PACIFIC ENERGY GP, INC. (Note 1)
CONSOLIDATED BALANCE SHEET
December 31, 2002
| | December 31, 2002 | |||||
|---|---|---|---|---|---|---|
| | (in thousands) | |||||
| Current assets: | ||||||
| Cash and cash equivalents | $ | 24,158 | ||||
| Crude oil sales receivable | 24,157 | |||||
| Transportation accounts receivable | 10,568 | |||||
| Crude oil inventory | 3,887 | |||||
| Spare parts inventory | 445 | |||||
| Prepaid expenses | 2,720 | |||||
| Other | 421 | |||||
| Total current assets | 66,356 | |||||
| Property and equipment, net | 404,842 | |||||
| Investment in Frontier (notes 1 and 4) | 9,175 | |||||
| Other assets | 6,950 | |||||
| $ | 487,323 | |||||
| Current liabilities: | ||||||
| Accounts payable | $ | 2,768 | ||||
| Accrued crude oil purchases | 24,385 | |||||
| Provision for right-of-way costs (note 9) | 350 | |||||
| Accrued power costs | 1,706 | |||||
| Accrued interest payable | 2,542 | |||||
| Due to related parties (note 8) | 539 | |||||
| Derivatives liability—current portion (note 1) | 4,775 | |||||
| Other | 4,909 | |||||
| Total current liabilities | 41,974 | |||||
| Long-term debt (note 7) | 225,000 | |||||
| Derivatives liability (note 1) | 2,600 | |||||
| Minority interest | 150,033 | |||||
| Other liabilities (note 13) | 2,600 | |||||
| Total liabilities | 422,207 | |||||
| Commitments and contingencies (note 13) | ||||||
| Stockholder's equity: | ||||||
| Common stock, 1,000 shares authorized, $0.01 par value, 100 shares issued | 1 | |||||
| Additional paid-in-capital | 66,808 | |||||
| Accumulated other comprehensive loss (note 1) | (4,403 | ) | ||||
| Retained earnings | 2,710 | |||||
| Total owners' equity | 65,116 | |||||
| $ | 487,323 | |||||
See accompanying notes to consolidated financial statement.
F-1
PACIFIC ENERGY GP, INC.
Notes to Consolidated Financial Statement
December 31, 2002
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The accompanying consolidated balance sheet as of December 31, 2002 includes the accounts of Pacific Energy GP, Inc. (the "General Partner"), an indirect wholly owned subsidiary of The Anschutz Corporation ("Anschutz"), and Pacific Energy Partners, L.P. (the "Partnership"). At December 31, 2002, the General Partner has an effective ownership in the Partnership of 59.7%. This effective ownership is derived through its ownership of a 2.0% general partner interest and its ownership of 57.7% of the limited partner interests. The remaining ownership interest of 40.3%, owned by third parties, is reflected on the balance sheet as "minority interest". The consolidated balance sheet presents the General Partner as a single entity, separate from Anschutz, as of December 31, 2002. All significant intercompany balances and transactions have been eliminated during the consolidation process.
On July 26, 2002, the Partnership completed an initial public offering of common units representing limited partner interests in the Partnership. The Partnership, which was formed by Anschutz in February 2002, and its subsidiaries are engaged in gathering, blending, transporting, storing, marketing and distributing crude oil.
Anschutz, through the General Partner, conveyed to the Partnership its ownership interests in Pacific Energy Group LLC ("PEG"), whose subsidiaries consist of: (i) Pacific Pipeline System LLC ("PPS"), owner of Line 2000 and the Line 63 system, (ii) Pacific Marketing and Transportation LLC ("PMT"), owner of the PMT gathering and blending assets, (iii) Rocky Mountain Pipeline System LLC ("RMP"), owner of the Western Corridor system and the Salt Lake City Core system assets purchased from an affiliate of BP plc on March 1, 2002, (iv) Anschutz Ranch East Pipeline LLC ("AREPI"), owner of AREPI pipeline and successor to Anschutz Ranch East Pipeline, Inc., and (v) Ranch Pipeline LLC ("RPL"), the owner of a 22.22% partnership interest in Frontier Pipeline Company ("Frontier") and successor to Ranch Pipeline, Inc. Anschutz made this conveyance in exchange for: (i) the continuation of its 2% General Partner interest in the Partnership; (ii) incentive distribution rights (as defined in the Partnership's partnership agreement); (iii) 1,865,000 common units; (iv) 10,465,000 subordinated units; and (v) $105.1 million from borrowings under PEG's term loan facility on closing of the initial public offering.
In the financial statement and notes included herein references to the "Company" refer to the consolidated entity, including the Partnership.
Description of Business and History
PEG was formed in August 2001, and at June 30, 2003 and December 31, 2002, owned 100% of PPS, PMT, RMP, AREPI and RPL.
