gas ............... 674,147 Goodwill ............................. 150,906 ======== $881,549 ========
The $150.9 million of goodwill was assigned to our Natural Gas Pipelines business segment and the entire amount is expected to be deductible for tax purposes.
Milwaukee Bagging Operations
Effective May 1, 2002, we purchased a bagging operation facility adjacent to our Milwaukee, Wisconsin dry-bulk terminal for $8.5 million. The purchase enhances the operations at our Milwaukee terminal, which is capable
of handling up to 150,000 tons per year of fertilizer and salt for de-icing and livestock purposes. The Milwaukee bagging operations are included in our Terminals business segment.
Our purchase price and our allocation to assets acquired and liabilities assumed was as follows (in thousands)
Purchase price: Cash paid, including transaction costs $ 8,500 ------- Total purchase price.................. $ 8,500 ======= Allocation of purchase price: Current assets........................ $ 40 Property, plant and equipment......... 3,140 Goodwill.............................. 5,320 ------- $8,500 =======
The $5.3 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes.
Trailblazer Pipeline Company
On May 6, 2002, we acquired the remaining 33 1/3% ownership interest in Trailblazer Pipeline Company from Enron Trailblazer Pipeline Company for $68 million. We now own 100% of Trailblazer Pipeline Company. During the first quarter of 2002, we paid $12.0 million to CIG Trailblazer Gas Company, an affiliate of El Paso Corporation, in exchange for CIG's relinquishment of its rights to become a 7% to 8% equity owner in Trailblazer Pipeline Company in mid-2002. 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 current certificated capacity of 846 million cubic feet per day of natural gas.
Our purchase price and our allocation to assets acquired, liabilities assumed and minority interest was as follows (in thousands):
Purchase price: Cash paid, including transaction costs $80,125 ------- Total purchase price.................. $80,125 ======= Allocation of purchase price: Property, plant and equipment......... $41,739 Goodwill.............................. 15,000 Minority interest..................... 23,386 ------- $80,125 =======
The $15.0 million of goodwill was assigned to our Natural Gas Pipelines business segment and the entire amount is expected to be deductible for tax purposes.
Owensboro Gateway Terminal
Effective September 1, 2002, we acquired the Lanham River Terminal near Owensboro, Kentucky and related equipment for $7.7 million. As of December 31, 2002, we have paid approximately $7.2 million and established a $0.5 million liability for final purchase price settlements. The facility is one of the nation's largest storage and handling points for bulk aluminum. The terminal also handles a variety of other bulk products, including petroleum coke, lime and de-icing salt. The terminal is situated on a 92-acre site along the Ohio River, and the purchase expands our presence along the river, complementing our existing facilities located near Cincinnati, Ohio and Moundsville, West Virginia. The acquired terminal is now called the Owensboro Gateway Terminal and is included in our Terminals business segment.
Our purchase price and our allocation to assets acquired and liabilities assumed was as follows (in thousands):
Purchase price: Cash paid, including transaction costs $7,140 Purchase price reserve................ 500 Liabilities assumed................... 11 ------ Total purchase price.................. $7,651 ====== Allocation of purchase price: Current assets........................ $ 42 Property, plant and equipment......... 4,265 Intangibles-agreements................ 54 Goodwill.............................. 3,290 ------ $7,651 ======
The $3.3 million of goodwill was assigned to our Terminals business segment and the entire amount is expected to be deductible for tax purposes.
IC Terminal Holdings Company
Effective September 1, 2002, we acquired all of the shares of the capital stock of IC Terminal Holdings Company from the Canadian National Railroad. Our purchase price was approximately $17.8 million, consisting of $17.6 million and the assumption of $0.2 million in liabilities. The acquisition includes the former ICOM marine terminal in St. Gabriel, Louisiana. The St. Gabriel facility features 400,000 barrels of liquids storage capacity and a related pipeline network that serves one of the fastest growing petrochemical production areas in the country. The acquisition further expands our terminal businesses along the Mississippi River. The acquired terminal will be referred to as the Kinder Morgan St. Gabriel terminal and will be included in our Terminals business segment.
Our purchase price and our allocation to assets acquired and liabilities assumed was as follows (in thousands):
Purchase price: Cash paid, including transaction costs $17,572 Liabilities assumed................... 253 ------- Total purchase price.................. $17,825 ======= Allocation of purchase price: Current assets........................ $ 46 Property, plant and equipment......... 14,430 Investment in ICPT, LLC............... 1,785 Non-current note receivable........... 1,350 Deferred charges and other assets..... 214 ------- $17,825 =======
Pro Forma Information
The following summarized unaudited Pro Forma Consolidated Income Statement information for the twelve months ended December 31, 2002 and 2001, assumes the 2002 and 2001 acquisitions and joint ventures had occurred as of January 1, 2001. 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 2002 and 2001 acquisitions and joint ventures as of January 1, 2001 or the results which will be attained in the future. Amounts presented below are in thousands, except for the per unit amounts:
Pro Forma Year Ended December 31, ------------------------ 2002 2001 ---------- ---------- (Unaudited) Revenues........................... $4,510,960 $5,275,551 Operating Income................... 729,564 609,439 Income before extraordinary charge. 632,171 519,980 Net Income......................... 616,888 502,487 Basic and diluted Limited Partners' Net Income per unit............... $ 1.93 $ 1.60
Acquisitions Subsequent to December 31, 2002
Effective January 1, 2003, we acquired long-term lease contracts from New York-based M.J. Rudolph Corporation to operate four bulk facilities at major ports along the East Coast and in the southeastern United States. The acquisition also includes the purchase of certain assets that provide stevedoring services at these locations. The cost of the acquisition will be approximately $31.3 million. On December 31, 2002, we paid $29.9 million for the Rudolph acquisition and this amount is included with Other current assets on our accompanying balance sheet. We expect to pay the remaining approximate amount of $1.4 million during the first quarter of 2003. The acquired operations serve various terminals located at the ports of New York and Baltimore, along the Delaware River in Camden, New Jersey, and in Tampa Bay, Florida. Combined, these facilities transload nearly four million tons annually of products such as fertilizer, iron ore and salt. The acquisition expands our growing terminals business segment and complements certain of our existing terminal facilities and will be included in our Terminals business segment.
4. New Accounting Pronouncements
On January 1, 2003, we adopted SFAS No. 143, "Accounting for Asset Retirement Obligations". SFAS No. 143 requires companies to record a liability relating to the retirement and removal of assets used in their business. The liability is initially recorded at its fair 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. With respect to our Natural Gas Pipelines and Products Pipelines business segments, we have certain surface facilities that are required to be dismantled and removed, with certain site reclamation to be performed. While, in general, our right-of-way agreements do no require us to remove pipe or otherwise perform remediation upon taking the pipeline permanently out of service, some right-of-way agreements do provide for these actions. With respect to our CO2 Pipelines business segment, we generally are required to plug our oil production wells when removed from service and we anticipate recording a liability for such obligation. Our Terminals business segment has entered into certain facility leases which require removal of improvements upon expiration of the lease term. We anticipate recording a liability for such obligation. For the Natural Gas Pipelines and Products Pipelines business segments, we expect that we will be unable to reasonably estimate and record liabilities for the majority of our obligations that fall under the provisions of this statement because we cannot reasonably estimate when such obligations would be settled. For the CO2 Pipelines and Terminals business segments, the effect of adopting SFAS No. 143 is not material to the consolidated financial statements.
In April 2002, the Financial Accounting Standards Board issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections". This Statement eliminates the current requirement that gains and losses on debt extinguishment must be classified as extraordinary items in the income statement. Instead, such gains and losses will be classified as extraordinary items only if they are deemed to be unusual and infrequent, in accordance with the current GAAP criteria for extraordinary classification. In addition, SFAS No. 145 eliminates an inconsistency in lease accounting by requiring that modifications of capital leases that result in reclassification as operating leases be accounted for consistent with sale-leaseback accounting rules. This Statement also contains other nonsubstantive corrections to authoritative accounting literature. The changes related to debt extinguishment will be effective for fiscal years beginning after May 15, 2002, and the changes related to lease accounting will be effective for transactions occurring after May 15, 2002. Adoption of this Statement will not have any immediate effect on our consolidated financial statements. We will apply this guidance prospectively.
In June 2002, the Financial Accounting Standards Board issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities", which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally Emerging Issues Task Force Issue No. 94-3. We will adopt the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of the company's commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized.
In November 2002, the Financial Accounting Standards Board issued Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others". This interpretation of Financial Accounting Standards Board Statements No. 5, 57 and 107, and rescission of FIN No. 34 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. This interpretation incorporates, without change, the guidance in FIN No. 34, "Disclosure of Indirect Guarantees of Indebtedness of Others", which is being superceded. The initial recognition and initial measurement provisions of FIN No. 45 are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements in this interpretation are effective for financial statements of interim or annual periods after December 15, 2002, and have been adopted. For more information, see Note 13.
In December 2002, the Financial Accounting Standards Board issued SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure". This amendment to SFAS No. 123, "Accounting for Stock-Based Compensation", provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this statement amends the disclosure requirements of SFAS No. 123 to require disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The provisions of this statement are effective for financial statements of interim or annual periods after December 15, 2002. Early application of the disclosure provisions is encouraged, and earlier application of the transition provisions is permitted, provided that financial statements for the 2002 fiscal year have not been issued as of the date the statement was issued.
5. Income Taxes
Components of the income tax provision applicable to continuing operations for federal and state taxes are as follows (in thousands):
Year Ended December 31, ------------------------------- 2002 2001 2000 --------- --------- --------- Taxes currently payable: Federal................ $15,855 $ 9,058 $10,612 State.................. 3,116 1,192 1,416 Foreign................ 147 - - --------- ------- ------- Total.................. 19,118 10,250 12,028 Taxes deferred: Federal................ (3,280) 5,366 1,627 State.................. (555) 757 279 --------- ------- ------- Total.................. (3,835) 6,123 1,906 --------- ------- ------- Total tax provision..... $15,283 $16,373 $13,934 ========= ======= ======== Effective tax rate..... 2.4% 3.5% 4.8%
The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows:
Year Ended December 31, ---------------------------- 2002 2001 2000 --------- -------- --------- Federal income tax rate................ 35.0% 35.0% 35.0% Increase (decrease) as a result of: Partnership earnings not subject to tax................................. (35.0)% (35.0)% (35.0)% Corporate subsidiary earnings subject to tax.............................. 0.6% 1.3% 0.6% Income tax expense attributable to corporate equity earnings........... 1.6% 1.8% 4.1% State taxes.......................... 0.2% 0.4% 0.1% Effective tax rate..................... 2.4% 3.5% 4.8%
Deferred tax assets and liabilities result from the following (in thousands):
December 31, ---------------- 2002 2001 ------- ------- Deferred tax assets: Book accruals.................... $ 97 $ 404 Net Operating Loss/Alternative minimum tax credits............. 3,556 1,846 ------- ------- Total deferred tax assets.......... 3,653 2,250 Deferred tax liabilities: Property, plant and equipment.... 33,915 40,794 ------- ------- Total deferred tax liabilities..... 33,915 40,794 ------- ------- Net deferred tax liabilities....... $30,262 $38,544 ======= =======
We had available, at December 31, 2002, approximately $1.4 million of alternative minimum tax credit carryforwards, which are available indefinitely, and $2.1 million of net operating loss carryforwards, which will expire between the years 2003 and 2022. 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):
December 31, ------------------- 2002 2001 -------- -------- Natural gas, liquids and carbon dioxide pipelines............................... $2,544,987 $2,246,930 Natural gas, liquids and carbon dioxide pipeline station equipment.............. 2,801,729 2,168,924 Coal and bulk tonnage transfer, storage and services............................ 281,713 214,040 Natural gas and transmix processing...... 98,094 97,155 Other.................................... 292,881 217,245 Accumulated depreciation and depletion... (452,408) (302,012) ----------- ----------- 5,566,996 4,642,282 Land and land right-of-way............... 340,507 283,878 Construction work in process............. 336,739 156,452 ----------- ----------- $6,244,242 $5,082,612 =========== ===========
Depreciation and depletion expense charged against property, plant and equipment consists of the following (in thousands):
2002 2001 2000 -------- -------- ------- Depreciation and depletion expense........ $171,461 $126,641 $79,740
7. Investments
Our significant equity investments at December 31, 2002 consisted of:
o Plantation Pipe Line Company (51%);
o Red Cedar Gathering Company (49%);
o MKM Partners, L.P. (15%);
o Thunder Creek Gas Services, LLC (25%);
o Coyote Gas Treating, LLC (Coyote Gulch) (50%);
o Cortez Pipeline Company (50%); and
o Heartland Pipeline Company (50%).
On April 1, 2000, we acquired the remaining 80% ownership interest in Shell CO2 Company, Ltd. and renamed the entity Kinder Morgan CO2 Company, L.P. 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 International Marine Terminals (33 1/3%) for one month of 2002. We acquired an additional 33 1/3% interest in International Marine Terminals effective February 1, 2002, and after this date, the financial results of IMT were no longer reported under the equity method.
We 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 January 1, 2001, Kinder Morgan CO2 Company, L.P. acquired our 15% interest in MKM Partners, L.P., 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. We account for our 15% investment in the joint venture under the equity method of accounting because our ownership interest includes 50% of the joint venture's general partner interest, and the ownership of this general partner interest gives us the ability to exercise significant influence over the operating and financial policies of the joint venture.
We acquired our investment in Cortez Pipeline Company as part of our KMCO2 acquisition. We acquired our investments in Coyote Gas Treating, LLC and Thunder Creek Gas Services, LLC from KMI on December 31, 2000. Please refer to Note 3 for more information on our acquisitions.
