Back to GetFilings.com



 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 


 

FORM 10-Q

 

ý

Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

For the quarterly period ended March 31, 2005

OR

 

o

Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

For the transition period from              to              

 

Commission File Number 1-313345

 


 

PACIFIC ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

 

DELAWARE

 

68-0490580

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer Identification No.)

 

5900 Cherry Avenue

Long Beach, CA 90805-4408

(Address of principal executive offices)

 

(562) 728-2800

(Registrant’s telephone number, including area code)

 


 

                Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes ý  No o

 

                Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes ý  No o

 

                There were 19,258,330 of the registrant’s Common Units and 10,465,000 of the registrant’s Subordinated Units outstanding at March 31, 2005.

 



 

PACIFIC ENERGY PARTNERS, L.P.

 

FORM 10-Q

 

TABLE OF CONTENTS

 

 

 

 

PART I. FINANCIAL INFORMATION

 

Item 1.

Financial Statements

 

 

Condensed Consolidated Balance Sheets (Unaudited)—As of March 31, 2005 and December 31, 2004

 

 

Condensed Consolidated Statements of Income (Unaudited)—For the Three Months Ended March 31, 2005 and 2004

 

 

Condensed Consolidated Statement of Partners’ Capital (Unaudited)—For the Three Months Ended March 31, 2005

 

 

Condensed Consolidated Statements of Comprehensive Income (Unaudited)—For the Three Months Ended March 31, 2005 and 2004

 

 

Condensed Consolidated Statements of Cash Flows (Unaudited)—For the Three Months Ended March 31, 2005 and 2004

 

 

Notes to Condensed Consolidated Financial Statements (Unaudited)

 

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

 

Item 4.

Controls and Procedures

 

PART II. OTHER INFORMATION

 

Item 1.

Legal Proceedings

 

Item 6.

Exhibits

 

 



 

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

PACIFIC ENERGY PARTNERS, L.P. (Note 1)

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

 

 

March 31,

 

December 31,

 

 

 

2005

 

2004

 

 

 

(in thousands)

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

22,097

 

$

23,383

 

Crude oil sales receivable

 

51,999

 

28,609

 

Transportation and storage accounts receivable

 

21,997

 

20,137

 

Canadian goods and services tax receivable

 

7,595

 

7,632

 

Insurance proceeds receivable (note 2)

 

11,495

 

 

Due from related parties (note 3)

 

128

 

 

Crude oil inventory

 

26,449

 

9,174

 

Prepaid expenses

 

4,928

 

4,159

 

Other

 

3,654

 

2,451

 

Total current assets

 

150,342

 

95,545

 

Property and equipment, net

 

715,580

 

718,624

 

Investment in Frontier

 

8,200

 

7,886

 

Other assets, net

 

45,968

 

47,850

 

 

 

$

920,090

 

$

869,905

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

17,273

 

$

15,127

 

Accrued crude oil purchases

 

65,493

 

27,231

 

Line 63 oil release reserve (note 2)

 

13,496

 

 

Accrued interest

 

5,538

 

1,124

 

Due to related parties (note 3)

 

 

533

 

Derivatives liability—current portion

 

1,410

 

400

 

Other

 

5,930

 

3,630

 

Total current liabilities

 

109,140

 

48,045

 

Senior notes and credit facilities, net (note 4)

 

356,369

 

357,163

 

Deferred income taxes

 

34,248

 

34,556

 

Environmental liabilities

 

7,022

 

7,269

 

Other liabilities

 

340

 

406

 

Total liabilities

 

507,119

 

447,439

 

Commitments and contingencies (notes 2 and 8)

 

 

 

 

 

Partners’ capital:

 

 

 

 

 

Common unitholders (19,258,330 and 19,158,747 units outstanding at March 31, 2005 and December 31, 2004, respectively)

 

356,708

 

361,427

 

Subordinated unitholders (10,465,000 units outstanding at March 31, 2005 and December 31, 2004)

 

38,096

 

41,521

 

General Partner interest

 

6,714

 

6,280

 

Undistributed employee long-term incentive compensation (note 5)

 

 

116

 

Accumulated other comprehensive income

 

11,453

 

13,122

 

Net partners’ capital

 

412,971

 

422,466

 

 

 

$

920,090

 

$

869,905

 

 

 

 

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

1



 

PACIFIC ENERGY PARTNERS, L.P. (Note 1)

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

 

 

 

Three Months Ended March 31,

 

 

 

2005

 

2004

 

 

 

(in thousands, except per unit amounts)

 

Pipeline transportation revenue

 

$

28,037

 

$

24,727

 

Storage and terminaling revenue

 

10,322

 

10,123

 

Pipeline buy/sell transportation revenue

 

9,106

 

 

Crude oil sales, net of purchases of $114,391 and $81,115 for the three months ended March 31, 2005 and 2004

 

1,782

 

4,812

 

Net revenue

 

49,247

 

39,662

 

Expenses:

 

 

 

 

 

Operating

 

21,754

 

18,917

 

Line 63 oil release costs (note 2)

 

2,000

 

 

General and administrative

 

5,172

 

3,854

 

Accelerated long-term incentive plan compensation expense (note 5)

 

3,115

 

 

Transaction costs (notes 3 and 6)

 

1,807

 

 

Depreciation and amortization

 

6,529

 

5,242

 

 

 

40,377

 

28,013

 

Share of net income of Frontier

 

357

 

393

 

Operating income

 

9,227

 

12,042

 

Interest expense

 

(5,598

)

(4,126

)

Other income

 

353

 

161

 

Income before income taxes

 

3,982

 

8,077

 

Income tax (expense) recovery:

 

 

 

 

 

Current

 

(732

)

 

Deferred

 

171

 

 

 

 

(561

)

 

Net income

 

$

3,421

 

$

8,077

 

Net income (loss) for the general partner interest (note 6)

 

$

(1,702

)

$

162

 

Net income for the limited partner interests

 

$

5,123

 

$

7,915

 

 

 

 

 

 

 

Basic net income per limited partner unit

 

$

0.17

 

$

0.32

 

Diluted net income per limited partner unit

 

$

0.17

 

$

0.31

 

 

 

 

 

 

 

Weighted average limited partner units outstanding:

 

 

 

 

 

Basic

 

29,655

 

24,999

 

Diluted

 

29,673

 

25,149

 

 

See accompanying notes to condensed consolidated financial statements.