PPS owns and operates two crude oil pipelines, Line 2000 and the Line 63 system. In January 1999, PPS completed construction of Line 2000, a 130-mile crude oil pipeline that extends from Kern County in the San Joaquin Valley of California to the Los Angeles Basin, where it has direct and indirect connections to various refineries and terminal facilities. Line 2000 has a permitted annual average throughput capacity of 130,000 barrels of crude oil per day. Shipments of crude oil on Line 2000 began on February 23, 1999.
Effective May 1, 1999, ARCO Midcon, formerly ARCO Pipe Line Company ("ARCO"), exchanged its Line 63 assets for a 26.5% ownership interest in PPS and a note of $63.6 million. On June 7, 2001, ARCO made a capital contribution of $63.6 million to PPS, and PPS Holding Company ("Holdings"), a
F-2
wholly owned subsidiary of Anschutz and the 100% owner of the General Partner, then purchased ARCO's ownership interest in PPS for $47.0 million in cash, and PPS repaid the $63.6 million note. This purchase of an additional ownership interest in PPS resulted in negative goodwill of $40.6 million, which was allocated proportionately to reduce property, plant and equipment of PPS.
The Line 63 system includes a 107-mile crude oil pipeline capable of shipping approximately 105,000 barrels of crude oil per day from the San Joaquin Valley to various refineries and delivery points in the Los Angeles Basin. The Line 63 system also includes storage assets, various gathering lines in the San Joaquin Valley, distribution lines in the San Joaquin Valley that service refineries in the Bakersfield area, crude oil distribution lines in the Los Angeles Basin and a delivery facility in the Los Angeles Basin.
PMT was formed in June 2001, in connection with the purchase of certain assets in the San Joaquin Valley for approximately $14.4 million. The assets acquired consist of 122 miles of intrastate crude oil gathering pipelines and six storage and blending facilities with approximately 254,000 barrels of storage capacity and blending capacity of up to 65,000 barrels per day as well as a base stock of crude oil. The purchase price was allocated among the fair values of the assets acquired and no goodwill resulted from this acquisition. The purchase price is subject to adjustment based on operating cash flows (as defined in the purchase agreement) during the 24 months following the acquisition. Depending on the amount of this cash flow, the purchase price could decrease by up to $1.5 million or increase by up to $7.5 million. In addition, the seller remains liable for various indemnity, product supply and construction obligations undertaken in connection with the sale. PMT and the seller are engaged in discussions relating to the settlement of all obligations undertaken by them in connection with PMT's purchase of these assets.
RMP was formed in December 2001 in connection with the acquisition on March 1, 2002 of certain pipeline and related assets located in the Rocky Mountain region from an affiliate of BP plc for approximately $107.0 million. The pipeline and related assets acquired by RMP consist of various ownership interests in 1,925 miles of intrastate and interstate crude oil transportation pipelines, 209 miles of gathering pipelines and 29 storage tanks with approximately 1.4 million barrels of storage capacity. The purchase price was allocated among the fair values of the assets acquired and no goodwill resulted from this acquisition.
AREPI, which was transferred to PEG on July 12, 2002 in preparation for the Partnership's initial public offering, owns and operates a 42-mile crude oil pipeline with a throughput capacity of 52,500 barrels per day. The AREPI pipeline originates 21 miles south of Evanston, Wyoming at Ranch Station, Utah where it connects with the Frontier pipeline (discussed below) and terminates at Kimball Junction, Utah, where it connects with a ChevronTexaco pipeline that serves the Salt Lake City refineries.
RPL, which was transferred to PEG on March 1, 2002 in preparation for the Partnership's initial public offering, owns a 22.22% partnership interest in Frontier, a Wyoming general partnership, which owns Frontier pipeline. RPL owned a 12.5% partnership interest in Frontier until December 2001, at which time it acquired an additional 9.72% partnership interest from an affiliate of BP plc for $8.6 million. Frontier pipeline is a 290-mile pipeline with a throughput capacity of 62,200 barrels per day that originates in Casper, Wyoming and delivers crude oil to the AREPI pipeline and the Salt Lake City Core system.
Pacific Energy GP, Inc., as general partner of the Partnership, manages the Partnership's operations and activities on the Partnership's behalf. The General Partner does not receive a management fee or other compensation for its management of the Partnership. However, the General Partner and its affiliates are reimbursed for all expenses incurred by them on the Partnership's behalf. These expenses include the costs of employee, officer and director compensation and benefits allocable to the General Partner and other expenses necessary or appropriate to the conduct of the business and
F-3
allocable to the General Partner. The General Partner may determine expenses allocable to the Partnership in any reasonable manner as determined by the General Partner in its sole discretion, pursuant to the terms of the Partnership's partnership agreement.
Management Estimates
Preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires that management make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the balance sheet date. The actual results could differ significantly from those estimates.
The Company's most significant estimates involve the valuation of individual assets acquired in purchase transactions, the useful lives of components of property and equipment, the expected costs of environmental remediation, and contingent liabilities.
Cash Equivalents
For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents.