On January 1, 2002, we adopted SFAS No. 142 and, accordingly, we reclassed the $140.3 million representing the balance, on that date, of our total unamortized excess cost over underlying fair value of net assets accounted for under the equity method from our investments to our goodwill.
Our total investments consisted of the following (in thousands):
December 31, -------------------- 2002 2001 --------- --------- Plantation Pipe Line Company............. $126,024 $217,473 Red Cedar Gathering Company.............. 64,459 99,484 MKM Partners, L.P........................ 60,795 58,633 Thunder Creek Gas Services, LLC.......... 36,921 30,159 Coyote Gas Treating, LLC................. 2,344 16,323 Cortez Pipeline Company.................. 10,486 9,599 Heartland Pipeline Company............... 5,459 5,608 All Others............................... 4,556 3,239 -------- -------- Total Equity Investments................. $311,044 $440,518 ======== ========
Our earnings from equity investments were as follows (in thousands):
Year Ended December 31, --------------------------- 2002 2001 2000 -------- -------- -------- Plantation Pipe Line Company.......... $26,426 $25,314 $31,509 Cortez Pipeline Company............... 28,154 25,694 17,219 Red Cedar Gathering Company........... 19,082 18,814 16,110 MKM Partners, L.P..................... 8,174 8,304 -- Coyote Gas Treating, LLC.............. 2,651 2,115 -- Thunder Creek Gas Services, LLC....... 2,154 1,629 -- Heartland Pipeline Company............ 998 882 1,581 Shell CO2 Company, Ltd................ -- -- 3,625 Coltonn Transmix Processing Facility.. -- -- 1,815 Trailblazer Pipeline Company.......... -- -- (24) All Others............................ 1,619 2,082 (232) -------- -------- -------- Total................................. $89,258 $84,834 $71,603 ======== ======== ======== Amortization of excess costs.......... $(5,575) $(9,011) $(8,195) ======== ======== ========
Summarized combined unaudited financial information for our significant equity investments is reported below (in thousands; amounts represent 100% of investee financial information):
Year Ended December 31, ---------------------------- Income Statement 2002 2001 2000 -------------------------------- -------- -------- -------- Revenues........................... $505,602 $449,259 $399,335 Costs and expenses................. 309,291 280,100 276,000 Earnings before extraordinary items 196,311 169,159 123,335 Net income......................... 196,311 169,159 123,335
December 31, ------------------- Balance Sheet 2002 2001 -------------------- --------- --------- Current assets.......... $ 83,410 $ 101,015 Non-current assets...... 1,101,057 1,079,053 Current liabilities..... 243,636 242,438 Non-current liabilities. 374,132 392,739 Partners'/owners' equity 566,699 544,891
8. Intangibles
Effective January 1, 2002, we adopted Statement of Financial Accounting Standards No. 141 "Business Combinations" and Statement of Financial Accounting Standards No. 142 "Goodwill and Other Intangible Assets". These accounting pronouncements require that we prospectively cease amortization of all intangible assets having indefinite useful economic lives. Such assets, including goodwill, are not to be amortized until their lives are determined to be finite. A recognized intangible asset with an indefinite useful life should be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We completed this initial transition impairment test in June 2002 and determined that our goodwill was not impaired as of January 1, 2002.
Our intangible assets include goodwill, lease value, contracts and agreements. We acquired our 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 then allocated the balance of the Kinder Morgan Texas Pipeline, L.P. intangible lease value between goodwill and property.
On January 1, 2002, we adopted SFAS No. 142 and, accordingly, we reclassed the $140.3 million representing the balance, on that date, of our total unamortized excess cost over underlying fair value of net assets accounted for under the equity method from our investments to our intangibles.
All of our intangible assets having definite lives are being amortized on a straight-line basis over their estimated useful lives. SFAS Nos. 141 and 142 also require that we disclose the following information related to our intangible assets still subject to amortization and our goodwill (in thousands):
December 31, ----------------- 2002 2001 --------- --------- Goodwill.................. $876,839 $566,633 Accumulated amortization.. (19,899) (19,899) --------- --------- Goodwill.................. 856,940 546,734 Lease value............... 6,124 6,124 Contracts and other....... 11,580 10,739 Accumulated amortization.. (380) (200) --------- --------- Other intangibles, net 17,324 16,663 --------- --------- Total intangibles, net $874,264 $563,397 ========= =========
Changes in the carrying amount of goodwill for the twelve months ended December 31, 2002 are summarized as follows (in thousands):
Amortization expense on intangibles, including amortization of excess intangible costs of equity investments, consists of the following (in thousands): 2002 2001 2000 ------ ------ ------ Goodwill............ $ - $13,416 $5,460 Lease value......... 140 4,999 140 Contracts and other. 40 60 40 ----- ------- ------ Total amortization.. $ 180 $18,475 $5,640 ===== ======= ======
Our weighted average amortization period for our intangible assets is approximately 41 years. The following table shows the estimated amortization expense for these assets for each of the five succeeding fiscal years (in thousands): Year Expense ---- ------- 2003 $180 2004 $180 2005 $180 2006 $180 2007 $180
Had SFAS No. 142 been in effect prior to January 1, 2002, our reported limited partners' interest in net income and net income per unit would have been as follows (in thousands, except per unit amounts):
Year Ended December 31, --------------------------- 2002 2001 2000 ---- ---- ---- Reported limited partners' interest in net income $ 337,561 $ 240,248 $ 168,878 Add: limited partners' interest in goodwill amortization -- 13,280 5,405 --------- --------- --------- Adjusted limited partners' interest in net income $ 337,561 $ 253,528 $ 174,283 ========= ========= ========= Basic limited partners' net income per unit: Reported net income $ 1.96 $ 1.56 $ 1.34 Goodwill amortization -- 0.09 0.04 --------- --------- --------- Adjusted net income $ 1.96 $ 1.65 $ 1.38 ========= ========= =========
Diluted limited partners' net income per unit: Reported net income $ 1.96 $ 1.56 $ 1.34 Goodwill amortization -- 0.09 0.04 --------- --------- --------- Adjusted net income $ 1.96 $ 1.65 $ 1.38 ========= ========= =========
9. Debt
Our debt and credit facilities as of December 31, 2002, consisted primarily of:
o a $530 million unsecured 364-day credit facility due October 14, 2003;
o a $445 million unsecured three-year credit facility due October 15, 2005;
o $37.1 million of Series F First Mortgage Notes due December 2004 (our subsidiary, SFPP, L.P. is the obligor on the notes);
o $200 million of 8.00% Senior Notes due March 15, 2005;
o $40 million of Plaquemines, Louisiana Port, Harbor, and Terminal District Revenue Bonds due March 15, 2006 (our 66 2/3% owned subsidiary, International Marine Terminals, is the obligor on the bonds);
o $250 million of 5.35% Senior Notes due August 15, 2007;
o $30 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);
o $250 million of 6.30% Senior Notes due February 1, 2009;
o $250 million of 7.50% Senior Notes due November 1, 2010;
o $700 million of 6.75% Senior Notes due March 15, 2011;
o $450 million of 7.125% Senior Notes due March 15, 2012;
o $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);
o $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);
o $23.7 million of tax-exempt bonds due 2024 (our subsidiary, Kinder Morgan Operating L.P. "B", is the obligor on the bonds);
o $300 million of 7.40% Senior Notes due March 15, 2031;
o $300 million of 7.75% Senior Notes due March 15, 2032;
o $500 million of 7.30% Senior Notes due August 15, 2033; and
o a $975 million short-term commercial paper program (supported by our credit facilities, the amount available for borrowing under our credit facilities is reduced by our outstanding commercial paper borrowings).
None of our debt or credit facilities are subject to payment acceleration as a result of any change to our credit ratings. However, the margin that we pay with respect to LIBOR based borrowings under our credit facilities is tied to our credit ratings.
Our outstanding short-term debt at December 31, 2002, consisted of:
o $220 million of commercial paper borrowings;
o $37.1 million under the SFPP, L.P. 10.7% First Mortgage Notes;
o $5 million under the Central Florida Pipeline LLC Notes; and
o $2.8 million in other borrowings.
We intend and have the ability to refinance our $264.9 million of short-term debt on a long-term basis under our
unsecured long-term credit facility. Accordingly, such amounts have been classified as long-term debt in our accompanying consolidated balance sheet. Currently, we do not anticipate any liquidity problems. The weighted average interest rate on all of our borrowings was approximately 5.015% during 2002 and 6.965% during 2001.
Credit Facilities
On December 31, 2000, we had two credit facilities, a $300 million unsecured five-year credit facility expiring on September 29, 2004, and a $600 million unsecured 364-day credit facility expiring on October 25, 2001. On December 31, 2000, the outstanding balance under our five-year credit facility was $207.6 million and the outstanding balance under our 364-day credit facility was $582 million.
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 credit facility was used to support the increase in our commercial paper program to $1.7 billion for our acquisition of the GATX businesses. 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 this $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 expiring on October 23, 2002. The terms of this credit facility were substantially similar to the terms of the expired facility. There were no borrowings under either credit facility at December 31, 2001.
On February 21, 2002, we obtained a third unsecured 364-day credit facility, in the amount of $750 million, expiring on February 20, 2003. The credit facility was used to support the increase in our commercial paper program to $1.8 billion for our acquisition of Tejas Gas, LLC, and the terms of this credit facility were substantially similar to the terms of our other two credit facilities. Upon issuance of additional senior notes in March 2002, this short-term credit facility was reduced to $200 million.
In August 2002, upon the completion of our i-unit equity sale, we terminated, under the terms of the agreement, our $200 million unsecured 364-day credit facility that was due February 20, 2003. On October 16, 2002, we successfully renegotiated our bank credit facilities by replacing our $750 million unsecured 364-day credit facility due October 23, 2002 and our $300 million unsecured five-year credit facility due September 29, 2004 with two new credit facilities. Our current facilities include:
o a $530 million unsecured 364-day credit facility due October 14, 2003; and
o a $445 million unsecured three-year credit facility due October 15, 2005.
Our credit facilities are with a syndicate of financial institutions. Wachovia Bank, National Association is the administrative agent under both credit facilities. The terms of our two credit facilities are substantially similar to the terms of our previous credit facilities. Interest on the two credit facilities accrues at our option at a floating rate equal to either:
o the administrative agent's base rate (but not less than the Federal Funds Rate, plus 0.5%); or
o LIBOR, plus a margin, which varies depending upon the credit rating of our long-term senior unsecured debt.
Our credit facilities include the following restrictive covenants as of December 31, 2002:
o requirements to maintain certain financial ratios:
o total debt divided by earnings before interest, income taxes, depreciation and amortization for the preceding four quarters may not exceed 5.0;
o total indebtedness of all consolidated subsidiaries shall at no time exceed 15% of consolidated indebtedness;
o tangible net worth as of the last day of any fiscal quarter shall not be less than $2,100,000,000; and
o consolidated indebtedness shall at no time exceed 62.5% of total capitalization;
o limitations on entering into mergers, consolidations and sales of assets;
o limitations on granting liens; and
o prohibitions on making any distribution to holders of units if an event of default exists or would exist upon making such distribution.
There were no borrowings under either credit facility at December 31, 2002. The amount available for borrowing under our credit facilities is reduced by:
o a $23.7 million letter of credit that supports Kinder Morgan Operating L.P. "B"'s tax-exempt bonds;
o a $28 million letter of credit entered into on December 23, 2002 that supports Nassau County, Florida Ocean Highway and Port Authority tax exempt bonds (associated with the operations of our bulk terminal facility located at Fernandina Beach, Florida); and
o our outstanding commercial paper borrowings.
Our new three-year credit facility also permits us to obtain bids for fixed rate loans from members of the lending syndicate.
Senior Notes
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.
On March 14, 2002, we closed a public offering of $750 million in principal amount of senior notes, consisting of $450 million in principal amount of 7.125% senior notes due March 15, 2012 at a price to the public of 99.535% per note, and $300 million in principal amount of 7.75% senior notes due March 15, 2032 at a price to the public of 99.492% per note. In the offering, we received proceeds, net of underwriting discounts and commissions, of approximately $445.0 million for the 7.125% notes and $295.9 million for the 7.75% notes. We used the proceeds to reduce our outstanding balance on our commercial paper borrowings.
On March 22, 2002, we paid $200 million to retire the principal amount of our Floating Rate senior notes that matured on that date. We borrowed the necessary funds under our commercial paper program.
Under an indenture dated August 19, 2002, and a First Supplemental Indenture dated August 23, 2002, we completed a private placement of $750 million in debt securities. The notes consisted of $500 million in principal amount of 7.30% Senior Notes due August 15, 2033 and $250 million in principal amount of 5.35% Senior Notes due August 15, 2007. In the offering, we received proceeds, net of underwriting discounts and commissions, of approximately $494.7 million for the 7.30% notes and $248.3 million for the 5.35% notes. The proceeds were used to reduce the borrowings under our commercial paper program. On November 18, 2002, we exchanged these notes with substantially identical notes that were registered under the Securities Act of 1933.
At December 31, 2002, our unamortized liability balance due on the various series of our senior notes was as follows (in millions):
8.0% senior notes due March 15, 2005 $ 199.8 5.35% senior notes due August 15, 2007 249.8 6.3% senior notes due February 1, 2009 249.5 7.5% senior notes due November 1, 2010 248.8 6.75% senior notes due March 15, 2011 698.3 7.125% senior notes due March 15, 2012 448.1 7.4% senior notes due March 15, 2031 299.3 7.75% senior notes due March 15, 2032 298.5 7.3% senior notes due August 15, 2033 499.0 -------- Total $3,191.1 ========
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. As of December 31, 2002, we have entered into interest rate swap agreements with a notional principal amount of $1.95 billion for the purpose of hedging the interest rate risk associated with our fixed and variable rate debt obligations.