 

2



 

PACIFIC ENERGY PARTNERS, L.P. (Note 1)

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(Unaudited)

 

 

 

 

 

 

 

 

 

Undistributed

 

 

 

 

 

 

 

 

 

 

 

 

 

Employee

 

Accumulated

 

 

 

 

 

 

 

 

 

General

 

 Long-Term

 

Other

 

 

 

 

 

Limited Partner Units

 

Limited Partner Amounts

 

Partner

 

Incentive

 

Comprehensive

 

 

 

 

 

Common

 

Subordinated

 

Common

 

Subordinated

 

Interest

 

Compensation

 

Income

 

Total

 

 

 

(in thousands)

 

Balance, December 31, 2004

 

19,159

 

10,465

 

$

361,427

 

$

41,521

 

$

6,280

 

$

116

 

$

13,122

 

$

422,466

 

Net income (note 6)

 

 

 

3,315

 

1,808

 

(1,702

)

 

 

3,421

 

Distribution to partners

 

 

 

(9,579

)

(5,233

)

(302

)

 

 

(15,114

)

General partner contribution (note 6)

 

 

 

 

 

2,407

 

 

 

2,407

 

Employee compensation under long-term incentive plan

 

 

 

 

 

 

2,886

 

 

2,886

 

Issuance of common units pursuant to long-term incentive plan (note 5)

 

99

 

 

1,545

 

 

31

 

(3,002

)

 

(1,426

)

Foreign currency translation adjustment

 

 

 

 

 

 

 

(537

)

(537

)

Change in fair value of hedging derivatives

 

 

 

 

 

 

 

(1,132

)

(1,132

)

Balance, March 31, 2005

 

19,258

 

10,465

 

$

356,708

 

$

38,096

 

$

6,714

 

$

 

$

11,453

 

$

412,971

 

 

See accompanying notes to condensed consolidated financial statements.

 

3



 

PACIFIC ENERGY PARTNERS, L.P. (Note 1)

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

 

 

 

Three Months Ended March 31,

 

 

 

2005

 

2004

 

 

 

(in thousands)

 

 

 

 

 

 

 

Net income

 

$

3,421

 

$

8,077

 

Change in fair value of hedging derivatives

 

(1,132

)

(4,236

)

Change in foreign currency translation adjustment

 

(537

)

 

Comprehensive income

 

$

1,752

 

$

3,841

 

 

See accompanying notes to condensed consolidated financial statements.

 

4



 

PACIFIC ENERGY PARTNERS, L.P. (Note 1)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

 

Three Months Ended March 31,

 

 

 

2005

 

2004

 

 

 

(in thousands)

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

Net income

 

$

3,421

 

$

8,077

 

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

Depreciation and amortization

 

6,529

 

5,242

 

Amortization of debt issue costs

 

459

 

311

 

Non-cash portion of employee compensation under long-term incentive plan

 

1,545

 

659

 

Deferred tax benefit

 

(171

)

 

Share of net income of Frontier

 

(357

)

(393

)

Distributions from Frontier, net

 

 

289

 

 

 

11,426

 

14,185

 

Net changes in operating assets and liabilities:

 

 

 

 

 

Crude oil sales receivable

 

(23,327

)

5,556

 

Transportation and storage accounts receivable

 

(1,832

)

676

 

Insurance proceeds receivable

 

(11,495

)

 

Crude oil inventory

 

(17,246

)

(2,995

)

Other current assets and liabilities

 

(1,681

)

422

 

Accounts payable and other accrued liabilities

 

8,716

 

1,319

 

Accrued crude oil purchases

 

38,176

 

(5,981

)

Line 63 oil release reserve

 

13,496

 

 

Other non-current assets and liabilities

 

(301

)

 

 

 

4,506

 

(1,003

)

NET CASH PROVIDED BY OPERATING ACTIVITIES

 

15,932

 

13,182

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

Additions to property and equipment

 

(4,389

)

(2,413

)

Acquisition deposit

 

 

(9,920

)

Other

 

129

 

 

NET CASH USED IN INVESTING ACTIVITIES

 

(4,260

)

(12,333

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

Issuance of common units, net of fees and offering expenses

 

 

114,250

 

Capital contributions from the general partner

 

2,438

 

2,443

 

Proceeds from note payable to bank

 

26,833

 

16,500

 

Repayment of long-term debt

 

(25,854

)

(89,500

)

Deferred financing costs

 

(600

)

(175

)

Distributions to partners

 

(15,114

)

(12,390

)

Related parties

 

(661

)

156

 

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES

 

(12,958

)

31,284

 

 

 

 

 

 

 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

 

(1,286

)

32,133

 

CASH AND CASH EQUIVALENTS, beginning of reporting period

 

23,383

 

9,699

 

CASH AND CASH EQUIVALENTS, end of reporting period

 

$

22,097

 

$

41,832

 

 

See accompanying notes to condensed consolidated financial statements.

 

5



 

PACIFIC ENERGY PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2005

(Unaudited)

 

1.             SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

                Basis of Presentation

 

                Pacific Energy Partners, L.P. and its subsidiaries (the “Partnership”) are engaged principally in the business of gathering, transporting, storing and distributing crude oil and related products in California and the Rocky Mountain region of the U.S. and Canada. The Partnership generates revenue primarily by transporting crude oil on its pipelines and by leasing storage capacity. The Partnership also buys, blends and sells crude oil, activities that are complementary to the Partnership’s pipeline transportation business. The Partnership operates primarily in California, Colorado, Montana, Wyoming and Utah in the United States, and in Alberta, Canada and conducts its business through two regional business segments: the West Coast Business Unit and the Rocky Mountain Business Unit.

 

                We are managed by our general partner, Pacific Energy GP, LP, a Delaware limited partnership, which, prior to its conversion to a limited partnership on March 3, 2005, was Pacific Energy GP, Inc., a corporation owned 100% by a subsidiary of The Anschutz Corporation (“TAC”).  On March 3, 2005, TAC sold all of its interest in Pacific Energy GP, Inc. to LB Pacific, LP (“LBP”), which was formed by the Lehman Brothers Merchant Banking Group (“LBMB”) in connection with the purchase (see “Note 3 — Related Party Transactions”).  Pacific Energy GP, LP is managed by its general partner, Pacific Energy Management LLC, a Delaware limited liability company.

 

                The unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial reporting and with Securities and Exchange Commission (“SEC”) regulations. Accordingly, these statements have been condensed and do not include all of the information and footnotes required for complete financial statements. These statements involve the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals considered necessary for a fair presentation, have been included. The results of operations for the three months ended March 31, 2005 are not necessarily indicative of the results of operations for the full year. All significant intercompany balances and transactions have been eliminated during the consolidation process.

 

The condensed consolidated financial statements include the ownership and results of operations of the Rangeland system, including the Mid-Alberta Pipeline (“MAPL”), since the acquisition of those assets on May 11, 2004 and June 30, 2004, respectively.

 

                These financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements and notes thereto included in the Partnership’s annual report on Form 10-K for the year ended December 31, 2004. Certain prior year balances in the accompanying condensed consolidated financial statements have been reclassified to conform to the current year presentation.

 

                Income Taxes

 

                The Partnership and its U.S. and Canadian subsidiaries are not taxable entities in the U.S. and are not subject to U.S. federal or state income taxes, as the tax effect of operations is passed through to its unitholders. The Partnership’s Canadian subsidiaries are taxable entities in Canada and are subject to Canadian federal and provincial income taxes and other Canadian income taxes. In addition, monies repatriated from Canada into the U.S. may be subject to withholding taxes.

 

                Income taxes are accounted for under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in operations in the period that includes the enactment date.  The Partnership intends to repatriate its Canadian subsidiaries’ earnings in the future.  As such, the Partnership records a provision for Canadian withholding taxes on any repatriable earnings of its Canadian subsidiaries.