Crude Oil Inventory
Pursuant to its tariff filings, the Company is entitled to a percentage (pipeline loss allowance) of the crude oil (in barrels) transported through the regulated pipelines. As these barrels are earned each month, the Company recognizes revenue and a corresponding increase in crude oil inventory based on average crude prices for that month. The crude oil inventory balance is subject to downward adjustment each quarter if crude prices decline below the carrying value of the inventory. The Company generally sells these barrels when it accumulates a salable quantity. As the sales occur, a gain or loss is recognized based on the difference between the sales price and the inventory carrying value, as adjusted, and is recorded to pipeline transportation revenue.
Spare Parts Inventory
Spare parts inventory is stated at cost using the first-in, first-out method.
Property and Equipment
The components of property and equipment are capitalized at cost and depreciated using the straight-line method over the estimated useful lives of the assets as follows:
| Pipelines | 40 years | |
| Buildings and oil tanks | 30 years | |
| Station and pumping equipment | 15 - 20 years | |
| Other | 3 - 10 years |
Environmental Remediation
The Company accrues environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable in the future and may be reasonably estimated. These accruals are undiscounted and are based on information currently available, existing technology, the estimated timing of remedial actions and related inflation assumptions and enacted laws and regulations.
F-4
Investments
The investment in Frontier is accounted for under the equity method of accounting. Under the equity method, the investment is initially recorded at cost and subsequently adjusted to recognize the investor's share of distributions and net income or losses of the investee as they occur. Recognition of any such losses is generally limited to the extent of the investor's investment in, advances to, commitments and guarantees for the investee.
Impairment of Long-Lived Assets
Long-lived assets are reviewed for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. This review consists of a comparison of the carrying value of the asset with the asset's expected future undiscounted cash flows without interest costs. Estimates of expected future cash flows are to represent management's best estimate based on reasonable and supportable assumptions and projections. If the expected future cash flows exceed the carrying value of the asset, no impairment is recognized. If the carrying value of the asset exceeds the expected future cash flows, an impairment exists and is measured by the excess of the carrying value over the estimated fair value of the asset. Any impairment provisions are permanent and may not be restored in the future. The Company adopted Statement of Financial Accounting Standards No. 144,"Accounting for the Impairment or Disposal of Long-Lived Assets," effective January 1, 2002, which did not have any impact on the Company's financial position or results from operations.
Trade Receivables
Crude oil sales receivables are recognized when the crude oil is delivered to customers.
Transportation accounts receivables are recognized upon delivery of the crude oil to the customer.
Derivative Instruments
The Company uses, on a limited basis, certain derivative instruments (principally futures and options) to hedge its minimal exposure to market price volatility related to its sales of crude oil. The Company does not engage in speculative derivative activities of any kind. Derivative instruments are included in other assets in the accompanying consolidated balance sheets. Changes in the fair value of the Company's derivatives related to crude oil sales are recognized in net income.
In August and September 2002, PEG entered into three interest rate swap agreements pursuant to which it executed five interest rate swap transactions that mature in 2009, totaling $140.0 million, and two interest rate swap transactions that mature in 2007, totaling $30.0 million. The Company designated these swaps as a hedge of its exposure to variability in future cash flows attributable to the LIBOR interest payments due on $170.0 million outstanding under the term loan facility. The average swap rate on this $170.0 million of debt is approximately 4.25%, resulting in an all-in interest rate on the $170.0 million of approximately 7.00% (including the current applicable margin of 2.75%).
As of December 31, 2002, interest rates, as measured by market quotations for the future periods covered by the interest rate swap agreements, had declined as compared to August and September 2002, when PEG entered into these interest rate swap agreements. This decline resulted in an unrealized loss of $7.4 million on the aggregate interest rate hedge, which is recorded as a liability at December 31, 2002. The $7.4 million liability is shown on the consolidated balance sheet in two components, a current liability of $4.8 million, and a long term liability of $2.6 million. The unrealized loss is shown in "other comprehensive income," a component of partners' capital, and not in the consolidated income statement. Should interest rates remain unchanged from the December 31, 2002 market quotations for these future periods, actual losses realized on the interest rate swap agreements in each of the future periods would be offset by the benefit of lower floating rates in those periods,
F-5
such that total net interest expense on the $170.0 million of hedged debt would be fixed at the all-in interest rate of 7.00%.
By using derivative financial instruments to hedge exposures related to changes in market prices, and interest rates, the Company exposes itself to market risk and credit risk. Market risk is the adverse effect on the value of a financial instrument that results from a change in interest rates, currency exchange rates or market prices. The market risk associated with price volatility is managed by established parameters that limit the types and degree of market risk that may be undertaken.
Credit risk is the failure of the counterparty to perform under the terms of the derivative agreement. When the fair value of a derivative agreement is positive, the counterparty owes the Company, which creates credit risk for the Company. When the fair value of a derivative agreement is negative, the Company owes the counterparty and, therefore, it does not pose credit risk. As of December 31, 2002, the counterparties to the interest rate swap agreements did not pose a credit risk to the Company as the fair value of each derivative agreement was negative.