These interest rate 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 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. At December 31, 2002, we recognized an asset of $167.0 million for the net fair value of our swap agreements and we included this amount with Deferred charges and other assets on the accompanying balance sheet. 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. For more information on our risk management activities, see Note 14.
Commercial Paper Program
On December 31, 2000, our commercial paper program provided for the issuance of up to $600 million of commercial paper. On that date, we had $52 million of commercial paper outstanding with an interest rate of 7.02%. 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. We entered into a $1.1 billion unsecured 364-day credit facility to support this increase in our commercial paper program, and we used the program's increase in available funds to close on the GATX acquisition.
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 representing limited liability company interests with limited voting rights to the public in an initial public offering. Its shares were issued at a price of $35.21 per share, less commissions and underwriting expenses, and it used substantially all of the net proceeds from that offering to purchase i-units from us. After commissions and underwriting expenses, we received net proceeds of approximately $996.9 million for the issuance of 29,750,000 i-units to KMR. We used the proceeds from the i-unit issuance to reduce the borrowings under our commercial paper program.
Also during the second quarter of 2001, after the issuance of additional senior notes on March 12, 2001 and the issuance of i-units in May 2001, we decreased our commercial paper program back to $600 million. On October 17, 2001, we increased our commercial paper program to $900 million. As of December 31, 2001, we had $590.5 million of commercial paper outstanding with an interest rate of 2.6585%.
On February 21, 2002, our commercial paper program increased to provide for the issuance of up to $1.8 billion of commercial paper. We entered into a $750 million unsecured 364-day credit facility to support this increase in our
commercial paper program, and we used the program's increase in available funds to close on the Tejas acquisition. After the issuance of additional senior notes on March 14, 2002, we reduced our commercial paper program to $1.25 billion.
On August 6, 2002, KMR issued in a public offering, an additional 12,478,900 of its shares, including 478,900 shares upon exercise by the underwriters of an over-allotment option, at a price of $27.50 per share, less commissions and underwriting expenses. The net proceeds from the offering were used to buy i-units from us. After commissions and underwriting expenses, we received net proceeds of approximately $331.2 million for the issuance of 12,478,900 i-units. We used the proceeds from the i-unit issuance to reduce the borrowings under our commercial paper program and, in conjunction with our issuance of additional i-units and as previously agreed upon under the terms of our credit facilities, we reduced our commercial paper program to provide for the issuance of up to $975 million of commercial paper as of December 31, 2002. On December 31, 2002, we had $220.0 million of commercial paper outstanding with an average interest rate of 1.58%.
The borrowings under our commercial paper program were used to finance acquisitions made during 2001 and 2002. The borrowings under our commercial paper program reduce the borrowings allowed under our credit facilities.
SFPP, L.P. Debt
At December 31, 2002, the outstanding balance under SFPP, L.P.'s Series F notes was $37.1 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. We expect to pay the remaining $37.1 million balance in December 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 collateralized 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:
o $4.1 million of 7.30% New Jersey Industrial Revenue Bonds due September 1, 2019;
o $59.5 million of 6.95% Texas Industrial Revenue Bonds due February 1, 2022;
o $7.4 million of 6.65% New Jersey Industrial Revenue Bonds due September 1, 2022;
o $13.3 million of 7.00% Louisiana Industrial Revenue Bonds due March 1, 2023; and
o $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. (see Note 3). 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. These 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, 2002, the interest rate was 1.05%. 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% with repayments 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, 2002, Central Florida's outstanding balance under the Senior Notes was $30.0 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
Credit Facility
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, and 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, provided for loans of up to $85.2 million and had a maturity date of June 29, 2003. The agreement provided for an interest rate of LIBOR plus a margin as determined by certain financial ratios. Pursuant to the terms of the revolving credit facility, Trailblazer Pipeline Company partnership distributions were restricted by certain financial covenants. 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%. In July 2002, we paid the $31.0 million outstanding balance under Trailblazer's revolving credit facility and terminated the facility.
Senior Notes
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 2002, the weighted-average interest rate on these bonds was 1.39% per annum, and at December 31, 2002, the interest rate was 1.59%. We have an outstanding letter of credit issued under our credit facilities that supports our tax-exempt bonds. The letter of credit reduces the amount available for borrowing under our credit facilities.
International Marine Terminals Debt
As of February 1, 2002, we owned a 66 2/3% interest in International Marine Terminals partnership (see Note 3). The principal assets owned by IMT are dock and wharf facilities financed by the Plaquemines Port, Harbor and Terminal District (Louisiana) $40,000,000 Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds (International Marine Terminals Project) Series 1984A and 1984B. The bonds mature on March 15, 2006. The bonds are backed by two letters of credit issued by KBC Bank N.V. On March 19, 2002, an Amended and Restated Letter of Credit Reimbursement Agreement relating to the letters of credit in the amount of $45.5 million was entered into by IMT and KBC Bank. In connection with that agreement, we agreed to guarantee the obligations of IMT in proportion to our ownership interest. Our obligation is approximately $30.3 million for principal, plus interest and other fees.
Maturities of Debt
The scheduled maturities of our outstanding debt, excluding market value of interest rate swaps, at December 31, 2002, are summarized as follows (in thousands):
2003......... $264,937 2004......... 5,018 2005......... 204,836 2006......... 45,019 2007......... 254,863 Thereafter... 2,884,860 --------- Total........ $3,659,533 ==========
Of the $264.9 million scheduled to mature in 2003, we intend and have the ability to refinance the entire amount on a long-term basis under our existing credit facilities.
Fair Value of Financial Instruments
The estimated fair value of our long-term debt, excluding market value of interest rate swaps, is based upon prevailing interest rates available to us at December 31, 2002 and December 31, 2001 and 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.
December 31, 2002 December 31, 2001 --------------------- ---------------------- Carrying Estimated Carrying Estimated Value Fair Value Value Fair Value -------- ---------- -------- ---------- (In thousands) Total Debt $3,659,533 $4,475,058 $2,797,234 $3,094,530
10. Pensions and Other Post-retirement Benefits
In connection with our acquisition of SFPP, L.P. and Kinder Morgan Bulk Terminals, Inc. 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.
Net periodic benefit costs and weighted-average assumptions for these plans include the following components (in thousands):
2002 2001 2000 ---------- ---------- --------------------- Other Other Other Post- Post- Post- retirement retirement Pension retirement Benefits Benefits Benefits Benefits ---------- ---------- -------- ---------- Net periodic benefit cost Service cost............. $ 165 $ 120 $ -- $ 46 Interest cost............ 906 804 145 755 Expected return on plan assets................... -- -- (170) -- Amortization of prior service cost............ (545) (545) -- (493) Actuarial gain........... -- (27) -- (290) ------- ------- ------ ------- Net periodic benefit cost $ 526 $ 352 $ (25) $ 18 ======= ======= ====== =======
Additional amounts recognized Curtailment (gain) loss $ -- $ -- $ -- $ -- Weighted-average assumptions as of December 31: Discount rate............ 6.50% 7.00% 7.5% 7.75% Expected return on plan assets.................. -- -- 8.5% -- Rate of compensation increase................ 3.9% -- -- --
Information concerning benefit obligations, plan assets, funded status and recorded values for these plans follows (in thousands):
2002 2001 --------------- --------------- Other Other Post-retirement Post-retirement Benefits Benefits --------------- --------------- Change in benefit obligation Benefit obligation at Jan. 1...... $ 13,368 $ 10,897 Service cost...................... 165 120 Interest cost..................... 906 804 Participant contributions......... 143 -- Amendments........................ (493) -- Actuarial (gain) loss............. (264) 2,350 Benefits paid from plan assets.... (550) (803) --------- --------- Benefit obligation at Dec. 31.......................... $ 13,275 $ 13,368 ========= =========
Change in plan assets Fair value of plan assets at Jan. 1........................ $ -- $ -- Actual return on plan assets...... -- -- Employer contributions............ 407 803 Participant contributions......... 143 -- Benefits paid from plan assets.... (550) (803) --------- --------- Fair value of plan assets at Dec. 31....................... $ -- $ -- ========= =========
2002 2001 --------------- --------------- Other Other Post-retirement Post-retirement Benefits Benefits --------------- --------------- Funded status.................... $(13,275) $(13,368) Unrecognized net acturiral (gain) loss..................... 729 993 Unrecognized prior service (benefit)............... (1,059) (1,111) Adj. for 4th qtr. employer contributions........... 105 -- --------- --------- Prepaid (accrued) benefit cost............................ $(13,500) $(13,486) ========= =========
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 (2.5 years). For measurement purposes, a 11% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2003. The rate was assumed to decrease gradually to 5% by 2009 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:
1-Percentage 1-Percentage Point Increase Point Decrease -------------- -------------- Effect on total of service and interest cost components............. $ 106 $ (89) Effect on postretirement benefit obligation........................... $1,148 $ (974)
Multiemployer Plans and Other Benefits
As a result of acquiring several terminal operations, primarily our acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, we participate in several multi-employer pension plans for the benefit of 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 $1.3 million for the year ended 2002 and $0.6 million for the year ended 2001.
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).
The Kinder Morgan Savings Plan, formerly the Kinder Morgan Retirement Savings Plan, permits all full-time employees of KMGP Services Company, Inc. and KMI 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, KMGP Services Company, Inc. and KMI 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 2003, no discretionary contributions were made to individual accounts for 2002. The total amount charged to expense for our Savings Plan was $5.6 million during 2002. 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 KMGP Services Company, Inc. and KMI 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, discretionary contributions are made to the plan based on our and KMI's performance. In the first quarter of 2002, an additional 1% discretionary contribution was made to individual accounts. No additional contributions were made for 2002 performance. Interest will be credited to the personal retirement accounts at the 30-year U.S. Treasury bond rate in effect each year. Employees become 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, 2002, our partners' capital consisted of:
o 129,943,218 common units;
o 5,313,400 Class B units; and
o 45,654,048 i-units.
Together, these 180,910,666 units represent the limited partners' interest and an effective 98% economic interest in the Partnership, exclusive of our general partner's incentive distribution. Our general partner has an effective 2% interest in the Partnership, excluding our general partner's incentive distribution. At December 31, 2002, our common unit total consisted of 116,987,483 units held by third parties, 11,231,735 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, 2001, our Partners' capital consisted of:
o 129,855,018 common units;
o 5,313,400 Class B units; and
o 30,636,363 i-units.
Our total common units outstanding at December 31, 2001, 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.
All of our Class B units were issued in December 2000. The Class B units are similar to our common units except that they are not eligible for trading on the New York Stock Exchange. We initially issued 29,750,000 i-units in May 2001. The i-units are a separate class of limited partner interests in us. All of our i-units are owned by KMR and are not publicly traded. In accordance with its limited liability company agreement, KMR's activities are restricted to being a limited partner in, and controlling and managing the business and affairs of, the Partnership, our operating partnerships and our subsidiaries.
On August 6, 2002, KMR issued in a public offering, an additional 12,478,900 of its shares, including 478,900 shares upon exercise by the underwriters of an over-allotment option, at a price of $27.50 per share, less commissions and underwriting expenses. The net proceeds from the offering were used to buy additional i-units from us. After commissions and underwriting expenses, we received net proceeds of approximately $331.2 million for the issuance of 12,478,900 i-units. We used the proceeds from the i-unit issuance to reduce the debt we incurred in our acquisition of Kinder Morgan Tejas during the first quarter of 2002.
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. Furthermore, under the terms of our partnership agreement, we agreed 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. The number of i-units we distribute to KMR is based upon the amount of cash we distribute to the owners of our common units. When cash is paid to the holders of our common units, we will issue additional i-units to KMR. The fraction of an i-unit paid per i-unit owned by KMR will have the same value as the cash payment on the common unit.
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. Based on the preceding, KMR received a distribution of 937,658 i-units on November 14, 2002. These additional i-units distributed were based on the $0.61 per unit distributed to our common unitholders on that date. For the year ended December 31, 2002, KMR received distributions of 2,538,785 i-units. These additional i-units distributed were based on the $2.36 per unit distributed to our common unitholders during 2002.
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 are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate value of cash and i-units being distributed.
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, 2002, 2001 and 2000, we declared distributions of $2.435, $2.15 and $1.7125, respectively, per unit. Our distributions to unitholders for 2002, 2001 and 2000 required incentive distributions to our general partner in the amount of $267.4 million, $199.7 million and $107.8 million, respectively. The increased incentive distributions paid for 2002 over 2001 and 2001 over 2000 reflect the increase in amounts distributed per unit as well as the issuance of additional units.
On January 15, 2003, we declared a cash distribution for the quarterly period ended December 31, 2002, of $0.625 per unit. This distribution was paid on February 14, 2003, to unitholders of record as of January 31, 2003. 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 $0.625 distribution per common unit. The number of i-units distributed was 858,981. For each outstanding i-unit that KMR held, a fraction of an i-unit was issued. The fraction was determined by dividing:
o $0.625, the cash amount distributed per common unit
by
o $33.219, the average of KMR's limited liability shares' closing market prices from January 14-28, 2003, 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 February 14, 2003 distribution required an incentive distribution to our general partner in the amount of $72.5 million. Since this distribution was declared after the end of the quarter, no amount is shown in the December 31, 2002 balance sheet as a Distribution Payable.