 

                Net Income per Unit

 

                Basic net income per limited partner unit is determined by dividing net income after deducting the amount allocated to the general partner interest, by the weighted average number of outstanding limited partner units.

 

                Diluted net income per limited partner unit is calculated in the same manner as basic net income per limited partner unit above,

 

6



 

except that the weighted average number of outstanding limited partner units is increased to include the dilutive effect of outstanding options and restricted units by application of the treasury stock method. Following is a reconciliation of the basic weighted average outstanding limited partner units to diluted weighted average limited partner units.

 

 

 

Three Months Ended March 31,

 

 

 

2005

 

2004

 

 

 

(in thousands)

 

 

 

 

 

 

 

Basic weighted average limited partner units

 

29,655

 

24,999

 

Effect of restricted units

 

 

134

 

Effect of options

 

18

 

16

 

Diluted weighted average limited partner units

 

29,673

 

25,149

 

 

                Allocation of Net Income

 

                Net income is allocated to the Partnership’s general partner and limited partners based on their respective interest in the Partnership.  The Partnership’s general partner is also directly charged with specific costs that it has individually assumed and for which the limited partners are not responsible (see “Note 6—Allocation of Net Income”).

 

                New Accounting Pronouncements

 

                In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 123 (revised December 2004), Share-Based Payment (SFAS 123R).  This Statement is a revision of SFAS No. 123.  SFAS 123R establishes standards for the accounting of transactions in which an entity exchanges its equity instruments for goods or services.  SFAS 123R is effective for the Partnership as of the beginning of the first annual reporting period that begins after June 15, 2005.  The Partnership has not yet determined the impact of the adoption of SFAS 123R on the Partnership’s consolidated financial statements.

 

                On March 30, 2005 the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), to clarify the term conditional asset retirement obligation as that term is used in FASB Statement No. 143, Accounting for Asset Retirement Obligations. The Interpretation also clarifies when an entity has sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for the Partnership no later than the end of fiscal years ending after December 15, 2005.  The Partnership is in the process of determining the impact of FIN 47 on its financial statements.

 

2.             LINE 63 OIL RELEASE RESERVE

 

                On March 23, 2005, a release of approximately 3,400 barrels of crude oil occurred on Line 63 when it was severed as a result of a landslide induced by heavy rainfall in the Pyramid Lake area of Los Angeles County.  Over the period March 2005 through March 2006, the Partnership expects to incur an estimated $13.5 million for oil containment and clean-up of the impacted areas, future monitoring costs, potential third-party claims and penalties, and other costs.  As of March 31, 2005, the Partnership had incurred approximately $3.3 million of the total expected costs related to the oil release for work performed through that date.  Additionally, the Partnership expects to incur approximately $1.0 million to repair the pipeline, which will be expensed as incurred.

 

                The Partnership has a pollution liability insurance policy with a $2.0 million deductible that covers containment and clean-up costs, third-party claims and penalties.  The insurance carrier has, subject to a reservation of certain rights, acknowledged coverage of the incident under the policy and has begun processing and paying invoices related to the clean-up.  The Partnership believes that, subject to the $2.0 million deductible, it will be entitled to recover substantially all of its clean-up costs and any third party claims associated with the release.  The Partnership’s insurance coverage will not cover the cost to repair the pipeline.  For the three months ended March 31, 2005, the Partnership accrued a receivable of $11.5 million for insurance receipts it deems probable.

 

                Accrued costs relating to the release of $13.5 million net of accrued insurance receipt of $11.5 million, or $2.0 million, are recorded in “Line 63 oil release costs” in the accompanying condensed consolidated statements of income for the three months ended March 31, 2005.

 

                The foregoing estimates are based on facts known at the time of estimation and the Partnership’s assessment of the ultimate outcome. Among the many uncertainties that impact the estimates are the necessary regulatory approvals for, and potential modification of, remediation and repair plans, the limited amount of data available at the time of the assessment of the impact of soil and water contamination, the current uncertainty of the geological conditions that will be encountered during the repairs of the damaged pipeline, changes in costs associated with environmental remediation services and equipment and the possibility of third-

 

7



 

party legal claims giving rise to additional expenses. Therefore, no assurance can be made that costs incurred in excess of this provision, if any, would not have a material adverse effect on the Partnership’s financial condition, results of operations, or cash flows, though the Partnership believes it is likely that most, if not all, of any such excess cost, to the extent attributable to clean-up and third-party claims, would be recoverable through insurance. As new information becomes available in future periods, the Partnership may change its provision and recovery estimates.

 

3.             RELATED PARTY TRANSACTIONS

 

                Sale of The Anschutz Corporation’s Interest in the Partnership

 

                On March 3, 2005, TAC sold all of its interest in Pacific Energy GP, Inc. to LBP, which was formed by LBMB in connection with the purchase.  The acquisition by LBP (the “LB Acquisition”) included the 100% ownership interest in Pacific Energy GP, Inc., which owned (i) the 2% general partner interest in the Partnership and the incentive distribution rights, and (ii) 10,465,000 subordinated units of the Partnership representing a 34.6% limited partner interest in the Partnership.  Immediately prior to the closing of the LB Acquisition, Pacific Energy GP, Inc. was converted to Pacific Energy GP, LLC, a Delaware limited liability company; and immediately after the closing of the LB Acquisition, Pacific Energy GP, LLC was converted to Pacific Energy GP, LP (the “General Partner”). Immediately following the consummation of the LB Acquisition, the General Partner distributed the 10,465,000 subordinated units of the Partnership to LBP.

 

                In connection with the conversion of the Partnership’s General Partner to a limited partnership, the General Partner ceased to have a board of directors, and is now managed by its general partner, Pacific Energy Management LLC, a Delaware limited liability company (“PEM” or the “Managing General Partner”), which is 100% owned by LBP.  PEM has a board of directors (the “Board of Directors” or “Board”) that manages the business and affairs of PEM and, thus, indirectly manages the business and affairs of the General Partner and the Partnership.  All of the officers and employees of Pacific Energy GP, Inc. were transferred to fill the same positions with PEM, and the PEM Board established the same committees as had been maintained by Pacific Energy GP, Inc. prior to the LB Acquisition. PEM also adopted Pacific Energy GP, Inc.’s governance guidelines and its compensation structure and employee benefits plans and policies.

 

                Additionally, on March 21, 2005, an affiliate of First Reserve Corporation (“First Reserve”) acquired from LBMB a 30% partnership interest in LBP. LBMB and its affiliates continue to own a 70% partnership interest in LBP.  As a result of its ownership interest, First Reserve is entitled to and has nominated one director to the Board of Directors of PEM.  The director nominated by First Reserve was appointed by LBP to the Board on April 6, 2005.

 

                The Board of Directors of PEM is now comprised of six of the directors who served on the board of directors of Pacific Energy GP, Inc. prior to the LB Acquisition, together with five new directors appointed by LBP.