Restricted Units and Unit Options
As permitted under Statement of Financial Accounting Standards No. 123 "Accounting for Stock-Based Compensation," the Company has elected to measure costs for restricted units and unit options using the intrinsic value method, as prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." Compensation expense related to the restricted units has been recognized by the Company. The compensation expense was recognized over the vesting periods of the units. No compensation expense related to the unit options has been recognized because the exercise price of the unit options equals the market price of the underlying units on the date of grant.
Income Taxes
No federal or state income taxes related to operations is included in the accompanying consolidated balance sheet. The Company is not a taxable entity as it is a Qualified Subchapter S Subsidiary (QSub) of Anschutz. Thus, federal and state income taxes related to the Company's operations are included in the consolidated financial statements of Anschutz.
Financial Instruments
The carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and other liabilities approximate their fair value. The carrying value of the Company's long-term debt together with the derivatives liability approximates the fair value of the debt as the interest rates reset periodically.
Recent Accounting Pronouncements
In May 2003, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 150 ("SFAS No. 150"), "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." This statement establishes standards for the measurement and classification of certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise effective beginning the first interim period beginning after June 15, 2003. The adoption of this standard did not have any impact on the Company's financial position or results of operations.
In April 2003, the FASB issued Statement of Financial Accounting Standards No. 149 ("SFAS No. 149"), "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This statement amends and clarifies financial accounting and reporting for derivative instruments, including
F-6
certain derivative instruments embedded in other contracts and for hedging activities under Statement of Financial Accounting Standards No. 133 ("SFAS No. 133"), "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003 and should be applied prospectively. However, provisions related to SFAS No. 133 Implementation Issues effective for fiscal quarters beginning prior to June 15, 2003 should continue to be applied in accordance with their respective dates. The adoption of this standard is not expected to have any impact on the Company's financial position or results of operations.
Effective January 1, 2003, the Company adopted SFAS No. 143, as required. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including future retirement costs, future inflation rates and the credit-adjusted risk-free interest rate. A substantial portion of our assets have obligations to perform removal and/or remediation activities when the asset is retired. However, the fair value of the asset retirement obligation cannot be reasonably estimated, as the retirement dates are indeterminate. The Company will record such asset retirement obligation in the period in which the retirement dates are determined. The cumulative effect of adopting this standard did not have a material impact on the Company's financial position.
In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation of Variable Interest Entities." This interpretation clarifies the application of Accounting Research Bulletin No. 51 ("ARB 51"), "Consolidated Financial Statements," and requires companies to evaluate variable interest entities for specific characteristics to determine whether additional consolidation and disclosure requirements apply. This interpretation is immediately applicable for variable interest entities created after January 31, 2003, and applies to fiscal periods beginning after June 15, 2003 for variable interest entities acquired prior to February 1, 2003. The adoption of this standard did not have any impact on the Company's financial position.
In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This interpretation clarifies the requirements of a guarantor in accounting for and disclosing certain guarantees issued and outstanding. This interpretation is effective for fiscal years ending after December 15, 2002. The adoption of this interpretation did not have any impact on the Company's financial position in 2002.
In July 2002, the FASB issued Statement of Financial Accounting Standards No. 146 ("SFAS No. 146"), "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." It requires that a liability be recognized for those costs only when the liability is incurred, that is, when it meets the definition of a liability in the FASB's conceptual framework. SFAS No. 146 also establishes fair value as the objective for initial measurement of liabilities related to exit or disposal activities. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002, with earlier adoption encouraged. The adoption of this standard did not have any impact on the Company's financial position.
In April 2002, the FASB issued Statement of Financial Accounting Standards No. 145 ("SFAS No. 145"), "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." The rescission of FASB Statement No. 4 ("Statement 4"), "Reporting Gains and Losses from Extinguishment of Debt," and FASB Statement No 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements," which amended Statement 4, will affect income statement classification of gains and losses from extinguishment of debt. Upon adoption, enterprises must reclassify prior period items that do not meet the extraordinary item classification criteria in Accounting Principles Bulletin No. 30, "Reporting the Results of Operations." The provisions of SFAS No. 145 related to the rescission of Statement 4 are applicable in fiscal years beginning after May 15,
F-7
2002. The provisions of SFAS No. 145 related to FASB Statement No. 13, "Accounting for Leases," are effective for transactions occurring after May 15, 2002. All other provisions of SFAS No. 145 are effective for financial statements issued on or after May 15, 2002. The adoption of this standard did not have any impact on the Company's financial position.
In August 2001, the FASB issued Statement of Financial Accounting Standards No. 143 ("SFAS No. 143"), "Accounting for Asset Retirement Obligations." This statement requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The standard is effective for fiscal years beginning after June 15, 2002.