12. Related Party Transactions
General and Administrative Expenses
KMGP Services Company, Inc. provides employees and KMR, through its wholly owned subsidiary, Kinder Morgan Services LLC, provides 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 KMGP Services Company, Inc. 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 LLC 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 KMI, 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 provide reimbursement 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 KMI and the Group are employed by KMI. Additionally, other KMI employees assist in the operation of our Natural Gas Pipeline assets formerly owned by KMI. These KMI employees' expenses are allocated without a profit component between KMI 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 as follows:
o its 1.0101% direct general partner ownership interest (accounted for as minority interest in the consolidated financial statements of the Partnership); and
o its 0.9899% ownership interest indirectly owned via its 1% ownership interest in the Partnership.
At December 31, 2002, our general partner owned 1,724,000 common units, representing approximately 0.95% of our outstanding limited partner units. 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. Available cash consists generally of all of our cash receipts, including cash received by our operating partnerships, 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.
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.
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;
o 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;
o 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;
o 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
o 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 value of cash and i-units being distributed. Our general partner's declared incentive distributions for the years ended December 31, 2002, 2001 and 2000 were $267.4 million, $199.7 million and $107.8 million, respectively.
Kinder Morgan, Inc.
KMI, through its subsidiary Kinder Morgan (Delaware), Inc., remains the sole stockholder of our general partner. At December 31, 2002, KMI directly owned 6,523,650 common units and 5,313,400 Class B units, indirectly owned 6,432,085 common units owned by its consolidated affiliates, including our general partner and owned 13,511,726 KMR shares, representing an indirect ownership interest of 13,511,726 i-units. Together, these units represent approximately 17.6% of our outstanding limited partner units. Including both its general and limited partner interests in us, at the 2002 distribution level, KMI received approximately 51% of all quarterly distributions from us, of which approximately 40% is attributable to its general partner interest and 11% is attributable to its limited partner interest. The actual level of distributions KMI will receive in the future will vary with the level of distributions to the limited partners determined in accordance with our partnership agreement.
Kinder Morgan Management, LLC
KMR, our general partner's delegate, remains the sole owner of our 45,654,048 i-units.
Asset Acquisitions
2000 Kinder Morgan, Inc. Asset Contributions
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. The transaction was approved unanimously by the independent
directors of our general partner, with the benefit of independent financial and legal advisors, including a fairness opinion from the investment banking firm A.G. Edwards & Sons, Inc.
Mexican Entity Transfer
In the fourth quarter of 2002, KMI transferred to us its interests in Kinder Morgan Natural Gas de Mexico, S. de R.L. de C.V., hereinafter referred to as KM Mexico. KM Mexico is the entity through which we are developing the Mexican portion of our Mier-Monterrey natural gas pipeline that connects to the southern tip of Kinder Morgan Texas Pipeline, L.P.'s intrastate pipeline, hereinafter referred to the Monterrey Project. The Monterrey Project was initially conceived at KMI in 1996 and between 1996 and 1998 KMI and its subsidiaries paid, on behalf of KM Mexico, approximately $2.5 million in connection with the Monterrey Project to explore the feasibility of and to obtain permits for the Mexican portion of the project. Following 1998, the Monterrey Project was dormant at KMI.
In December 2000, when KMI contributed to us Kinder Morgan Texas Pipeline, L.P., the entity that had been primarily responsible for the Monterrey Project, the Monterrey Project was still dormant (and thought likely to remain dormant indefinitely). Consequently, KM Mexico was not contributed to us at that time.
In 2002, Kinder Morgan Texas Pipeline, L.P. reassessed the Monterrey Project and determined that the Monterrey Project was an economically feasible project for us. Accordingly, KMI's Board of Directors on the one hand, and KMR and our general partner's Boards of Directors on the other hand, unanimously determined, respectively, that KMI should transfer KM Mexico to us for approximately $2.5 million, the amount paid by KMI and its subsidiaries, on KM Mexico's behalf, in connection with the Monterrey Project between 1996 and 1998.
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 agreements between KMI and us. The agreements have five-year terms and contain automatic five-year extensions. Pursuant to the applicable underlying agreements, we pay KMI either a fixed amount or actual costs incurred as reimbursement for the corporate general and administrative expenses incurred in connection with the operation of these assets. The amounts paid to KMI for corporate general and administrative costs, including amounts related to Trailblazer Pipeline Company, were $13.3 million of fixed costs and $2.8 million of actual costs incurred for 2002, and $9.5 million of fixed costs and $3.2 million of actual costs incurred for 2001. Commencing in 2003, KMI will be operating additional pipeline assets, including our North System and Cypress Pipeline, which are part of our Products Pipelines business segment, as well as our Monterrey Pipeline, which is currently under construction and will be part of our Natural Gas Pipelines business segment. We estimate the total reimbursement to be paid to KMI in respect of all pipeline assets operated by KMI and its subsidiaries for us for 2003 will be approximately $19.7 million, which includes $14.4 million of fixed costs (adjusted for inflation) and $5.3 million of actual costs. We believe the amounts paid to KMI for the services they provided each year fairly reflect the value of the services performed. 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
We own a 50% equity interest in Coyote Gas Treating, LLC, referred to herein as Coyote Gulch. Coyote Gulch is a joint venture, and El Paso Field Services Company owns the remaining 50% equity interest. We are the managing partner of Coyote Gulch. As of December 31, 2002, Coyote's balance sheet has current notes payable to
each partner in the amount of $17.1 million. These notes are due on June 30, 2003. At that time, the partners can either renew the notes or make capital contributions which enable Coyote to payoff the existing notes.
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 partnership agreements provide that in the absence of bad faith by KMR, the resolution of a conflict by KMR will not be a breach of any duties. 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
Operating Leases
We have entered into certain operating leases. Including probable elections to exercise renewal options, the remaining terms on our leases range from one to 41 years. Future commitments related to these leases at December 31, 2002 are as follows (in thousands): 2003...................... $ 18,747 2004...................... 15,128 2005...................... 13,206 2006...................... 11,819 2007...................... 9,545 Thereafter................ 55,545 -------- Total minimum payments.... $123,990 ========
We have not reduced our total minimum payments for future minimum sublease rentals aggregating approximately $1.6 million. Total lease and rental expenses, including related variable charges were $21.6 million for 2002, $41.1 million for 2001 and $7.5 million for 2000.
Common Unit Option Plan
During 1998, we established a common unit option plan, which provides that key personnel of KMGP Services Company, Inc. and KMI 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, 2002 and 2001, outstanding options for 261,600 and 379,400 common units had been granted to certain personnel with a term of seven years at an average exercise price of approximately $17.30 per unit. During 2002, 88,200 options were exercised at an average price of $17.77 per unit. These options had an average fair market value of $34.24 per unit. During 2001, 55,200 options were exercised at an average price of $17.52 per unit. These options had an average fair market value of $33.26 per unit. In addition, as of December 31, 2002, outstanding options for 20,000 common units, at an average exercise price of $20.58 per unit, had been granted to two of Kinder Morgan G.P., Inc.'s three non-employee directors. The options granted generally have a term of seven years, vest 40% on the first anniversary of the date of grant and 20% on each of the next three anniversaries, and have exercise prices equal to the market price of the common units at the grant date.
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.
Other
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 obtained 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, 2002, there were no outstanding awards granted under our Executive Compensation Plan.
Contingent Debt
Cortez Pipeline Company Debt
Pursuant to a certain Throughput and Deficiency Agreement, the owners of Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% owner; a subsidiary of Exxon Mobil Corporation - 37% owner; and Cortez Vickers Pipeline Company - 13% owner) are required, on a percentage ownership basis, to contribute capital to Cortez Pipeline Company in the event of a cash deficiency. The Throughput and Deficiency Agreement contractually supports the borrowings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by obligating the owners of Cortez Pipeline Company to fund cash deficiencies at Cortez Pipeline Company, including cash deficiencies relating to the repayment of principal and interest on borrowings by Cortez Capital Corporation. Parent companies of the respective Cortez Pipeline Company owners further severally guarantee, on a percentage basis, the obligations of the Cortez Pipeline Company owners under the Throughput and Deficiency Agreement.
Due to our indirect ownership of Cortez Pipeline Company through Kinder Morgan CO2 Company, L.P., 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 Capital Corporation's debt programs in place as of April 1, 2000.
At December 31, 2002, the debt facilities of Cortez Capital Corporation consisted of:
o $115.7 million of Series D notes due May 15, 2013;
o a $175 million short-term commercial paper program; and
o a $175 million committed revolving credit facility due December 26, 2003 (to support the above-mentioned $175 million commercial paper program).
At December 31, 2002, Cortez Capital Corporation had $140.6 million of commercial paper outstanding with an interest rate of 1.39%, the average interest rate on the Series D notes was 6.9322% and there were no borrowings under the credit facility.
Plantation Pipeline Company Debt
On April 30, 1997, Plantation Pipeline Company entered into a $10 million, ten-year floating-rate term credit agreement. We, as an owner of Plantation Pipeline Company, severally guarantee this debt on a pro rata basis equivalent to our respective 51% ownership interest. During 1999, this agreement was amended to reduce the maturity date by three years. The $10 million is outstanding at December 31, 2002.
Red Cedar Gas Gathering Company Debt
In October 1998, Red Cedar Gas Gathering Company sold $55 million in aggregate principal amount of Senior Notes due October 31, 2010. The $55 million was sold in 10 different notes in varying amounts with identical terms.
The Senior Notes are secured by a first priority lien on the ownership interests, including our 49% ownership interest, in Red Cedar Gas Gathering Company. The Senior Notes are also guaranteed by us and the other owner of Red Cedar Gas Gathering Company. The principal is to be repaid in seven equal installments beginning on October 31, 2004 and ending on October 31, 2009, with any remainder due October 31, 2010. The $55 million is outstanding at December 31, 2002.
Nassau County, Florida Ocean Highway and Port Authority Debt
Nassau County, Florida Ocean Highway and Port Authority is a political subdivision of the state of Florida. During 1990, Ocean Highway and Port Authority issued its Adjustable Demand Revenue Bonds in the aggregate principal amount of $38.5 million for the purpose of constructing certain port improvements located in Fernandino Beach, Nassau County, Florida. A letter of credit was issued as security for the Adjustable Demand Revenue Bonds and was guaranteed by the parent company of Nassau Terminals, Inc., the operator of the port facilities. In July 2002, we acquired Nassau Terminals, Inc. and became guarantor under the letter of credit agreement. In December 2002, we issued a $28 million letter of credit under our credit facilities and the former letter of credit guarantee was terminated.
14. Risk Management
Hedging Activities
Certain of our business activities expose us to risks associated with changes in the market price of natural gas, natural gas liquids, crude oil and carbon dioxide. Through KMI, we use energy financial instruments to reduce our risk of changes in the prices of natural gas, natural gas liquids and crude oil markets (and carbon dioxide to the extent contracts are tied to crude oil prices) as discussed below. 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:
o commodity futures and options contracts;
o fixed-price swaps; and
o 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:
o pre-existing or anticipated physical natural gas, natural gas liquids and crude oil sales;
o pre-existing or anticipated physical carbon dioxide sales that have pricing tied to crude oil prices;
o natural gas purchases; and
o 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 our Risk Management Committee, which is charged with the review and enforcement of our management's risk management policy.
As a result of our adoption of SFAS No. 133, as discussed in Note 2, 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. During 2001, we reclassified a total of $51.5 million to earnings as a result of hedged sales and purchases during the period.
The gains and losses included in Accumulated other comprehensive income will be reclassified into earnings as the hedged sales and purchases take place. Approximately $42.5 million of the Accumulated other comprehensive loss balance of $45.3 million representing unrecognized net losses on derivative activities at December 31, 2002 is expected to be reclassified into earnings during the next twelve months. During 2002, we reclassified $7.5 million of the accumulated other comprehensive income balance of $63.8 million representing unrecognized net losses on derivative activities at December 31, 2001 into earnings. For each of the years ended December 31, 2002 and 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.
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 $1.9 million at December 31, 2002 and $20.0 million on December 31, 2001. Our margin deposits associated with over-the-counter swap partners were $0.0 million on December 31, 2002 and ($42.1) million on December 31, 2001.
We recognized a gain of $0.7 million during 2002 and a loss of $1.3 million during 2001 as a result of ineffective hedges. These amounts are reported within the caption Operations and maintenance in the accompanying Consolidated Statements of Income. For each of the years ended December 31, 2002 and 2001, we did not exclude any component of the derivative instruments' gain or loss from the assessment of hedge effectiveness.
The differences between the current market value and the original physical contracts value associated with our hedging activities are primarily reflected as Other current assets and Accrued other current liabilities in the accompanying consolidated balance sheets. At December 31, 2002, our balance of $104.5 million of Other current assets included approximately $57.9 million related to risk management hedging activities, and our balance of $298.7 million of Accrued other current liabilities included approximately $101.3 million related to risk management hedging activities. At December 31, 2001, our balance of $194.9 million of Other current assets included approximately $163.7 million related to risk management hedging activities, and our balance of $209.9 million of Accrued other current liabilities included approximately $117.8 million related to risk management hedging activities.
The remaining differences between the current market value and the original physical contracts value associated with our hedging activities are reflected as deferred charges or deferred credits in the accompanying consolidated balance sheets. At December 31, 2002, our balance of $250.8 million of Deferred charges and other assets included
approximately $5.7 million related to risk management hedging activities, and our balance of $199.8 million of Other long-term liabilities and deferred credits included approximately $8.5 million related to risk management hedging activities. At December 31, 2001, our balance of $75.0 million of Deferred charges and other assets included approximately $22.0 million related to risk management hedging activities, and our balance of $246.5 million of Other long-term liabilities and deferred credits included approximately $4.7 million related to risk management hedging activities.