 

                Cost Reimbursements

 

                Managing General Partner: The Partnership’s Managing General Partner employs all U.S.-based employees. All employee expenses incurred by the Managing General Partner on behalf of the Partnership are charged back to the Partnership.

 

                Special Agreement: On March 3, 2005, Douglas L. Polson, previously the Chairman of the Board of Directors of Pacific Energy GP, Inc., entered into a Special Agreement and a Consulting Agreement with PEM.  In accordance with the Special Agreement, Mr. Polson resigned as Chairman of the Board of Directors of Pacific Energy GP, Inc. effective March 3, 2005.  Mr. Polson was paid approximately $0.9 million, representing accrued but unused vacation, accrued salary through March 3, 2005 and payment in satisfaction of other obligations under his employment agreement.  The severance portion of this payment of approximately $0.9 million was recorded as an expense in “Transaction costs” in the accompanying condensed consolidated income statements (see “Note 6 – Allocation of Net Income”). LBP reimbursed this amount, which was recorded as a partner’s capital contribution.  Pursuant to the Consulting Agreement, Mr. Polson has agreed to perform advisory services to PEM from time to time as shall be mutually agreed between Mr. Polson and the Chief Executive Officer of PEM. In consideration for Mr. Polson’s services under the Consulting Agreement, which has a one-year term, Mr. Polson will receive a monthly consulting fee of $12,500 and reimbursement of all reasonable business expenses incurred or paid by Mr. Polson in the course of performing his duties thereunder.

 

                LB Pacific, LP and TAC: LBP and TAC reimbursed the Partnership for certain other costs relating to the LB Acquisition.  These included $1.2 million for the Consent Solicitation (as defined and further described in “Note 4—Long-Term Debt”, below) and $0.3 million for legal and other expenses (also see “Note 6—Allocation of Net Income”).

 

                Other Related Party Transactions

 

                Revenue from Related Parties: Rocky Mountain Pipeline system (“RMPS”) serves as the contract operator for certain gas

 

8



 

producing properties owned by a subsidiary of TAC in Wyoming and Utah, in exchange for which RMPS is reimbursed its direct costs of operation and is paid an annual fee of $0.3 million as compensation for the time spent by RMPS management and for other overhead services related to their activities.

 

                RMPS also receives an operating fee and management fee from Frontier Pipeline Company (“Frontier”) in connection with time spent by RMPS management and for other services related to Frontier’s pipeline’s activities. RMPS received $0.2 million and $0.1 million for the three months ended March 31, 2005 and 2004, respectively.

 

                Expenses Paid to Related Parties: The Partnership utilizes the financial accounting system owned and provided by TAC under a shared services arrangement for a fee of $0.1 million per year and TAC charges the Partnership for any out-of-pocket costs it incurs. The fixed annual fee includes all license, maintenance and employee costs associated with the Partnership’s use of the financial accounting system.  The Partnership will continue to use the financial accounting system after the close of the LB Acquisition pursuant to a transition services agreement until December 31, 2005, or earlier if elected by the Partnership.

 

                In January 2003, the Partnership began leasing approximately 4,700 square feet of office space from an affiliate of TAC, for a term of five years at an annual cost of $0.1 million per year.   This space was increased to 5,400 square feet in 2004.

 

                Due from (to) Related Parties:  Due from related parties consists of $0.1 million due from PEM and $0.5 million due to Pacific Energy GP, Inc. at March 31, 2005 and December 31, 2004, respectively.

 

4.             LONG-TERM DEBT

 

                The Partnership’s long-term debt obligations are shown below:

 

 

 

March 31,
2005

 

December 31,
2004

 

 

 

(in thousands)

 

 

 

 

 

 

 

Senior secured U.S. revolving credit facility, bearing interest at 4.4% on March 31, 2005, due July 2007

 

$

52,000

 

$

51,000

 

Senior secured Canadian revolving credit facility, bearing interest at 4.9% on March 31, 2005, due May 2007

 

53,737

 

54,005

 

Senior notes, net of unamortized discount of $4,125 and including fair value increase of $1,063, with a coupon of 71/8%, due June 2014

 

246,938

 

248,491

 

Future payment for MAPL assets, net of unamortized discount of $439, due June 2007

 

3,694

 

3,667

 

Long-term debt

 

$

356,369

 

$

357,163

 

 

Under the Indenture governing the Partnership’s Senior Notes, the Partnership would have been required to make a “Change of Control Offer” to the note holders if the LB Acquisition would have caused a rating decline. In order to avoid triggering the “Change of Control Offer” provision, the Partnership solicited the consent (the “Consent Solicitation”) of the holders of the Senior Notes to amend certain provisions of the Indenture, including an amendment to the definition of “Change of Control.”  The Consent Solicitation commenced on January 28, 2005 and expired on February 10, 2005. During that time, a majority of the holders of the Senior Notes consented to the adoption of the proposed amendments and as such the proposed amendments were approved. Thereafter, a supplemental indenture that incorporated the proposed amendments was executed by the parties to the Indenture. Fees of approximately $0.6 million paid to holders of the Senior Notes were capitalized and included in “Other assets” in the accompanying condensed consolidated balance sheet at March 31, 2005 and will be amortized over the remaining life of the Senior Notes.  Solicitation–related fees and expenses of approximately $0.6 million are included in “Transaction costs” in the accompanying condensed consolidated statements of income. LBP and TAC reimbursed the Partnership for the costs of the Consent Solicitation, which are recorded as a partner’s capital contribution (see “Note 3—Related Party Transactions”).

 

                Additionally, the U.S. and Canadian revolving credit facilities also contained change of control provisions.  The Partnership amended the U.S. and Canadian revolving credit facilities to account for the change in control of its General Partner.

 

9



 

5.             VESTING OF UNIT GRANTS UNDER LONG-TERM INCENTIVE PLAN

 

                On March 3, 2005, in connection with the LB Acquisition and with the change in control of the Partnership’s General Partner, all restricted units outstanding under the Partnership’s Long-Term Incentive Plan immediately vested pursuant to the terms of the grants.  The Partnership issued 99,583 common units and recognized a compensation expense of $3.1 million, which is included in “Accelerated long-term incentive plan compensation expense” in the accompanying condensed consolidated statements of income.

 

6.             ALLOCATION OF NET INCOME

 

                The allocation of net income between the Partnership’s general partner and limited partners is as follows.