Effective January 1, 2003, the Company adopted SFAS No. 143, as required. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including future retirement costs, future inflation rates and the credit-adjusted risk-free interest rate. A substantial portion of our assets have obligations to perform removal and/or remediation activities when the asset is retired. However, the fair value of the asset retirement obligation cannot be reasonably estimated, as the retirement dates are indeterminate. The Company will record such asset retirement obligation in the period in which the retirement dates are determined. The cumulative effect of adopting this standard did not have a material impact on the Company's financial position.
2. PENDING ACQUISITION
In February 2002, Holdings entered into an asset purchase agreement to acquire certain storage and pipeline assets of Edison Pipeline and Terminal Company ("EPTC"), a division of Southern California Edison Company (the "EPTC Assets") for approximately $158.2 million, plus post-closing adjustments of approximately $9 million related to the value of displacement oil, warehouse inventory, certain pre-closing capital expenditures and other costs. In addition, $3 million of transaction costs and assumed liabilities are also estimated. Holdings subsequently assigned the purchase agreement to Pacific Terminals LLC, a wholly-owned subsidiary. The acquisition was approved by the California Public Utilities Commission on July 10, 2003 and closed on July 31, 2003. Under an agreement with the Partnership, Holdings transferred all of its interest in Pacific Terminals LLC to the Partnership on July 30, 2003.
3. PROPERTY AND EQUIPMENT
Property and equipment consists of the following amounts at December 31, 2002:
| | 2002 | ||
|---|---|---|---|
| | (in thousands) | ||
| Pipeline | $ | 360,032 | |
| Station and pumping equipment | 50,691 | ||
| Buildings | 12,044 | ||
| Land and other | 33,349 | ||
| 456,116 | |||
| Less accumulated depreciation | 51,274 | ||
| $ | 404,842 | ||
The 2001 purchase of ARCO's ownership interest in PPS described in note 1 resulted in negative goodwill of $40.6 million, which was allocated proportionately to reduce pipeline assets of PPS.
F-8
4. INVESTMENT IN FRONTIER PIPELINE COMPANY
Prior to December 17, 2001, RPL owned a 12.5% partnership interest in Frontier. On December 17, 2001, RPL purchased an additional 9.72% interest in Frontier for $8.6 million, which increased its ownership in Frontier to 22.22%. RMP became the operator of Frontier concurrent with this acquisition. RPL's investment in Frontier exceeded its proportionate share of Frontier's partners' capital at December 31, 2001 by approximately $7.1 million. This excess was associated with the value of Frontier's pipeline assets and is being amortized over twenty years, the remaining estimated useful life of the pipeline.
The condensed balance sheet of Frontier at December 31, 2002 is presented below (unaudited):
Balance Sheet
| | December 31, 2002 | ||
|---|---|---|---|
| | (in thousands) | ||
| Current assets | $ | 4,481 | |
| Property and equipment, net | 9,252 | ||
| Other assets | 1 | ||
| $ | 13,734 | ||
Current liabilities | $ | 365 | |
| Other liabilities | 2,298 | ||
| Partners' capital | 11,071 | ||
| $ | 13,734 | ||
5. LEASES
The Company is obligated under several noncancelable operating leases, primarily for the rental of office space and trucks which expire through the year 2007. These leases require the Company to pay all operating costs such as maintenance and insurance. Future minimum rental payments under noncancelable operating leases at December 31, 2002 are as follows (in thousands):
| Year ending December 31, | ||||
| 2003 | $ | 841 | ||
| 2004 | 200 | |||
| 2005 | 191 | |||
| 2006 | 169 | |||
| 2007 | 3 | |||
| $ | 1,404 | |||
6. STOCKHOLDER'S EQUITY
On July 26, 2002, the Partnership completed its initial public offering of 8,600,000 common units representing limited partner interests, at a price of $19.50 per common unit. Total proceeds from the sale of the 8,600,000 units were $167.7 million, before offering costs and underwriting commissions. Concurrent with the closing of this offering, PEG entered into a $425.0 million credit agreement with a syndicate of financial institutions led by Fleet National Bank, that provides for a five-year $200.0 million senior secured revolving credit facility and a seven-year $225.0 million senior secured term loan facility. On July 26, 2002, PEG borrowed $225.0 million under the term loan facility. The
F-9
$200.0 million revolving credit facility is currently undrawn except for the letters of credit totaling $6.5 million at December 31, 2002. (See Note 7, Long-term Debt)
A summary of the proceeds received from these two transactions and the use of those proceeds is as follows (in thousands):
| Proceeds received: | |||||
| Sale of common units | $ | 167,700 | |||
| Borrowing under term loan facility | 225,000 | ||||
| Total proceeds received | $ | 392,700 | |||
Use of proceeds from sale of common units: | |||||
| Underwriting discount | $ | 11,500 | |||
| Professional fees and other offering costs(1) | 4,900 | ||||
| Repayment of debt(1) | 151,300 | ||||
| Total use of proceeds from the sale of common units | $ | 167,700 | |||
| Use of proceeds from term loan facility: | |||||
| Debt issuance costs and related expenses | $ | 5,300 | |||
| Repayment of debt | 114,600 | ||||