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 our consolidated balance sheets. In all instances, 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, 2002, our principal uses of derivative financial instruments will be to mitigate the risk associated with market movements in the price of energy commodities. Our net short natural gas derivatives position primarily represents our hedging of anticipated future natural gas purchases and sales. Our net short crude oil derivatives position represents our crude oil derivative purchases and sales made to hedge anticipated oil purchases and sales. In addition, crude oil contracts have been sold to hedge anticipated carbon dioxide purchases and sales that have pricing tied to crude oil prices. Finally, our net short natural gas liquids derivatives position reflects the hedging of our forecasted natural gas liquids purchases and sales. As of December 31, 2002, the maximum length of time over which we have hedged our exposure to the variability in future cash flows associated with commodity price risk is through December 2007.
As of December 31, 2002, 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 has an investment grade credit rating. We both owe money and are owed money under these financial instruments. At December 31, 2002, if all parties owing us failed to pay us amounts due under these arrangements, our credit loss would be $9.5 million.
At December 31, 2002, our largest credit exposure to a single counterparty was $4.2 million. In addition, defaults by counterparties under over-the-counter swaps and options could expose us to additional commodity price risks in the event that we are unable to enter into replacement contracts for such swaps and options on substantially the same terms. Alternatively, we may need to pay significant amounts to the new counterparties to induce them to enter into replacement swaps and options on substantially the same terms.
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:
o ceased to account for those derivatives as hedges;
o entered into new derivative transactions on substantially similar terms with other counterparties to replace our position with Enron;
o designated the replacement derivative positions as hedges of the exposures that had been hedged with the Enron positions; and
o 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. As of December 31, 2002 and 2001, respectively, we were a party to interest rate swap agreements with a notional principal amount of $1.95 billion and $900 million, respectively, for the purpose of hedging the interest rate risk associated with our fixed and variable rate debt obligations.
As of December 31, 2002, a notional principal amount of $1.75 billion of these agreements effectively converts 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:
o $200 million principal amount of our 8.0% senior notes due March 15, 2005;
o $200 million principal amount of our 5.35% senior notes due August 15, 2007;
o $250 million principal amount of our 6.30% senior notes due February 1, 2009;
o $200 million principal amount of our 7.125% senior notes due March 15, 2012;
o $300 million principal amount of our 7.40% senior notes due March 15, 2031;
o $200 million principal amount of our 7.75% senior notes due March 15, 2032; and
o $400 million principal amount of our 7.30% senior notes due August 15, 2033.
These swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes, therefore, as of December 31, 2002, the maximum length of time over which we have hedged our exposure to the variability in future cash flows associated with interest rate risk is through August 2033. The swap agreements related to our 7.40% senior notes contain mutual cash-out provisions at the then-current economic value every seven years. The swap agreements related to our 7.125% senior notes contain cash-out provisions at the then-current economic value at March 15, 2009. The swap agreements related to our 7.75% senior notes and our 7.30%
senior notes contain mutual cash-out provisions at the then-current economic value every five years. These interest rate swaps have been designated as fair value hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives that hedge a recognized asset or liability's exposure to changes in their fair value as fair value hedges and the gain or loss on fair value hedges are to be recognized in earnings in the period of change together with the offsetting loss or gain on the hedged item attributable to the risk being hedged. The effect of that accounting is to reflect in earnings the extent to which the hedge is not effective in achieving offsetting changes in fair value.
As of December 31, 2002, we also have swap agreements that effectively convert the interest expense associated with $200 million of our variable rate debt to fixed rate. The maturity dates of these swap agreements range from September 2, 2003 to August 1, 2005. In the prior year, this hedge was designated a fair value hedge on our $200 million Floating Rate Senior Notes, which were retired in March 2002. Subsequent to the repayment of our Floating Rate Senior Notes, the swaps were designated as a cash flow hedge of the risk associated with changes in the designated benchmark interest rate (in this case, one-month LIBOR) related to forecasted payments associated with interest on an aggregate of $200 million of our portfolio of commercial paper.
In addition, our interest rate swaps 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 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 record interest expense equal to the variable rate payments or fixed rate payments under the swaps. Interest expense is accrued monthly and paid semi-annually. At December 31, 2002, we recognized an asset of $179.1 million and a liability of $12.1 million for the $167.0 million net fair value of our swap agreements, and we included these amounts with Deferred charges and other assets and Other long-term liabilities and deferred credits on the accompanying balance sheet. The offsetting entry to adjust the carrying value of the debt securities whose fair value was being hedged was recognized as Market value of interest rate swaps on the accompanying balance sheet. 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, and again, the offsetting entry to adjust the carrying value of the debt securities whose fair value was being hedged was recognized as Market value of interest rate swaps on the accompanying balance sheet.
We are exposed to credit related losses in the event of nonperformance by counterparties to these interest rate swap agreements. While we enter into derivative transactions only with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk.
15. Reportable Segments
We divide our operations into four reportable business segments (see Note 1):
o Products Pipelines;
o Natural Gas Pipelines;
o CO2 Pipelines; and
o 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 sale, gathering, transmission and storage of natural gas. Our CO2 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 and from the production of crude oil from fields in the Permian Basin of West Texas. 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):
2002 2001 2000 ---- ---- ---- Revenues Products Pipelines............. $ 576,542 $ 605,392 $ 420,272 Natural Gas Pipelines.......... 3,086,187 1,869,315 174,187 CO2 Pipelines.................. 146,280 122,094 89,214 Terminals...................... 428,048 349,875 132,769 ----------- ----------- ----------- Total consolidated revenues.... $4,237,057 $2,946,676 $ 816,442 =========== =========== =========== Operating income Products Pipelines............. $ 342,372 $ 298,991 $ 195,057 Natural Gas Pipelines.......... 253,498 171,899 97,349 CO2 Pipelines.................. 66,560 59,559 48,059 Terminals...................... 180,725 142,672 39,523 ----------- ----------- ----------- Total segment operating income. 843,155 673,121 379,988 Corporate administrative expenses..................... (118,857) (109,293) (64,427) ----------- ----------- ----------- Total consolidated operating income........................ $ 724,298 $ 563,828 $ 315,561 =========== =========== ===========
Earnings from equity investments, net of amortization of excess costs Products Pipelines............ $ 25,717 $ 22,686 $ 29,105 Natural Gas Pipelines......... 23,610 21,156 14,975 CO2 Pipelines................. 34,311 31,981 19,328 Terminals..................... 45 -- -- ----------- ----------- ----------- Consolidated equity earnings, net of amortization.......... $ 83,683 $ 75,823 $ 63,408 =========== =========== ===========
Interest revenue Products Pipelines.............. $ -- $ -- $ -- Natural Gas Pipelines........... -- -- -- CO2 Pipelines................... -- -- -- Terminals....................... -- -- --
----------- ----------- ----------- Total segment interest revenue.. -- -- -- ----------- ----------- ----------- Unallocated interest revenue.... 1,819 4,473 3,818 ----------- ----------- ----------- Total consolidated interest $ 1,819 $ 4,473 $ 3,818 revenue........................ =========== =========== ===========
Interest (expense) Products Pipelines.............. $ -- $ -- $ -- Natural Gas Pipelines........... -- -- -- CO2 Pipelines................... -- -- -- Terminals....................... -- -- -- ----------- ----------- ----------- Total segment interest (expense) -- -- -- ----------- ----------- ----------- Unallocated interest (expense).. (178,279) (175,930) (97,102) ----------- ----------- ----------- Total consolidated interest $ (178,279) $ (175,930) $ (97,102) (expense)...................... =========== =========== ===========
Other, net(a) Products Pipelines.............. $ (14,000) $ 440 $ 10,492 Natural Gas Pipelines........... 36 749 744 CO2 Pipelines................... 112 547 741 Terminals....................... 15,550 226 2,607 ----------- ----------- ----------- Total consolidated Other, net... $ 1,698 $ 1,962 $ 14,584 =========== =========== ===========
(a) 2002 amounts include non-recurring environmental expense adjustments resulting in a $15.7 million loss to our Products Pipelines business segment and a $16.0 million gain to our Terminals business segment.
2002 2001 2000 ---- ---- ---- Income tax benefit (expense) Products Pipelines.............. $ (10,154) $ (9,653) $ (11,960) Natural Gas Pipelines........... (378) -- -- CO2 Pipelines................... -- -- -- Terminals....................... (4,751) (6,720) (1,974) ----------- ----------- ----------- Total consolidated income tax benefit (expense).............. $ (15,283) $ (16,373) $ (13,934) =========== =========== ===========
Segment earnings Products Pipelines.............. $ 343,935 $ 312,464 $ 222,694 Natural Gas Pipelines........... 276,766 193,804 113,068 CO2 Pipelines................... 100,983 92,087 68,128 Terminals....................... 191,569 136,178 40,156 ----------- ----------- ----------- Total segment earnings.......... 913,253 734,533 444,046 Interest and corporate administrative expenses(a)..... (304,876) (292,190) (165,698) ----------- ----------- ----------- Total consolidated net income... $ 608,377 $ 442,343 $ 278,348 =========== =========== ===========
(a) Includes interest and debt expense, general and administrative expenses, minority interest expense and other insignificant items.
Assets at December 31 Products Pipelines............ $3,088,799 $3,095,899 $ 2,220,984 Natural Gas Pipelines......... 3,121,674 2,058,836 1,552,506 CO2 Pipelines................. 613,980 503,565 417,278 Terminals..................... 1,165,096 990,760 357,689 ----------- ----------- ----------- Total segment assets.......... 7,989,549 6,649,060 4,548,457 Corporate assets(a)........... 364,027 83,606 76,753 ----------- ----------- ----------- Total consolidated assets..... $8,353,576 $6,732,666 $4,625,210 =========== =========== ===========
(a) Includes cash, cash equivalents and certain unallocable deferred charges.
Depreciation and amortization Products Pipelines............ $ 64,388 $ 65,864 $ 40,730 Natural Gas Pipelines......... 48,411 31,564 21,709 CO2 Pipelines................. 29,196 17,562 10,559 Terminals..................... 30,046 27,087 9,632 ----------- ----------- ----------- Total consolidated depreciation and amortization............. $ 172,041 $ 142,077 $ 82,630 =========== =========== ===========
Investments at December 31 Products Pipelines............ $ 133,927 $ 225,561 $ 231,651 Natural Gas Pipelines......... 103,724 146,566 141,613 CO2 Pipelines................. 71,283 68,232 9,559 Terminals..................... 2,110 159 59 ----------- ----------- ----------- Total consolidated equity investments.................. 311,044 440,518 382,882 Investment in oil and gas assets to be contributed to joint venture........................ -- -- 34,163 ----------- ----------- ----------- $ 311,044 $ 440,518 $ 417,045 =========== =========== ===========
Capital expenditures Products Pipelines............ $ 62,199 $ 84,709 $ 69,243 Natural Gas Pipelines......... 194,485 86,124 14,496 CO2 Pipelines................. 163,183 65,778 16,115 Terminals..................... 122,368 58,477 25,669 ----------- ----------- ----------- Total consolidated capital expenditures................. $ 542,235 $ 295,088 $ 125,523 =========== =========== ===========
Our total operating revenues are derived from a wide customer base. For each of the years ended December 31, 2002 and 2001, one customer accounted for more than 10% of our total consolidated revenues. Total transactions within our Natural Gas Pipelines segment in 2002 with CenterPoint Energy accounted for 15.6% of our total consolidated revenues during 2002. Total transactions within our Natural Gas Pipelines and Terminals segment in 2001 with the Reliant Energy group of companies, including the entities which became CenterPoint Energy in October 2002, accounted for 20.2% of our total consolidated revenues during 2001. For the year ended December 31, 2000, 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, referred to herein as FERC, under the Interstate Commerce Act. The Interstate Commerce Act requires, among other things, that interstate petroleum products pipeline rates be just and reasonable and non-discriminatory. Pursuant to FERC Order No. 561, effective January 1, 1995, interstate 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 interstate 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, 2002, 2001 and 2000, the application of the indexing methodology did not significantly affect our tariff rates.
Federal Energy Regulatory Commission Proceedings
SFPP, L.P.
SFPP, L.P., referred to herein as SFPP, is the subsidiary limited partnership that owns our Pacific operations, excluding CALNEV Pipe Line LLC and related terminals acquired from GATX Corporation. Tariffs charged by SFPP are subject to certain proceedings at the FERC 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. Generally, the interstate rates on our Pacific operations' pipeline systems are "grandfathered" under the Energy Policy Act of 1992 unless "substantially changed circumstances" are found to exist. To the extent "substantially changed circumstances" are found to exist, our Pacific operations may be subject to substantial exposure under these FERC complaints.
The complainants have alleged a variety of grounds for finding "substantially changed circumstances." 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". Given the relative 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 will 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.
We currently believe that these FERC complaints seek approximately $197 million in tariff reparations and prospective annual tariff reductions, the aggregate average annual impact of which would be approximately $45 million. We are not able to predict with certainty the final outcome of the pending FERC proceedings involving SFPP, should they be carried through to their conclusion, or whether we can reach a settlement with some or all of the complainants.
However, even if "substantially changed circumstances" are found to exist, we believe that the resolution of these FERC complaints will be for amounts substantially less than the amounts sought and that the resolution of such matters will not have a material adverse effect on our business, financial position or results of operations.