 

 

 

Three Months Ended March 31,

 

 

 

2005

 

2004

 

 

 

(in thousands)

 

 

 

 

 

 

 

Net income

 

$

3,421

 

$

8,077

 

Transaction costs reimbursed by general partner:

 

 

 

 

 

Senior Notes consent solicitation and other costs

 

893

 

 

Severance and other costs

 

914

 

 

Total transaction costs reimbursed by general partner

 

1,807

 

 

Income before transaction costs reimbursed by general partner

 

5,228

 

8,077

 

General partner’s share of income

 

2

%

2

%

General partner allocated share of net income before transaction costs

 

105

 

162

 

Transaction costs reimbursed by general partner

 

(1,807

)

 

Net income (loss) allocated to general partner

 

$

(1,702

)

$

162

 

 

 

 

 

 

 

Income before transaction costs reimbursed by general partner

 

$

5,228

 

$

8,077

 

Limited partners share of income

 

98

%

98

%

Limited partners share of net income

 

$

5,123

 

$

7,915

 

 

 

 

 

 

 

Net income (loss) allocated to general partner

 

$

(1,702

)

$

162

 

Net income allocated to limited partners

 

5,123

 

7,915

 

Net income

 

$

3,421

 

$

8,077

 

 

 

 

 

 

 

                LBP and TAC reimbursed the Partnership for certain costs incurred in connection with the LB Acquisition.  The Partnership was reimbursed $1.2 million for costs incurred in connection with the consent solicitation, $0.3 million of legal and other costs and $0.9 million relating to severance costs (see “Note 3—Related Party Transactions”), for a total of $2.4 million.  Of the $1.2 million incurred for the consent solicitation, $0.6 million was capitalized as deferred financing costs and $0.6 million was expensed.

 

10



 

7.             SEGMENT INFORMATION

 

                The Partnership’s business and operations are organized into two regional business segments: West Coast Business Unit and Rocky Mountain Business Unit. The West Coast Business Unit includes: (i) Pacific Pipeline System LLC, owner of Line 2000 and Line 63, (ii) Pacific Marketing and Transportation LLC, owner of the PMT gathering and blending system, and (iii) Pacific Terminals LLC, owner of the Pacific Terminals storage and distribution system. The Rocky Mountain Business Unit includes: (i) Rocky Mountain Pipeline System LLC, owner of the Partnership’s interest in various pipelines that make up the Western Corridor and Salt Lake City Core systems, (ii) Ranch Pipeline LLC, the owner of a 22.22% partnership interest in Frontier Pipeline Company, and (iii) PEG Canada, L.P. and its Canadian subsidiaries, which own and operate the Rangeland system (for the period since May 11, 2004). General and administrative costs, which consist of executive management, accounting and finance, human resources, information technology, investor relations, legal, and business development, are not allocated to the individual business units. Information regarding these two business units is summarized below:

 

 

 

 

 

 

 

Intersegment and

 

 

 

 

 

West Coast

 

Rocky Mountain

 

Intrasegment

 

 

 

 

 

Business Unit

 

Business Unit

 

Eliminations

 

Total

 

 

 

(in thousands)

 

Three months ended March 31, 2005

 

 

 

 

 

 

 

 

 

Business unit revenue:

 

 

 

 

 

 

 

 

 

Pipeline transportation revenue

 

$

17,443

 

$

12,456

 

$

(1,862

)

$

28,037

 

Storage and distribution revenue

 

10,472

 

 

(150

)

10,322

 

Pipeline buy/sell transportation revenue(1)

 

 

9,106

 

 

 

9,106

 

Crude oil sales, net of purchases(2)

 

1,812

 

 

(30

)

1,782

 

Net revenue

 

29,727

 

21,562

 

 

 

49,247

 

Expenses:

 

 

 

 

 

 

 

 

 

Operating

 

14,507

 

9,289

 

(2,042

)

21,754

 

Line 63 oil release costs(3)

 

2,000

 

 

 

 

2,000

 

Depreciation and amortization

 

3,477

 

3,052

 

 

 

6,529

 

Total expenses

 

19,984

 

12,341

 

 

 

30,283

 

Share of net income of Frontier

 

 

357

 

 

 

357

 

Operating income from segments(4)

 

$

9,743

 

$

9,578

 

 

 

$

19,321

 

Business unit assets(5)

 

$

538,568

 

$

350,600

 

 

 

$

889,168

 

Capital expenditures(6)

 

$

750

 

$

2,932

 

 

 

$

3,682

 

 

 

 

 

 

 

 

 

 

 

Three months ended March 31, 2004

 

 

 

 

 

 

 

 

 

Business unit revenue:

 

 

 

 

 

 

 

 

 

Pipeline transportation revenue

 

$

15,691

 

$

10,543

 

$

(1,507

)

$

24,727

 

Storage and distribution revenue

 

10,223

 

 

(100

)

10,123

 

Crude oil sales, net of purchases(2)

 

4,812

 

 

 

 

4,812

 

Net revenue

 

30,726

 

10,543

 

 

 

39,662

 

Expenses:

 

 

 

 

 

 

 

 

 

Operating

 

14,706

 

5,818

 

(1,607

)

18,917

 

Depreciation and amortization

 

3,765

 

1,477

 

 

 

5,242

 

Total expenses

 

18,471

 

7,295

 

 

 

24,159

 

Share of net income of Frontier

 

 

393

 

 

 

393

 

Operating income from segments(4)

 

$

12,255

 

$

3,641

 

 

 

$

15,896

 

Business unit assets(5)

 

$

511,254

 

$

123,837

 

 

 

$

635,091

 

Capital expenditures(6)

 

$

793

 

$

1,291

 

 

 

$

2,084

 


(1)                                  Includes the revenue of the Rangeland system, which was acquired on May 11, 2004 and June 30, 2004.  Pipeline buy/sell transportation revenue reflects net revenues of approximately $1.4 million on buy/sell transactions with different parties of $20.5 million.  The remaining amount reflects net revenues on buy/sell transactions with the same party.

(2)                                  The above amounts are net of purchases of $114,391 and $81,115 for 2005 and 2004, respectively.

(3)                                  See “Note 2 — Line 63 Oil Release Reserve” for further information.

 

11



 

(4)                                  The following is a reconciliation of operating income as stated above to net income:

 

 

 

Three Months Ended March 31,

 

 

 

2005

 

2004

 

 

 

(in thousands)

 

Income Statement Reconciliation

 

 

 

 

 

Operating income from above:

 

 

 

 

 

West Coast Business Unit

 

$

9,743

 

$

12,255

 

Rocky Mountain Business Unit

 

9,578

 

3,641

 

Operating income before general and administrative expense

 

19,321

 

15,896

 

Less: General and administrative expense

 

(5,172

)

(3,854

)

Less: Accelerated long-term incentive plan compensation expense

 

(3,115

)

 

Less: Transaction costs

 

(1,807

)

 

Operating income

 

9,227

 

12,042

 

Interest expense

 

(5,598

)

(4,126

)

Other income

 

353

 

161

 

Income tax expense

 

(561

)

 

Net income

 

$

3,421

 

$

8,077

 

 

(5)                                  Business unit assets do not include assets related to the Partnership’s corporate activity.  As of March 31, 2005 and 2004, corporate related assets were $30,922 and $50,449 respectively.

(6)                                  Capital expenditures do not include the Pier 400 project and other corporate related capital expenditures.  Pier 400 project and other corporate related capital expenditures were $0.7 million and $0.3 million for the three months ended March 31, 2005 and 2004, respectively.

 

8.             CONTINGENCIES

 

                The Partnership is involved in various regulatory disputes, litigation and claims arising out of its operations in the normal course of business. See also “Note 2—Line 63 Oil Release Reserve”. The Partnership is not currently a party to any other legal or regulatory proceedings, the resolution of which could be expected to have a material adverse effect on its business, financial condition or results of operations.