| Distribution to General Partner | 105,100 | ||||
| Total use of proceeds from term loan facility | $ | 225,000 | |||
| Total use of proceeds | $ | 392,700 | |||
7. LONG-TERM DEBT
The Company's long-term debt obligations at December 31, 2002 are shown below:
| | December 31, 2002 | |||
|---|---|---|---|---|
| | (in thousands) | |||
| Senior secured revolving credit facility | $ | — | ||
| Senior secured term loan facility | 225,000 | |||
| Less current portion of long-term debt | — | |||
| Total | $ | 225,000 | ||
F-10
Payments due on the senior secured term loan facility during each of the five years subsequent to December 31, 2002 are as follows: (in thousands):
| Year ending December 31, | ||||
| 2003 | $ | — | ||
| 2004 | — | |||
| 2005 | 1,125 | |||
| 2006 | 2,250 | |||
| 2007 | 2,250 | |||
| Thereafter | 219,375 | |||
| Total | $ | 225,000 | ||
A $200.0 million revolving credit facility is available to the Partnership for general purposes, including working capital, letters of credit and distributions to unitholders and to finance future acquisitions, including the acquisition of the EPTC Assets. The revolving credit facility has a borrowing sublimit of $45.0 million for working capital, letters of credit and partnership distributions to unitholders.
The revolving credit facility matures on July 26, 2007, at which time all outstanding amounts will be due and payable. The Partnership will be required to amortize amounts outstanding under the term loan facility on a quarterly basis at 1% per annum, with the first quarterly payment due September 2005. A 97% balloon payment will be due at maturity in July 2009.
PEG is the borrower under both the revolving credit facility and the term loan facility, which are guaranteed by the Partnership and certain of PEG's operating subsidiaries. The revolving credit facility and the term loan facility are both fully recourse to PEG and the guarantors, but non-recourse to the General Partner. Obligations under the revolving credit facility and the term loan facility are secured by pledges of membership interests in and the assets of certain of PEG's operating subsidiaries.
Indebtedness under the revolving credit facility and the term loan facility bear interest at the Partnership's option, at either (i) the base rate, which is equal to the higher of the prime rate as announced by Fleet National Bank or the Federal Funds rate plus 0.50% (each plus an applicable margin ranging from 0% to 0.50% for the revolving credit facility and ranging from 0.50% to 0.75% for the term loan facility) or (ii) LIBOR plus an applicable margin ranging from 1.25% to 2.50% for the revolving credit facility and ranging from 2.50% to 2.75% for the term loan facility. The applicable margins are subject to change based on the credit rating of the facilities or, if they are not rated, the credit rating of PEG. After the purchase of the EPTC Assets, the applicable margin will increase by a margin which ranges from 0.375% to 0.625% and will remain at that level for 270 days after the purchase or until we successfully conclude an equity offering, that reduces certain ratios to specified levels, whichever is earlier. PEG incurs a commitment fee which ranges from 0.25% to 0.50% per annum on the unused portion of the revolving credit facility. Under the credit agreement, PEG is prohibited from declaring dividends or distributions if any event of default, as defined in the credit agreement, occurs or would result from such declaration. In addition, the credit agreement contains certain financial covenants and covenants limiting the ability of PEG and certain of its subsidiaries to, among other things, incur or guarantee indebtedness, change ownership or structure, including consolidations, liquidations and dissolutions and enter into a new line of business. At December 31, 2002, PEG and its subsidiaries were in compliance with all such covenants.
At December 31, 2002, the Partnership had letters of credit outstanding totaling $6.5 million, for PMT activities, which were supported by the Partnership's $200.0 million revolving credit facility.
F-11
8. RELATED PARTY TRANSACTIONS
A subsidiary of Anschutz is a shipper on Line 2000 and is charged published tariff rates. This subsidiary entered into agreements with a third party to purchase crude oil, ship it on Line 2000, and sell it in the Los Angeles Basin. The amounts associated with these shipments included in accounts receivable were $0.4 million at December 31, 2002. As an original sponsor of the Line 2000 project, Anschutz and its subsidiaries qualify for participating shipper tariff rates on the Line 2000 pipeline. Anschutz has designated its rights for participating shipper rates to the Company and other affiliates.
RMP serves as the contract operator for Anschutz Wahsatch Gathering System, Inc. ("AWGS"), a wholly owned subsidiary of Anschutz that owns a natural gas gathering system in Wyoming and Utah. AWGS reimburses RMP for the direct costs of operating the AWGS assets, such as the salary and benefit costs incurred by the direct assigned field operating and maintenance personnel related to AWGS operations. In addition, AWGS pays an annual management fee of $0.3 million to reimburse RMP for the portion of time spent by management and for other overhead services related to AWGS activities. As of December 31, 2002, $0.1 million was included in the accounts receivable of RMP on account of these services.