OR92-8, et al. proceedings. In September 1992, El Paso Refinery, L.P. filed a protest/complaint with the FERC:
o challenging SFPP's East Line rates from El Paso, Texas to Tucson and Phoenix, Arizona;
o challenging SFPP's proration policy; and
o seeking to block the reversal of the direction of flow of SFPP's six-inch pipeline between Phoenix and Tucson.
At various subsequent dates, the following 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/or West Lines:
o Chevron U.S.A. Products Company;
o Navajo Refining Company;
o ARCO Products Company;
o Texaco Refining and Marketing Inc.;
o Refinery Holding Company, L.P. (a partnership formed by El Paso Refinery's long-term secured creditors that purchased its refinery in May 1993);
o Mobil Oil Corporation; and
o Tosco Corporation.
Certain of these parties also claimed that a gathering enhancement fee at SFPP's Watson Station in Carson, California was charged in violation of the Interstate Commerce Act.
The FERC consolidated these challenges in Docket Nos. OR92-8-000, et al., and ruled that they are complaint proceedings, with the burden of proof on the complaining parties. These parties must show that SFPP's rates and practices at issue violate the requirements of the Interstate Commerce Act.
A FERC administrative law judge held hearings in 1996, and issued an initial decision on September 25, 1997. The initial decision agreed with SFPP's position that "changed circumstances" had not been shown to exist on the West Line, and therefore held that all West Line rates that were "grandfathered" under the Energy Policy Act of 1992 were deemed to be just and reasonable and were not subject to challenge, either for the past or prospectively, in the Docket No. OR92-8 et al. proceedings. 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, was specifically excepted from that ruling.
The initial decision also included rulings generally adverse to SFPP on such cost of service issues as:
o the capital structure to be used in computing SFPP's 1985 starting rate base ;
o the level of income tax allowance; and
o the recovery of civil and regulatory litigation expenses and certain pipeline reconditioning costs.
The administrative law judge also ruled that SFPP's gathering enhancement service at Watson Station was subject to FERC jurisdiction and ordered SFPP to file a tariff for that service, with supporting cost of service documentation.
SFPP and other parties asked the FERC to modify various rulings made in the initial decision. On January 13, 1999, the FERC issued its Opinion No. 435, which affirmed certain of those rulings and reversed or modified others.
With respect to SFPP's West Line, the FERC affirmed 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 rate stated in Tariff No. 18 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 made several changes in the initial decision's methodology for calculating the rate base. It held that the June 1985 capital structure of SFPP's parent company at that time,
rather than SFPP's 1988 partnership capital structure, should be used to calculate the starting rate base and modified the accumulated deferred income tax and allowable cost of equity used to calculate the rate base. It also 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.
SFPP and certain complainants sought rehearing of Opinion No. 435 by the FERC. In addition, ARCO, RHC, Navajo, Chevron and SFPP filed petitions for review of Opinion No. 435 with the U.S. Court of Appeals for the District of Columbia Circuit, all of which were either dismissed as premature or held in abeyance pending FERC action on the rehearing requests.
On March 15, 1999, as required by the FERC's order, SFPP submitted a compliance filing implementing the rulings made in Opinion No. 435, establishing the level of rates to be charged by SFPP in the future, and setting forth the amount of reparations that would be owed by SFPP to the complainants under the order. The complainants contested SFPP's compliance filing.
On May 17, 2000, the FERC issued its Opinion No. 435-A, which modified Opinion No. 435 in certain respects. It denied requests to reverse its rulings that SFPP's West Line rates and Watson Station gathering enhancement facilities fee are entitled to be treated as "grandfathered" rates under the Energy Policy Act. It suggested, however, that if SFPP had fully recovered the capital costs of the gathering enhancement 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 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 with 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. That policy required customers to demonstrate a need for additional capacity if a shortage of available pipeline space existed. SFPP's prorationing policy has since been changed to eliminate the "demonstrated need" test.
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 fee, but required SFPP to pay refunds to the extent that the initial compliance tariff East Line rates exceeded the rates produced under Opinion No. 435-A.
In June 2000, several parties filed requests for rehearing of 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:
o decision to require use of the December 1988 partnership capital structure for the period 1984-88 in computing the starting rate base;
o elimination of civil litigation costs;
o refusal to allow any recovery of civil litigation settlement payments; and
o failure to provide any allowance for regulatory expenses in prospective rates.
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 stating revised East Line rates based on those rulings.
ARCO, Chevron, Navajo, RHC, Texaco and SFPP sought judicial review of Opinion No. 435-A in the U.S. Court of Appeals for the District of Columbia Circuit. All of those petitions except Chevron's were either dismissed as premature or held in abeyance pending action on the rehearing requests. On September 19, 2000, the court dismissed Chevron's petition for lack of prosecution, and subsequently denied a motion by Chevron for reconsideration of that dismissal.
On September 13, 2001, the FERC issued Opinion No. 435-B, which ruled on requests for rehearing and comments on SFPP's compliance filing. Based on those rulings, the FERC directed SFPP to submit a further revised compliance filing, including revised tariffs and revised estimates of reparations and refunds.
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 provision for regulatory costs in prospective rates. However, it modified the FERC's prior rulings on several other issues. It reversed the ruling that only Navajo is eligible to seek reparations, holding that Chevron, RHC, Tosco and Mobil are also eligible to recover reparations for East Line shipments. It ruled, however, that Ultramar is not eligible for reparations in the Docket No. OR92-8 et al. proceedings.
The FERC also changed prior rulings that had permitted SFPP to use 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. Opinion No. 435-B required SFPP to pay reparations to each complainant without any offset for unrecovered costs. It required SFPP to subtract from the total 1995-1998 supplemental costs allowed under Opinion No. 435-A any overearnings not paid out as reparations, and allowed SFPP to recover any remaining costs from shippers by means of a five-year surcharge beginning 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 include environmental or pipeline rehabilitation costs.
Opinion No. 435-B directed SFPP to make additional changes in its revised compliance filing, including:
o using a remaining useful life of 16.8 years in amortizing its starting rate base, instead of 20.6 years;
o removing the starting rate base component from base rates as of August 1, 2001;
o amortizing the accumulated deferred income tax balance beginning in 1992, rather than 1988;
o listing the corporate unitholders that were the basis for the income tax allowance in its compliance filing and certifying that those companies are not Subchapter S corporations; and
o "clearly" excluding civil litigation costs and explaining how it 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 asked the FERC to clarify:
o the period for which Chevron is entitled to reparations; and
o whether East Line shippers that have received the benefit of FERC-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 FERC's rate index in order to have standing to challenge SFPP rates for those years in pending or subsequent proceedings.
RHC's petition contended that Opinion No. 435-B should be modified on rehearing, to the extent it:
o suggested that a "substantial divergence" standard applies to complaint proceedings challenging the total level of SFPP's East Line rates subsequent to the Docket No. OR92-8 et al. proceedings;
o required 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
o permitted SFPP to recover 1993 rate case litigation expenses through a surcharge mechanism.
ARCO, Ultramar and SFPP filed petitions for 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 consolidated the Ultramar and SFPP petitions with the consolidated cases held in abeyance and ordered that the consolidated cases be returned to its active docket.
On November 7, 2001, the FERC issued an order ruling on the petitions for rehearing of Opinion No. 435-B. The FERC held that Chevron's eligibility for reparations should be measured from August 3, 1993, rather than the September 23, 1992 date sought by Chevron. The FERC 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 FERC's indexing regulations to the 1994 cost of service derived under the Opinion No. 435 orders must demonstrate a substantial divergence between the indexed rates and the pipeline's actual cost of service. Finally, the FERC held that SFPP's 1993 regulatory costs should not be included in the surcharge for the recovery of supplemental costs.
On November 20, 2001, SFPP submitted its compliance filing and tariffs implementing Opinion No. 435-B and the FERC's November 7, 2001 order. 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:
o should have calculated the supplemental cost surcharge differently;
o did not provide adequate information on the taxpaying status of its unitholders; and
o failed to estimate potential reparations for ARCO.
On December 7, 2001, Chevron filed a petition for rehearing of the FERC's November 7, 2001 order. The petition requested the FERC 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 December 10, 2001, SFPP filed a response to those claims. 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 FERC, on the ground that the FERC has no authority to require retroactive reductions of rates filed pursuant to its orders in complaint proceedings.
On January 7, 2002, SFPP and RHC filed petitions for review of the FERC's November 7, 2001 order in the U.S. Court of Appeals for the District of Columbia Circuit. 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 ordered the consolidated proceedings to be held in abeyance until the FERC acts on Chevron's request for rehearing of the November 7, 2001 order.
Motions to intervene and protest the December 14, 2001 corrected submissions were filed by Navajo, ARCO and ExxonMobil. 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.
On February 15, 2002, the FERC denied rehearing of the Director of the Division of Tariffs and Rates Central's letter orders. On February 21, 2002, SFPP filed a motion requesting that the FERC clarify whether it intended SFPP to file a retroactive tariff or simply make a compliance filing calculating the effects of Opinion No. 435-B back to August 1, 2000; in the event the order was clarified to require a retroactive tariff filing, SFPP asked the FERC to stay that requirement pending judicial review.
On April 8, 2002, SFPP filed a petition for review of the FERC's February 15, 2002 Order in the U.S. Court of Appeals for the District of Columbia Circuit. BP West Coast Products, LLC (formerly ARCO); ExxonMobil; Tosco Corporation; and Ultramar, Inc. and Valero Energy Corporation filed motions to intervene in that proceeding. On April 9, 2002, the Court of Appeals consolidated SFPP's petition with the petitions for review of the FERC's prior orders and directed the parties "to file motions to govern future proceedings" by May 9, 2002. Motions were filed by SFPP, RHC, Navajo, Chevron and the "Indicated Parties" (BP West Coast Products, ExxonMobil, Ultramar and Tosco). The FERC requested that the Court of Appeals continue to hold the consolidated cases in abeyance pending the completion of proceedings before the agency on rehearing.
On June 25, 2002, the Court of Appeals granted the ExxonMobil and Valero Energy motions to intervene, and directed intervenors on the side of petitioners to notify the court of that status and provide a statement of issues to be raised. ExxonMobil filed a notice on July 2, 2002; Ultramar, Inc. and Valero Energy on July 10, 2002. On July 12, 2002, SFPP responded to the ExxonMobil notice in order to urge the Court of Appeals not to rely on ExxonMobil's categorization of the issues and party alignments in allocating briefing.
On May 31, 2002, SFPP filed FERC Tariff No. 70, which implemented the FERC's annual indexing adjustment. Motions to intervene and protest were filed by Navajo and Chevron, contesting any indexing adjustment to the litigation surcharge permitted by Opinion No. 435-B. On June 28, 2002, the FERC's Director of the Division of Tariffs and Rates rejected Tariff No. 70 on the ground that the surcharge should not be indexed. On July 2, 2002, SFPP filed FERC Tariff No. 73 to replace Tariff No. 70 in compliance with that decision, which resulted in an average reduction from Tariff No. 70 of approximately $.0002 per barrel.
On September 26, 2002, the FERC issued an order ruling on the protests against SFPP's November 20, 2001 and December 14, 2001 compliance filings implementing Opinion No. 435-B and the November 7, 2001 Order. The FERC held that:
o SFPP must measure supplemental costs against the total amount of reparations for the entire reparations period (as opposed to year-by-year);
o SFPP will not be permitted to include in its supplemental costs (a) litigation expenses incurred during 1999 and 2000 or (b) payments made to Navajo and RHC to settle certain FERC litigation;
o the tariff surcharge collected by SFPP for all shipments between August 1, 2000 and December 1, 2001 is subject to refund; and
o in calculating its tax allowance, SFPP must exclude the ownership interest attributable to an entity that the FERC found to be a mutual fund.
The FERC rejected the requests by Navajo, BP West Coast Products and ExxonMobil to extend the period for which they are entitled to reparations beyond the periods specified in prior orders.
The September 26, 2002 Order also ruled on SFPP's request for clarification of the February 15, 2002 Order as to whether it was required to make a retroactive tariff filing or rather a compliance filing calculating the effects of Opinion No. 435-B beginning August 1, 2000. The FERC held that SFPP was required to file a tariff retroactive to August 1, 2000. The FERC did not rule on SFPP's alternative request for a stay. The FERC also ruled on Chevron's request for rehearing of the November 7, 2001 Order, clarifying that Chevron was eligible for reparations for shipments on the East Line for the two years prior to the filing of its complaint.
On October 22, 2002, ExxonMobil filed a Request for Clarification or, in the Alternative, Rehearing of the September 26, 2002 Order. ExxonMobil requested that the FERC clarify that ExxonMobil was eligible for reparations for East Line rates.
On October 25, 2002, SFPP filed Tariff No. 75 implementing changes required by the September 26, 2002 Order, and on October 28, 2002, SFPP submitted a compliance filing pursuant to that order. Valero Marketing and Supply Company filed a motion to intervene and protest regarding the compliance filing and tariff, and Tosco Corporation protested the compliance filing. Navajo Refining Company, L.P. moved to intervene in proceedings relating to the tariff, and Chevron Products Company and Equilon Enterprises LLC filed comments and related pleadings challenging the compliance filing and seeking additional relief.
On January 29, 2003, the FERC issued an order accepting the October 28, 2002 compliance filing subject to the condition that SFPP recalculate gross reparations in determining its per barrel surcharge and submit a revised tariff reflecting that change within fifteen days of the order. The FERC rejected all other challenges to that compliance filing.