 

9.             SUBSEQUENT EVENT

 

                On April 22, 2005, the Partnership declared a cash distribution of $0.5125 per limited partner unit, payable on May 13, 2005, to unitholders of record as of May 2, 2005.

 

12



 

10.          SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

 

                Given that certain, but not all subsidiaries of the Partnership are guarantors of the 71/8% Senior Notes, the Partnership is required to present the following supplemental condensed consolidating financial information. For purposes of the following footnote, the Partnership and its predecessor are referred to as “Parent.” Rocky Mountain Pipeline System LLC, Pacific Marketing and Transportation LLC, Ranch Pipeline LLC, PEG Canada GP LLC, PEG Canada, L.P. and Pacific Energy Group LLC, the guarantors of the Senior Notes, are collectively referred to as the “Guarantor Subsidiaries,” and Pacific Pipeline System LLC, Pacific Terminals LLC, Rangeland Pipeline Company, Rangeland Marketing Company, Rangeland Northern Pipeline Company, Rangeland Pipeline Partnership and Aurora Pipeline Company, Ltd. are referred to as “Non-Guarantor Subsidiaries.”

 

                The following supplemental condensed consolidating financial information reflects the Parent’s separate accounts, the combined accounts of the Guarantor Subsidiaries, the combined accounts of the Parent’s Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations and the Parent’s consolidated accounts for the dates and periods indicated. For purposes of the following condensed consolidating information, the Parent’s investments in its subsidiaries and the Guarantor Subsidiaries’ investments in their subsidiaries are accounted for under the equity method of accounting:

 

 

 

Balance Sheet

 

 

 

March 31, 2005

 

 

 

 

 

Guarantor

 

Non-Guarantor

 

Consolidating

 

 

 

 

 

Parent

 

Subsidiaries

 

Subsidiaries

 

Adjustments

 

Total

 

 

 

(in thousands)

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

Current assets

 

$

31,819

 

$

101,750

 

$

72,272

 

$

(55,499

)

$

150,342

 

Property and equipment

 

 

129,014

 

586,566

 

 

715,580

 

Equity investments

 

357,747

 

209,668

 

 

(559,215

)

8,200

 

Intercompany notes receivable

 

269,450

 

338,574

 

 

(608,024

)

 

Other assets

 

6,113

 

1,814

 

38,041

 

 

45,968

 

Total assets

 

$

665,129

 

$

780,820

 

$

696,879

 

$

(1,222,738

)

$

920,090

 

Liabilities and partners’ capital:

 

 

 

 

 

 

 

 

 

 

 

Current liabilities

 

$

5,220

 

$

100,991

 

$

58,428

 

$

(55,499

)

$

109,140

 

Long-term debt

 

246,938

 

52,000

 

57,431

 

 

356,369

 

Deferred income taxes

 

 

497

 

33,751

 

 

34,248

 

Intercompany notes payable

 

 

269,450

 

338,574

 

(608,024

)

 

Other liabilities

 

 

135

 

7,227

 

 

7,362

 

Total partners’ capital

 

412,971

 

357,747

 

201,468

 

(559,215

)

412,971

 

Total liabilities and partners’ capital

 

$

665,129

 

$

780,820

 

$

696,879

 

$

(1,222,738

)

$

920,090

 

 

 

 

Balance Sheet

 

 

 

December 31, 2004

 

 

 

 

 

Guarantor

 

Non-Guarantor

 

Consolidating

 

 

 

 

 

Parent

 

Subsidiaries

 

Subsidiaries

 

Adjustments

 

Total

 

 

 

(in thousands)

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

Current assets

 

$

14,869

 

$

80,320

 

$

41,948

 

$

(41,592

)

$

95,545

 

Property and equipment

 

 

129,496

 

589,128

 

 

718,624

 

Equity investments

 

366,148

 

194,787

 

 

(553,049

)

7,886

 

Intercompany notes receivable

 

283,550

 

338,884

 

 

(622,434

)

 

Other assets

 

7,223

 

1,993

 

38,634

 

 

47,850

 

Total assets

 

$

671,790

 

$

745,480

 

$

669,710

 

$

(1,217,075

)

$

869,905

 

Liabilities and partners’ capital:

 

 

 

 

 

 

 

 

 

 

 

Current liabilities

 

$

833

 

$

44,177

 

$

44,627

 

$

(41,592

)

$

48,045

 

Long-term debt

 

248,491

 

51,000

 

57,672

 

 

357,163

 

Deferred income taxes

 

 

470

 

34,086

 

 

34,556

 

Intercompany notes payable

 

 

283,550

 

338,884

 

(622,434

)

 

Other liabilities

 

 

135

 

7,540

 

 

7,675

 

Total partners’ capital

 

422,466

 

366,148

 

186,901

 

(553,049

)

422,466

 

Total liabilities and partners’ capital

 

$

671,790

 

$

745,480

 

$

669,710

 

$

(1,217,075

)

$

869,905

 

 

13



 

 

 

Statement of Income

 

 

 

Three Months Ended March 31, 2005

 

 

 

 

 

Guarantor

 

Non-Guarantor

 

Consolidating

 

 

 

 

 

Parent

 

Subsidiaries

 

Subsidiaries

 

Adjustments

 

Total

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Net operating revenues

 

$

 

$

14,268

 

$

37,021

 

$

(2,042

)

$

49,247

 

Operating expenses

 

 

(9,968

)

(13,828

)

2,042

 

(21,754

)

Line 63 oil release costs

 

 

 

(2,000

)

 

(2,000

)

General and administrative expense(1)

 

 

(4,618

)

(554

)

 

(5,172

)

Accelerated long-term incentive plan compensation expense

 

 

(2,684

)

(431

)

 

(3,115

)

Transaction costs

 

(893

)

(914

)

 

 

(1,807

)

Depreciation and amortization expense

 

 

(1,624

)

(4,905

)

 

(6,529

)

Share of net income of Frontier

 

 

357

 

 

 

357

 

Operating income

 

(893

)

(5,183

)

15,303

 

 

9,227

 

Interest expense

 

(4,078

)

(679

)

(841

)

 

(5,598

)

Intercompany interest income (expense)

 

 

6,271

 

(6,271

)

 

 

Equity earnings

 

8,384

 

7,990

 

 

(16,374

)

 

Other income

 

8

 

166

 

179

 

 

353

 

Income tax benefit (expense)

 

 

(181

)

(380

)

 

(561

)

Net income

 

$

3,421

 

$

8,384

 

$

7,990

 

$

(16,374

)

$

3,421

 


(1)          General and administrative expense is not currently allocated between Guarantor and Non-Guarantor Subsidiaries for financial reporting purposes.