In 2002, Anschutz paid certain expenses on behalf of RMP. Amounts charged in 2002 for reimbursement were $0.3 million, which is included in "due to related parties" of RMP at December 31, 2002. In 2002, Anschutz paid certain expenses on behalf of RPL. Amounts charged in 2002 for reimbursement were $0.4 million, which is included in "due to related parties" of RPL at December 31, 2002.
The Partnership and its subsidiaries do not have any employees. The General Partner employs approximately 215 individuals on behalf of the Partnership who directly support the operations of the Partnership. All expenses incurred by the General Partner are charged to the Partnership and its subsidiaries through the "due from related parties" account. At December 31, 2002, amounts due to the General Partner for reimbursement of payroll and related costs amounted to $0.3 million. In addition, the General Partner performs payroll and payroll related functions for Anschutz Wahsatch Gathering System ("AWGS"), a subsidiary of Anschutz. At December 31, 2002, the amount due from AWGS was $0.1 million, which was included in "due from related parties".
In 2002, the Company began utilizing the financial accounting system owned and provided by Anschutz under a shared services arrangement. In addition, the Company utilizes the services of Anschutz's risk management personnel for acquiring the Company's insurance, and the Company's surety bonds are issued under Anschutz's bonding line. Out of pocket costs incurred by Anschutz for the benefit of the Company for computer consultants, insurance premiums and surety bond costs were reimbursed by the Company. Beginning January 2003, the Company will pay Anschutz a fee of $0.1 million per year for these services and continue to reimburse Anschutz for any out of pocket costs it incurs. The fixed annual fee includes all license, maintenance and employee costs associated with the Company's use of the financial accounting system.
Beginning January 2003, the Company leased approximately 4,700 square feet of office space from an affiliate of Anschutz, for a term of five years at an initial annual cost of $0.1 million, the prevailing market rate for comparable space. Also beginning in 2003, the Company's trucking operation began hauling water for an Anschutz oil and gas subsidiary at rates equivalent to those charged to third parties.
9. RIGHT-OF-WAY OBLIGATIONS
The Company has secured various rights-of-way for its pipeline systems under right-of-way agreements that provide for annual payments to third parties.
F-12
Pursuant to an easement agreement between PPS and Union Pacific Corporation ("UPC"), UPC provides the Company with access to its right-of-way for a portion of Line 2000 in return for an annual rental. Under the agreement the annual rental is to be adjusted every five years, in accordance with prescribed procedures, to reflect fair rental value. The first revision was to have been made effective as of April 1, 2002, but as of January 28, 2003, the parties have not completed the revision process. Accordingly, the rental that was paid for 2002 was an estimate, and is subject to subsequent adjustment. Phillip F. Anschutz, a director of the General Partner and sole stockholder of Anschutz Company, the indirect parent of the General Partner, is a director and the Non-Executive Vice Chairman of UPC.
The Company operates under various right-of-way and franchise agreements, certain of which expire at various times through at least 2035. Due to the nature of the Company's operations, the Company expects to continue making payments and renewing the right-of-way agreements. The future minimum payments, as of December 31, 2002, under the Company's right-of-way agreements are presented below (in thousands) and reflect the Company's commitment for the next 15 years assuming the current right-of-way agreements will be renewed during the period. The annual amounts payable under right-of-way agreements subsequent to 2006 are subject to adjustments as described above as well as for the effects of inflation.
| Years ending December 31: | ||||
| 2003 | $ | 2,864 | ||
| 2004 | 2,864 | |||
| 2005 | 2,861 | |||
| 2006 | 2,861 | |||
| 2007 | 2,861 | |||
| Thereafter | 12,914 | |||
| Total | $ | 27,225 | ||
The Company has accrued an estimated liability of $0.4 million at December 31, 2002 related to costs it expects to incur related to title and easement work on the Line 63 system associated with the transfer of easements from ARCO to PPS.
10. LONG-TERM INCENTIVE PLAN
In July 2002, the General Partner adopted the Long-Term Incentive Plan (the "Plan") for employees and affiliates who perform services for the Partnership. The Plan consists of two components, a restricted unit plan and a unit option plan. The Plan currently permits the granting of an aggregate of 1,750,000 restricted units and unit options and is administered by the Compensation Committee of the General Partner, subject to approval by the Board of Directors. The General Partner's Board of Directors in its discretion may terminate the Plan at any time with respect to any restricted units for which a grant has not yet been made. The General Partner's Board of Directors also reserve the right to alter or amend the Plan from time to time, including increasing the number of common units with respect to which awards may be granted; provided, however, that no change in any outstanding grant may be made which would materially impair the rights of the participant without the consent of such participant. As the restricted units vest, the Company has the option to either issue common units or pay the holder of the restricted units cash equal to the fair market value on the vesting date. The Company intends to issue common units rather than pay cash as the restricted units vest, and as such, accounts for the restricted unit plan as a fixed plan.