Following the September 26, 2002 Order, several parties filed motions to govern future proceedings with the U.S. Court of Appeals for the District of Columbia Circuit. BP West Coast Products LLC and ExxonMobil (the "Indicated Parties") and Valero Energy Corporation, Ultramar Inc. and Tosco Corporation (the "Joint Parties") requested that the court return the petitions for review to its active docket but sever the docket involving compliance filing issues. The FERC filed a motion that did not take a definitive position on whether the petitions for review should continue to be held in abeyance, but noted that compliance filing issues were still pending before the FERC. SFPP, Chevron, Navajo and RHC filed responses to the motions to govern future proceedings. On December 6, 2002, the Court of Appeals granted the motion of the "Indicated Parties" and "Joint Parties" to return the petitions for review to the Court's active docket. The Court also severed the docket relating to compliance filing issues and directed the parties to submit a proposed briefing schedule and format. On January 6, 2003, SFPP and FERC filed a joint briefing proposal, and the shipper parties jointly filed a separate briefing proposal.
On October 18, 2002, Chevron filed a petition for review of Opinion Nos. 435, 435-A and 435-B in the U.S. Court of Appeals for the District of Columbia Circuit. The Court of Appeals consolidated that petition with the main docket on November 20, 2002. Tosco Corporation and BP West Coast Products LLC moved to intervene in that docket, and those motions were granted on December 10, 2002.
Petitions for review of the September 26, 2002 Order have been filed in the U.S. Court of Appeals for the District of Columbia Circuit by Navajo, on October 24, 2002, and by SFPP, on November 8, 2002. The Court consolidated those petitions with the main docket on November 5, 2002 and November 12, 2002, respectively. Valero Marketing and Supply Company moved to intervene in both dockets and Tosco Corporation moved to intervene in the docket for the SFPP petition. On January 6, 2003, Valero Marketing and Supply Company filed a motion to substitute itself for Ultramar Diamond Shamrock Corporation in Ultramar's petition for review of Opinion No. 435-B. On January 21, 2003 SFPP filed a response, stating that it did not object to the proposed substitution provided Valero Marketing and Supply Corporation was not permitted to create or enlarge any claim for damages.
On January 24, 2003, ConocoPhillips filed a motion to substitute itself for Tosco Corporation in the consolidated dockets, and on January 27, 2003, filed a similar motion in the severed docket relating to compliance filing issues.
Sepulveda proceedings. In December 1995, Texaco filed a complaint at FERC (Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipelines (Line Sections 109 and 110) to Watson Station, in the Los Angeles basin, were subject to FERC's jurisdiction under the Interstate Commerce Act, and, if so, claimed that the rate for that service was unlawful. Texaco sought to have its claims addressed in the OR92-8 proceeding discussed above. Several other West Line shippers filed similar complaints and/or motions to intervene. The FERC consolidated all of these filings into Docket No. OR96-2 and set the claims for a separate hearing. A hearing before an administrative law judge was held in December 1996.
In March 1997, the judge issued an initial decision holding that the movements on the Sepulveda pipelines were not subject to FERC jurisdiction. On August 5, 1997, the FERC reversed that decision. On October 6, 1997, SFPP filed a tariff establishing the initial interstate rate for movements on the Sepulveda pipelines at the preexisting rate of five cents per barrel. Several shippers protested that rate. In December 1997, SFPP filed an application for authority to charge a market-based rate for the Sepulveda service, which application was protested by several parties. On September 30, 1998, the FERC issued an order finding that SFPP lacks market power in the Watson Station destination market and that, while SFPP appeared to lack market power in the Sepulveda origin market, a hearing was necessary to permit the protesting parties to substantiate allegations that SFPP possesses market power in the origin market. A hearing before a FERC administrative law judge on this limited issue was 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 origin market. The ultimate disposition of SFPP's 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 pipelines. On February 22, 2001, the FERC granted SFPP's motion to block such consideration and to defer consideration of the pending complaints against the Sepulveda rate until after FERC's final disposition of SFPP's market rate application.
OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar filed a complaint at FERC (Docket No. OR97-2) challenging SFPP's West Line rates, claiming they were unjust and unreasonable and no longer subject to grandfathering. In October 1997, ARCO, Mobil and Texaco filed a complaint at the FERC (Docket No. OR98-1) challenging the justness and reasonableness of all of SFPP's interstate rates, raising claims against SFPP's East and West Line rates similar to those that have been at issue in Docket Nos. OR92-8, et al. discussed above, but expanding them to include challenges to SFPP's grandfathered interstate rates from the San Francisco Bay area to Reno, Nevada and from Portland to Eugene, Oregon - the North Line and Oregon Line. In November 1997, Ultramar Diamond Shamrock Corporation filed a similar, expanded complaint (Docket No. OR98-2). Tosco Corporation filed a similar complaint in April 1998. The shippers seek both reparations and prospective rate reductions for movements on all of the lines. SFPP answered each of these complaints. FERC issued orders accepting the complaints and consolidating them into one proceeding (Docket No. OR96-2, et al.), but holding them in abeyance pending a FERC decision on review of the initial decision in Docket Nos. OR92-8, et al.
In a companion order to Opinion No. 435, the FERC gave the complainants an opportunity to amend their complaints in light of Opinion No. 435, which the complainants did in January 2000. On May 17, 2000, the FERC issued an order finding that the various complaining parties had alleged sufficient grounds for their complaints to go forward to a hearing to 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.
In August 2000, Navajo and RHC filed complaints against SFPP's East Line rates and Ultramar filed an additional complaint updating its pre-existing challenges to SFPP's interstate pipeline rates. In September 2000, FERC accepted these new complaints and consolidated them with the ongoing proceeding in Docket No. OR96-2, et al.
A hearing in this consolidated proceeding was held from October 2001 to March 2002. An initial decision by the administrative law judge is expected in the first half of 2003.
OR02-4 proceedings. On February 11, 2002, Chevron, an intervenor in the OR96-2 proceeding, filed a complaint against SFPP in Docket No. OR02-4 along with a motion to consolidate the complaint with the OR96-2 proceeding. On May 21, 2002, the FERC dismissed Chevron's complaint and motion to consolidate. Chevron filed a request for rehearing and on September 25, 2002, the FERC dismissed Chevron's rehearing request. In October 2002, Chevron filed a request for rehearing of the FERC's September 25 order. The FERC has indicated that it intends to rule on Chevron's request in February 2003. Chevron continues to participate in the OR96-2 proceeding as an intervenor.
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.
In April 2002, Chevron filed a complaint against CALNEV's interstate rates, making allegations of unjust and unreasonable rates. CALNEV answered Chevron's complaint on May 16, 2002, and Chevron moved for leave to respond to CALNEV's answer on June 17, 2002.
In September of 2002, CALNEV and Chevron were able to reach a mutually agreeable resolution of the disputed claims, and a settlement was executed. In the settlement agreement, the parties agreed, among other things, that for a period of five years, CALNEV would not seek a rate increase at the FERC or the California Public Utilities Commission except as permitted under four specific exceptions and that Chevron would not file complaints against CALNEV's rates, provided it complies with such exceptions. On October 10, 2002, the FERC granted the parties' joint motion to dismiss the complaint with prejudice.
Trailblazer Pipeline Company
As required by its last rate case settlement, Trailblazer Pipeline Company made a general rate case filing at FERC on November 29, 2002. The filing provides for a small rate decrease and also includes a number of non-rate tariff changes. By an order issued December 31, 2002, FERC effectively bifurcated the proceeding. The rate change was accepted to be effective on January 1, 2003, subject to refund and a hearing. Most of the non-rate tariff changes were suspended until June 1, 2003, subject to refund and a technical conference procedure.
Trailblazer has sought rehearing of the FERC order with respect to the refund condition on the rate decrease. The Indicated Shippers have sought rehearing as to FERC acceptance of certain non-rate tariff provisions. A prehearing conference on the rate issues was held on January 16, 2003. A procedural schedule was established under which the hearing will commence on October 8, 2003, if the case is not settled. Discovery has commenced as to rate issues.
The technical conference on non-rate issues was held on February 6, 2003. Those issues include:
o capacity award procedures;
o credit procedures;
o imbalance penalties; and
o the maximum length of bid terms considered for evaluation in the right of first refusal process.
Initial and reply comments on these issues as discussed at the technical conference are due March 7, 2003 and March 18, 2003, respectively.
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 within three to four months.
The CPUC has recently issued a resolution approving a 2001 request by SFPP to raise its California rates to reflect increased power costs. The resolution approving the requested rate increase also requires SFPP to submit cost data for 2001, 2002, and 2003 to assist the CPUC in determining whether SFPP's overall rates for California intrastate transportation services are reasonable. The resolution reserves the right to require refunds, from the date of issuance of the resolution, to the extent the CPUC's analysis of cost data to be submitted by SFPP demonstrates that SFPP's California jurisdictional rates are unreasonable in any fashion.
There is no way to quantify the potential extent to which the CPUC could determine that SFPP's existing California rates are unreasonable or estimate the amount of dollars potentially subject to refund as a consequence of the CPUC resolution requiring the provision by SFPP of cost-of-service data. SFPP believes that submission of the required, representative cost data required by the CPUC will indicate that SFPP's existing rates for California intrastate services remain reasonable and that no refunds are justified.
We believe that the resolution of such matters will not have a material adverse effect on our business, financial position or results of operations.
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 the 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 FERC. 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. Several parties protested the November 19, 2001 compliance filing. KMIGT filed responses to those protests on December 14, 2001. At this time, it is unknown when this proceeding will be finally resolved. 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 court in December 2001. On April 5, 2002, the D.C. Circuit issued an order largely affirming Order Nos. 637, et seq. The D.C. Circuit remanded the FERC's decision to impose a 5-year cap on bids that an existing shipper would have to match in the right of first refusal process. The D.C. Circuit also remanded the FERC's decision to allow forward-hauls and backhauls to the same point. Finally, the D.C. Circuit held that several aspects of the FERC's segmentation policy and its policy on discounting at alternate points were not ripe for review. The FERC requested comments from the industry with respect to the issues remanded by the D.C. Circuit. They were due July 30, 2002.
On October 31, 2002, the FERC issued an order in response to the D.C. Circuit's remand of certain Order 637 issues. The order:
o eliminated the requirement of a 5-year cap on bid terms that an existing shipper would have to match in the right of first refusal process, and found that no term matching cap is necessary given existing regulatory controls;
o affirmed FERC's policy that a segmented transaction consisting of both a forwardhaul up to contract demand and a backhaul up to contract demand to the same point is permissible; and
o accordingly required, under Section 5 of the NGA, pipelines that the FERC had previously found must permit segmentation on their systems to file tariff revisions within 30 days to permit such segmented forwardhaul and backhaul transactions to the same point.
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's compliance filing reflected changes in:
o segmentation;
o scheduling for capacity release transactions;
o receipt and delivery point rights;
o treatment of system imbalances;
o operational flow orders;
o penalty revenue crediting; and
o right of first refusal language.
On October 15, 2001, FERC issued its order on Trailblazer's Order No. 637 compliance filing. FERC approved Trailblazer's proposed language regarding operational flow orders and the right of first refusal, but required Trailblazer to make changes to its tariff related to the other issues listed above.
On November 14, 2001, Trailblazer 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 filed for rehearing of that FERC order. These pleadings are pending FERC action.
Trailblazer anticipates no adverse impact on its business as a result of the implementation of Order No. 637.
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 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. Numerous parties, including KMIGT, have filed comment on the Proposed Standards of Conduct Rulemaking. On May 21, 2002, FERC held a technical conference dealing with the FERC's proposed changes in the Standard of Conduct Rulemaking. On June 28, 2002, KMIGT and numerous other parties flied additional written comments under a procedure adopted at the technical conference. The Proposed Rulemaking is awaiting further FERC action. We believe that these matters, as finally adopted, will not have a material adverse effect on our business, financial position or results of operations.
The FERC also issued a Notice of Proposed Rulemaking in Docket No. RM02-14-000 in which it proposed new regulations for cash management practices, including establishing limits on the amount of funds that can be swept from a regulated subsidiary to a non-regulated parent company. Kinder Morgan Interstate Gas Transmission LLC filed comments on August 28, 2002. We believe that these matters, as finally adopted, 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 claims that the rent payable for each of the years 1994 through 2004 should be approximately $4.4 million and SPTC claims it should be approximately $15.0 million. We believe SPTC's position in this case is without merit and we have set aside reserves that we believe are adequate to address any reasonably foreseeable outcome of this matter. As of early-February 2003, the matter is currently in trial.
Carbon Dioxide Litigation
Kinder Morgan CO2 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: CO2 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. filed 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); 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).
At a hearing conducted in the United States District Court for the District of Colorado on April 8, 2002, the Court orally announced that it had approved the certification of proposed plaintiff classes and approved a proposed settlement in the CO2 Claims Coalition, LLC, Rutter & Wilbanks, Watson, Ainsworth and United States ex rel. Crowley cases. The Court entered a written order approving the Settlement on May 6, 2002; plaintiffs counsel representing Shores, et al. appealed the court's decision to the 10th Circuit Court of Appeals. On December 26, 2002, the 10th Circuit Court of Appeals affirmed in all respects the District Court's Order approving settlement.
Following the decision of the 10th Circuit, the Plaintiffs and Defendants jointly filed motions to abate the Shell Western E&P Inc., Shores and First State Bank of Denton cases in order to afford the parties time to discuss potential settlement. These Motions were granted on February 6, 2003. In the Celeste C. Grynberg case, the parties are currently engaged in discovery.
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. Certain entities we acquired in the Kinder Morgan Tejas acquisition are also defendants in this matter. 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. On December 15, 2001, the defendants filed motions to transfer venue on jurisdictional grounds. There are no further pretrial proceedings at this time.
Will Price, et al. v. Gas Pipelines, et al., (f/k/a Quinque Operating Company et al. v. Gas Pipelines, et al.)