 

 

 

Statement of Income

 

 

 

Three Months Ended March 31, 2004

 

 

 

 

 

Guarantor

 

Non-Guarantor

 

Consolidating

 

 

 

 

 

Parent

 

Subsidiaries

 

Subsidiaries

 

adjustments

 

Total

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Net operating revenues

 

$

 

$

15,356

 

$

25,913

 

$

(1,607

)

$

39,662

 

Operating expenses

 

 

(9,700

)

(10,824

)

1,607

 

(18,917

)

General and administrative expense(1)

 

 

(3,828

)

(26

)

 

(3,854

)

Depreciation and amortization expense

 

 

(1,595

)

(3,647

)

 

(5,242

)

Share of net income of Frontier

 

 

393

 

 

 

393

 

Operating income

 

 

626

 

11,416

 

 

12,042

 

Interest expense

 

 

(4,126

)

 

 

(4,126

)

Intercompany interest income (expense)

 

 

3,747

 

(3,747

)

 

 

Equity earnings

 

8,076

 

7,710

 

 

(15,786

)

 

Other income

 

1

 

119

 

41

 

 

161

 

Net income

 

$

8,077

 

$

8,076

 

$

7,710

 

$

(15,786

)

$

8,077

 


(1)          General and administrative expense is not currently allocated between Guarantor and Non-Guarantor Subsidiaries for financial reporting purposes.

 

14



 

 

 

Statement of Comprehensive Income

 

 

 

Three Months Ended March 31, 2005

 

 

 

 

 

Guarantor

 

Non- Guarantor

 

Consolidating

 

 

 

 

 

Parent

 

Subsidiaries

 

Subsidiaries

 

Adjustments

 

Total

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

3,421

 

$

8,384

 

$

7,990

 

$

(16,374

)

$

3,421

 

Change in fair value of hedging derivatives

 

(1,132

)

(1,132

)

 

1,132

 

(1,132

)

Foreign currency translation adjustment

 

(537

)

(537

)

(537

)

1,074

 

(537

)

Comprehensive income

 

$

1,752

 

$

6,715

 

$

7,453

 

$

(14,168

)

$

1,752

 

 

 

 

 

Statement of Comprehensive Income

 

 

 

Three Months Ended March 31, 2004

 

 

 

 

 

Guarantor

 

Non- Guarantor

 

Consolidating

 

 

 

 

 

Parent

 

Subsidiaries

 

Subsidiaries

 

Adjustments

 

Total

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

8,077

 

$

8,076

 

$

7,710

 

$

(15,786

)

$

8,077

 

Change in fair value of hedging derivatives

 

(4,236

)

(4,236

)

 

4,236

 

(4,236

)

Comprehensive income

 

$

3,841

 

$

3,840

 

$

7,710

 

$

(11,550

)

$

3,841

 

 

15



 

 

 

 

Statement of Cash Flows

 

 

 

Three Months Ended March 31, 2005

 

 

 

 

 

Guarantor

 

Non-Guarantor

 

Consolidating

 

 

 

 

 

Parent

 

Subsidiaries

 

Subsidiaries

 

Adjustments

 

Total

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

3,421

 

$

8,384

 

$

7,990

 

$

(16,374

)

$

3,421

 

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

Equity earnings

 

(8,384

)

(7,990

)

 

16,374

 

 

Distributions from subsidiaries

 

15,114

 

12,673

 

 

(27,787

)

 

Depreciation, amortization and other

 

157

 

2,984

 

4,864

 

 

8,005

 

Net changes in operating assets and liabilities

 

3,915

 

1,840

 

74

 

(1,323

)

4,506

 

NET CASH PROVIDED BY OPERATING ACTIVITIES

 

14,223

 

17,891

 

12,928

 

(29,110

)

15,932

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

Additions to property, equipment and other

 

 

(1,091

)

(3,169

)

 

(4,260

)

Intercompany

 

(914

)

 

 

914

 

 

NET CASH USED IN INVESTING ACTIVITIES

 

(914

)

(1,091

)

(3,169

)

914

 

(4,260

)

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES

 

(14,894

)

(18,276

)

(7,984

)

28,196

 

(12,958

)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

 

(1,585

)

(1,476

)

1,775

 

 

(1,286

)

CASH AND CASH EQUIVALENTS, beginning of reporting period

 

2,713

 

17,523

 

3,147

 

 

23,383

 

CASH AND CASH EQUIVALENTS, end of reporting period

 

$

1,128

 

$

16,047

 

$

4,922

 

$

 

$

22,097

 

 

16



 

 

 

Statement of Cash Flows

 

 

 

Three Months Ended March 31, 2004

 

 

 

 

 

Guarantor

 

Non-Guarantor

 

Consolidating

 

 

 

 

 

Parent

 

Subsidiaries

 

Subsidiaries

 

Adjustments

 

Total

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

8,077

 

$

8,076

 

$

7,710

 

$

(15,786

)

$

8,077

 

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

Equity earnings

 

(8,076

)

(7,710

)

 

15,786

 

 

Distributions from subsidiaries

 

12,390

 

10,997

 

 

(23,387

)

 

Depreciation, amortization and other

 

 

2,461

 

3,647

 

 

6,108

 

Net changes in operating assets and liabilities

 

 

(3,059

)

2,628

 

(572

)

(1,003

)

NET CASH PROVIDED BY OPERATING ACTIVITIES

 

12,391

 

10,765

 

13,985

 

(23,959

)

13,182

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

Acquisition deposit

 

 

(9,920

)

 

 

(9,920

)

Additions to property, equipment and other

 

 

(1,620

)

(793

)

 

(2,413

)

Intercompany

 

(117,061

)

 

 

117,061

 

 

NET CASH USED IN INVESTING ACTIVITIES

 

(117,061

)

(11,540

)

(793

)

117,061

 

(12,333

)

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES

 

104,005

 

25,722

 

(5,341

)

(93,102

)

31,284

 

NET DECREASE IN CASH AND CASH EQUIVALENTS

 

(665

)

24,947

 

7,851

 

 

32,133

 

CASH AND CASH EQUIVALENTS, beginning of reporting period

 

746

 

8,603

 

350

 

 

9,699

 

CASH AND CASH EQUIVALENTS, end of reporting period

 

$

81

 

$

33,550

 

$

8,201

 

$

 

$

41,832

 

 

17



 

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

                References in this quarterly report on Form 10-Q to “Pacific Energy Partners,” “Partnership,” “we,” “ours,” “us” or like terms refer to Pacific Energy Partners, L.P. and its subsidiaries.

 

Forward-Looking Statements

 

                The information in this quarterly report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are identified as any statements that do not relate strictly to historical or current facts, including statements that use terms such as “anticipate,” “assume,” “believe,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “position,” “predict,” “project,” or “strategy” or the negative connotation or other variations of such terms or other similar terminology. In particular, statements express or implied, regarding our future results of operations or our ability to generate sales, income or cash flow or to make distributions to unitholders are forward-looking statements. Forward-looking statements are not guarantees of performance. Such statements are based on management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve risks and uncertainties. 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.