In December 2002, the General Partner granted 381,250 restricted units to certain key employees which vest over approximately two to five years from the date of grant. These units are subject to forfeiture if employment is terminated prior to vesting. The fair market value of the restricted units associated with these grants was $7.5 million on the grant date.
F-13
In December 2002, the General Partner granted 50,000 unit options. The unit options were granted with an exercise price equal to the fair market value at the date of grant. The outstanding unit options have 10 year terms and vest approximately two years from the date of grant. At December 31, 2002, there were 50,000 unit options outstanding at a weighted average exercise price of $19.50 per unit option and weighted-average remaining contractual life of 9.7 years.
11. EMPLOYEE BENEFIT PLAN
PPS sponsors a defined contribution 401(k) plan whereby eligible employees may contribute up to 18% of their annual compensation to the plan, subject to certain defined limits. PPS matches employee contributions up to 6% of the employee's annual compensation. Total employer contributions to the plan for 2002 were $0.8 million.
12. DISTRIBUTIONS
On January 20, 2003, the Partnership declared a cash distribution of $0.4625 per limited partner unit, which was paid on February 14, 2003 to unitholders of record as of January 31, 2003.
On April 21, 2003, the Partnership declared a cash distribution of $0.4625 per limited partner unit, which was paid on May 15, 2003 to unitholders of record as of April 30, 2003.
On July 18, 2003, the Partnership declared a cash distribution of $0.4625 per limited partner unit, payable on August 14, 2003 to unitholders of record as of July 31, 2003
13. COMMITMENTS AND CONTINGENCIES
On March 15, 2002, Sinclair Oil Corporation ("Sinclair") filed a complaint with the Wyoming Public Service Commission ("WPSC") alleging that RMP's common stream rules and specifications and RMP's refusal to prohibit certain types of crude oil diluents from the common stream, all in respect of the Big Horn segment of the Western Corridor system, are adverse to Sinclair and the public interest. On April 21, 2003, the WPSC deliberated Sinclair's complaint and verbally announced that RMP will be required to adopt tariff language that prohibits certain types of crude oil diluents from the common stream or, in the alternative, that shippers who receive crude oil from the common stream that includes diluents be compensated for any disadvantage they suffer from the effects of the diluents. Until a written order is issued by the WPSC, which is expected in August 2003, the Company cannot predict with any degree of certainty the effect of the WPSC's April 21, 2003 decision on the Company's operations. However, this ruling is not expected to have a material adverse effect on the Company's financial position, results of operations or liquidity.
On April 15, 2002, Sinclair filed a complaint with the FERC challenging RMP's $1.32 per barrel rate for shipments from the Canadian border to Casper, Wyoming. RMP answered the complaint with a general denial of Sinclair's allegations. In June 2003 the dispute with Sinclair was fully settled by the execution of an agreement between Sinclair and RMP pursuant to which RMP has adopted a new Canadian border to Casper tariff that provides a range of volume incentive rates that decrease as pipeline volumes increase, with the highest rate in the range remaining at the previous rate of $1.32 per barrel, and the lowest rate being $1.10 per barrel. RMP expects the new incentive rate structure, which was implemented effective July 1, 2003, to result in increased volume and revenue, thereby benefiting the Company.
On July 22, 2002, RMP filed an application with the FERC seeking authority to charge market-based rates on its portion of the Western Corridor system. Protests to the application for market-based rates were filed by Sinclair, Tesoro Refining and Marketing Company, ConocoPhillips and Chevron Products Company. As part of the settlement with Sinclair described in the previous paragraph, RMP agreed to withdraw its market-based rate application and not re-file it for a period of two years, subject
F-14
to certain exceptions. While being granted the right to set tariff rates on the basis of market considerations, rather than cost of service, would give RMP greater convenience and a desirable degree of pricing flexibility and responsiveness, RMP's withdrawal of its application for such authority, and its inability to re-file a similar application for two years, are not expected to have a material adverse effect on the Company's financial position.
The Company is subject to numerous federal, state and local laws which regulate the discharge of materials into the environment or that otherwise relate to the protection of the environment. The Company currently has an environmental remediation liability resulting from the acquisition of ARCO's interest in PPS in 2001. The accrued liability was $2.6 million at December 31, 2002 and was classified in consolidated balance sheet within "other liabilities." The actual future costs for environmental remediation activities will depend on, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the technology available and required to meet the various existing legal requirements, the nature and extent of future environmental laws, inflation rates and the determination of the Company's liability at multi-party sites, if any, in light of uncertainties with respect to joint and several liability, and the number, participation levels and financial viability of other parties.
The Company is involved in various other litigation and claims arising out of operations in the normal course of business; however, the Company is not currently a party to any legal or regulatory proceedings the resolution of which the Company expects to have a material adverse effect on its business, financial position, results of operations or liquidity.
F-15