Stevens County, Kansas District Court, Case No. 99 C 30. In May, 1999, three plaintiffs, Quinque Operating Company, Tom Boles and Robert Ditto, filed a purported nationwide class action in the Stevens County, Kansas District Court against some 250 natural gas pipelines and many of their affiliates. The District Court is located in Hugoton, Kansas. Certain entities we acquired in the Kinder Morgan Tejas acquisition are also defendants in this matter. The Petition (recently amended) alleges a conspiracy to underpay royalties, taxes and producer payments by the defendants' undermeasurement of the volume and heating content of natural gas produced from nonfederal lands for more than twenty-five years. The named plaintiffs purport to adequately represent the interests of unnamed plaintiffs in this action who are comprised of the nation's gas producers, State taxing agencies and royalty, working and overriding owners. The plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees from the defendants, jointly and severally. This action was originally filed on May 28, 1999 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. Subsequently, one of the defendants removed the action to Kansas Federal District Court and the case was styled as Quinque Operating Company, et al. v. Gas Pipelines, et al., Case No. 99-1390-CM, United States District Court for the District of Kansas. 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 cases referred to below, because of common factual questions. On April 10, 2000, the MDL Panel ordered that this case be consolidated with the Grynberg federal False Claims Act cases discussed below. 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. The Court in Kansas has issued a case management order addressing the initial phasing of the case. In this initial phase, the court will rule on motions to dismiss (jurisdiction and sufficiency of pleadings), and if the action is not dismissed, on class certification. Merits discovery has been stayed.
Recently, the defendants filed a motion to dismiss on grounds other than personal jurisdiction, which was denied by the Court in August, 2002. The Motion to Dismiss for lack of Personal Jurisdiction of the nonresident defendants has been briefed and is awaiting decision. The current named plaintiffs are Will Price, Tom Boles, Cooper Clark Foundation and Stixon Petroleum, Inc. Quinque Operating Company has been dropped from the action as a named plaintiff. On January 13, 2003, a motion to certify the class was argued. A decision on this moton is pending.
United States of America, ex rel., Jack J. Grynberg v. K N Energy
Civil Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado. This action was filed on June 9, 1997 pursuant to the federal False Claim Act and involves allegations of mismeasurement of natural gas produced from federal and Indian lands. The Department of Justice has decided not to intervene in support of the action. The complaint is part of a larger series of similar complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately 330 other defendants). Certain entities we acquired in the Kinder Morgan Tejas acquisition are also defendants in this matter. An earlier single action making substantially similar allegations against the pipeline industry was dismissed by Judge Hogan of the U.S. District Court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, Mr. Grynberg filed individual complaints in various courts throughout the country. In 1999, these cases were consolidated by the Judicial Panel for Multidistrict Litigation, and transferred to the District of Wyoming. The multidistrict litigation matter is called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. Motions to dismiss were filed and an oral argument on the motion to dismiss occurred on March 17, 2000. On July 20, 2000 the United States of America filed a motion to dismiss those claims by Grynberg that deal with the manner in which defendants valued gas produced from federal leases, referred to as valuation claims. Judge Downes denied the defendant's motion to dismiss on May 18, 2001. The United States' motion to dismiss most of plaintiff's valuation claims has been granted by the court. Grynberg has appealed that dismissal to the 10th Circuit, which has requested briefing regarding its jurisdiction over that appeal. Discovery is now underway to determine issues related to the Court's subject matter jurisdiction, arising out of the False Claim Act.
Sweatman and Paz Gas Corporation v. Gulf Energy Marketing, LLC, et al.
Mel R. Sweatman and Paz Gas Corporation vs. Gulf Energy Marketing, LLC, et al. On July 25, 2002, we were served with this suit for breach of contract, tortious interference with existing contractual relationships, conspiracy to commit tortuous interference and interference with prospective business relationship. Mr. Sweatman and Paz Gas Corporation claim that, in connection with our acquisition of Tejas Gas, LLC, we wrongfully caused gas volumes to be shipped on our Kinder Morgan Texas Pipeline system instead of our Kinder Morgan Tejas system. Mr. Sweatman and Paz Gas Corporation allege that this action eliminated profit on Kinder Morgan Tejas, a portion of which Mr. Sweatman and Paz Gas Corporation claim they are entitled under an agreement with a subsidiary of ours acquired in the Tejas Gas acquisition. We have filed a motion to remove the case from venue in Dewitt County, Texas to Harris County, Texas, and our motion was denied in a venue hearing in November 2002.
In a Second Amended Original Petition, Sweatman and Paz assert new and distinct allegations against us, principally that we were a party to an alleged commercial bribery committed by us, Gulf Energy Marketing, and Intergen inasmuch as we, in our role as acquirer of Kinder Morgan Tejas, allegedly paid Intergen to non-renew the underlying Entex contracts belonging to the Tejas/Paz joint venture. Moreoever, new and distinct allegations of breach of fiduciary and bribery of a fiduciary are also raised in this amended petition for the first time.
Based on the information available to date and our preliminary investigation, we believe this suit is without merit and we intend to defend it vigorously.
Maher et ux. v. Centerpoint Energy, Inc. d/b/a Reliant Energy, Incorporated, Reliant Energy Resources Corp., Entex Gas Marketing Company, Kinder Morgan Texas Pipeline, L.P., Kinder Morgan Energy Partners, L.P., Houston Pipeline Company, L.P. and AEP Gas Marketing, L.L.C., No. 30875 (District Court, Wharton County Texas).
On October 21, 2002, Kinder Morgan Texas Pipeline, L.P. and Kinder Morgan Energy Partners, L.P. were served with the above-entitled Complaint. A First Amended Complaint was served on October 23, 2002, adding additional defendants Kinder Morgan G.P., Inc., Kinder Morgan Tejas Pipeline GP, Inc., Kinder Morgan Texas Pipeline GP, Inc., Tejas Gas, LLC and HPL GP, LLC. The First Amended Complaint purports to bring a class action on behalf of those Texas residents who purchased natural gas for residential purposes from the so-called "Reliant Defendants" in Texas at any time during the period encompassing "at least the last ten years."
The Complaint alleges that Reliant Energy Resources Corp., by and through its affiliates, has artificially inflated the price charged to residential consumers for natural gas that it allegedly purchased from the non-Reliant defendants, including the above-listed Kinder Morgan entities. The Complaint further alleges that in exchange for Reliant Energy Resources Corp.'s purchase of natural gas at above market prices, the non-Reliant defendants, including the above-listed Kinder Morgan entities, sell natural gas to Entex Gas Marketing Company at prices substantially below market, which in turn sells such natural gas to commercial and industrial consumers and gas marketers at market price. The Complaint purports to assert claims for fraud, violations of the Texas Deceptive Trade Practices Act, and violations of the Texas Utility Code against some or all of the Defendants, and civil conspiracy against all of the defendants, and seeks relief in the form of, inter alia, actual, exemplary and statutory damages, civil penalties, interest, attorneys' fees and a constructive trust ab initio on any and all sums which allegedly represent overcharges by Reliant and Reliant Energy Resources Corp.
On November 18, 2002, the Kinder Morgan defendants filed a Motion to Transfer Venue and, Subject Thereto, Original Answer to the First Amended Complaint. The parties are currently engaged in preliminary discovery. Based on the information available to date and our preliminary investigation, the Kinder Morgan defendants believe that the claims against them are without merit and intend to defend against them vigorously.
Marie Snyder, et al v. City of Fallon, United States Department of the Navy, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Speedway Gas Station and John Does I-X, No. cv-N-02-0251-ECR-RAM (United States District Court, District of Nevada)("Snyder"); and Frankie Sue Galaz, et al v. United States of America, City of Fallon, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Berry Hinckley, Inc., and John Does I-X, No. cv-N-02-0630-DWH-RAM (United States District Court, District of Nevada)("Galaz").
On July 9, 2002, we were served with a purported Complaint for Class Action in the Snyder case, in which the plaintiffs, on behalf of themselves and others similarly situated, assert that a leukemia cluster has developed in the City of Fallon, Nevada. The Complaint alleges that the plaintiffs have been exposed to unspecified "environmental carcinogens" at unspecified times in an unspecified manner and are therefore "suffering a significantly increased fear of serious disease." The plaintiffs seek a certification of a class of all persons in Nevada who have lived for at least three months of their first ten years of life in the City of Fallon between the years 1992 and the present who have not been diagnosed with leukemia.
The Complaint purports to assert causes of action for nuisance and "knowing concealment, suppression, or omission of material facts" against all defendants, and seeks relief in the form of "a court-supervised trust fund, paid for by defendants, jointly and severally, to finance a medical monitoring program to deliver services to members of the purported class that include, but are not limited to, testing, preventative screening and surveillance for conditions resulting from, or which can potentially result from exposure to environmental carcinogens," incidental damages, and attorneys' fees and costs.
The defendants responded to the Complaint by filing Motions to Dismiss on the grounds that it fails to state a claim upon which relief can be granted. On November 7, 2002, the United States District Court granted the Motion to Dismiss filed by the United States, and further dismissed all claims against the remaining defendants for lack of Federal subject matter jurisdiction. Plaintiffs filed a Motion for Reconsideration and Leave to Amend, which was denied by the Court on December 30, 2002. Plaintiffs have filed a Notice of Appeal to the United States Court of Appeals for the 9th Circuit, which appeal is currently pending.
On December 3, 2002, plaintiffs filed an additional Complaint for Class Action in the Galaz matter asserting the same claims in the same Court on behalf of the same purported class against virtually the same defendants, including us. On February 10, 2003, the defendants filed Motions to Dismiss the Galaz Complaint on the grounds that it also fails to state a claim upon which relief can be granted. This motion is currently pending before the court.
Based on the information available to date and our preliminary investigation, we believe that the claims against us in the Snyder and Galaz matters are without merit and intend to defend against them vigorously.
Although no assurances can be given, we believe that we have meritorious defenses to all of these actions, that, to the extent an assessment of the matter is possible, 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.
Walter Chandler v. Plantation Pipe Line Company
On October 2, 2001, the jury rendered a verdict against Plantation Pipe Line Company in the case of Walter Chandler v. Plantation Pipe Line Company. The jury awarded the plaintiffs a total of $43.8 million. The judge reduced the award to $42.6 million due to a prior settlement with the plaintiffs by a third party.
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. As noted above, a current remediation effort is taking place among Chevron, Plantation and Alabama Department of Environmental Management.
In addition to the Chandler case, in 1998 and 1999, other entities and individuals living in close proximity to the Chandlers filed lawsuits against Plantation, Chevron and an environmental consulting firm, CH2MHill, alleging property damage and personal injuries from groundwater contaminated with petroleum hydrocarbons. In February 2003, Plantation settled, through a confidential settlement, all of these lawsuits as well as the Chandler litigation. Plantation believes that the settlement of these lawsuits and the Chandler litigation will not have a material adverse effect on its business, financial position or results of operations.
Marion County, Mississippi Litigation
In 1968, Plantation discovered a release from its 12-inch pipeline in Marion County, Mississippi. The pipeline was immediately repaired. In 1998 and 1999, 62 lawsuits were filed on behalf of 263 plaintiffs in the Circuit Court of Marion County, Mississippi. The majority of the claims are based on alleged exposure from the 1968 release, including claims for property damage and personal injury. Plantation has resolved some of the lawsuits but lawsuits by 236 of the plaintiffs are still pending. Although a trial date has not been set for any of the remaining cases, it is anticipated that a trial on a portion of the lawsuits will be scheduled in 2003. Plantation believes that the ultimate resolution of these Marion County, Mississippi cases will not have a material effect on its 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 and have established a reserve to address the costs associated with the cleanup:
o 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;
o several ground water hydrocarbon remediation efforts under administrative orders issued by the California Regional Water Quality Control Board and two other state agencies;
o 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; and
o a ground water remediation effort taking place between Chevron, Plantation Pipe Line Company and the Alabama Department of Environmental Management.
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.
Furthermore, our review of assets related to Kinder Morgan Interstate Gas Transmission LLC indicates possible environmental impacts from petroleum and used oil releases into the soil and groundwater at nine sites. Additionally, our review of assets related to Kinder Morgan Texas Pipeline indicates possible environmental impacts from petroleum releases into the soil and groundwater at six sites. Further delineation and remediation of any environmental impacts from these matters will be conducted. Reserves have been established to address the closure of these issues.
Although no assurance can be given, we believe that the ultimate resolution of the 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 $52.7 million at December 31, 2002. As of December 31, 2002, we were not able to reasonably estimate when the eventual settlements of these claims will occur.
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.
In addition to the matters described above, we may face additional challenges to our rates in the future. Shippers on our pipelines do have rights to challenge the rates we charge under certain circumstances prescribed by applicable regulations. There can be no assurance that we will not face challenges to the rates we receive for services on our pipeline systems in the future. In addition, since many of our assets are subject to regulation, we are subject to potential future changes in applicable rules and regulations that may have an adverse effect 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 26, 2003
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.
CERTIFICATIONS
I, Richard D. Kinder, certify that:
1. I have reviewed this annual report on Form 10-K of Kinder Morgan Energy Partners, L.P.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the periods covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
/s/ Richard D. Kinder ------------------------------ Richard D. Kinder Chairman and Chief Executive Officer
Date: February 26, 2003
I, C. Park Shaper, certify that:
1. I have reviewed this annual report on Form 10-K of Kinder Morgan Energy Partners, L.P.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the periods covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
/s/ C. Park Shaper ------------------------------ C. Park Shaper Vice President, Treasurer and Chief Financial Officer
Date: February 26, 2003