 

                We caution you that the forward-looking statements in this quarterly report on Form 10-Q are subject to all of the risks and uncertainties, many of which are beyond our control, incident to gathering, transporting, storing, and distributing crude oil and other related products and buying, gathering, blending and selling crude oil. For a more detailed description of these and other factors that may affect the forward-looking statements, please read “Risk Factors” contained in our annual report on Form 10-K for the year ended December 31, 2004, as well as other filings with the SEC. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. You should not put undue reliance on these forward-looking statements. We disclaim any obligation to announce publicly the result of any revision to any of the forward-looking statements to reflect future events or developments.

 

Introduction

 

                The following discussion of the financial condition and results of operations of Pacific Energy Partners, L.P. should be read together with the condensed consolidated financial statements and the notes thereto set forth elsewhere in this report. The discussion set forth in this section pertains to our unaudited condensed consolidated balance sheets, statements of income, statements of cash flows and statement of partners’ capital.

 

                This report on Form 10-Q should be read in conjunction with our annual report on Form 10-K for the year ended December 31, 2004.

 

Overview

 

                We are a publicly traded limited partnership engaged principally in the business of gathering, transporting, storing and distributing crude oil and related products in California and the Rocky Mountain region of the U.S. and in Alberta, Canada.  We conduct our business through two regional business segments: the West Coast Business Unit and the Rocky Mountain Business Unit. We generate revenue primarily by charging tariff rates for transporting crude oil on our pipelines and by leasing storage capacity.  We also buy, blend and sell crude oil, activities that are complementary to our pipeline transportation business.

 

Recent Developments

 

                Line 63 Crude Oil Release

 

                On March 23, 2005, a release of approximately 3,400 barrels of crude oil occurred on Line 63 when it was severed as a result of a landslide induced by heavy rainfall in the Pyramid Lake area of Los Angeles County.  Over the period March 2005 through March 2006, we expect to incur an estimated total of $13.5 million for oil containment and clean-up of the impacted areas, future monitoring costs, potential third-party claims and penalties, and other costs.  Through March 31, 2005, we had incurred approximately $3.3 million of the total expected oil release costs for work performed through such date.

 

                We have a pollution liability insurance policy with a $2.0 million deductible, and the insurance carrier has, subject to a reservation of certain rights, acknowledged coverage of the incident under the policy and has begun processing and paying invoices related to the clean-up.  Although we believe we are entitled, subject to the $2.0 million deductible, to recover substantially all of

 

18



 

our clean-up costs and third-party claims associated with the release, there is no absolute assurance that this will be the case.  In the first quarter of 2005, we have accrued a receivable of $11.5 million for insurance receipts that we deem probable. As new information becomes available in future periods, our initial estimates of costs and recoveries may change.

 

                Accrued costs relating to the release of $13.5 million, net of accrued insurance receipts of $11.5 million, or $2.0 million, is recorded in “Line 63 oil release costs” in the accompanying condensed consolidated statements of income.

 

                In addition, we expect to incur approximately $1.0 million in 2005 for the costs of repairing Line 63.  These costs, which are not covered by our insurance, will be expensed as incurred during the remainder of 2005.

 

On April 18, 2005, we received the necessary approvals to begin the repair of Line 63, and the first phase of the repair operation was completed on April 25, 2005, and Line 63 was returned to operation. During the time the pipeline was out of service, we transferred significant volumes of light crude oil, on a temporary basis, from Line 63 to Line 2000, to mitigate the impact on customers and limit the potential loss of revenue.  We also asked our customers to shift volumes of OCS crude oil from Line 63 to Line 2000.

 

The Partnership has filed an application with the California Public Utilities Commission to implement a temporary surcharge on its Line 63 tariff rates to recover its costs relating to this release together with other costs incurred or to be incurred as a result of problems caused by rain-induced earth movement and stream erosion.

 

                Sale of The Anschutz Corporation’s Interest in the Partnership

 

                On March 3, 2005, The Anschutz Corporation completed the sale of its 36.6% interest in the Partnership to LB Pacific, LP (“LBP”), an entity formed by Lehman Brothers Merchant Banking Group (“LBMB”).  The acquisition by LBP (the “LB Acquisition”) included the purchase of  a 100% ownership interest in Pacific Energy GP, Inc. (predecessor of Pacific Energy GP, LP), which owned (i) a 2% general partner interest in the Partnership and the incentive distribution rights, and (ii) 10,465,000 subordinated units of the Partnership representing a 34.6% limited partner interest.  Immediately prior to the closing of the LB Acquisition, Pacific Energy GP, Inc. was converted to Pacific Energy GP, LLC, a Delaware limited liability company; and immediately after the closing of the LB Acquisition, Pacific Energy GP, LLC was converted to Pacific Energy GP, LP, a Delaware limited partnership (together with its predecessors, the “General Partner”).  The general partner of Pacific Energy GP, LP is Pacific Energy Management LLC, a Delaware limited liability company (“PEM” or the “Managing General Partner”), which is 100% owned by LBP. Immediately following the closing of the LB Acquisition, our General Partner distributed the 10,465,000 subordinated units of the Partnership to LBP.

 

                In connection with the conversion of our General Partner to a limited partnership, our General Partner ceased to have a board of directors, and is now managed by PEM, its general partner. PEM has a board of directors (the “Board of Directors” or “Board”) that manages the business and affairs of PEM and, thus, indirectly manages the business and affairs of our General Partner and the Partnership.  The Board of Directors is comprised of eleven directors, six of whom served on the Board of Directors of our General Partner prior to the LB Acquisition, together with five new directors appointed by LBP. All of the officers and employees of our General Partner were transferred to the same positions with PEM, and the Board established the same committees as had been maintained by our General Partner prior to the LB Acquisition.  PEM also adopted our General Partner’s governance guidelines and its compensation structure and employee benefit plans and policies.

 

                Additionally, on March 21, 2005, an affiliate of First Reserve Corporation acquired a 30% minority interest in LBP from LBMB.  LBMB and its affiliates will continue to own a 70% controlling interest in LBP.  As a result of this investment in LBP, First Reserve was entitled to nominate one director to the Board of Directors of PEM. The director nominated by First Reserve, who was one of the five new directors appointed by LBP, was appointed to the Board on April 6, 2005.

 

                Pursuant to an Ancillary Agreement, LBP and The Anschutz Corporation reimbursed us the amount of $2.4 million for the cost of a consent solicitation to the holders of our Senior Notes to amend the indenture governing the Senior Notes, and for severance and other costs incurred in connection with the sale of our General Partner.  The Partnership was required by generally accepted accounting principles to record $0.6 million as capitalized deferred financing costs and $1.8 million as an expense.  The reimbursements were recorded as a partner’s capital contribution.

 

                On March 3, 2005, in connection with the change in control of the our General Partner, all restricted units outstanding under the Long-Term Incentive Plan immediately vested pursuant to the terms of the grants.  The Partnership issued 99,583 common units and recorded a compensation expense of $3.1 million.

 

Business Fundamentals

 

                Pipeline Transportation

 

                We generate pipeline transportation revenue by charging tariff rates for transporting crude oil on our common carrier pipelines. The fundamental items impacting our pipeline transportation revenue are the volume of crude oil or throughput that we transport on our pipelines, and our tariff rates. Throughput on our pipelines fluctuates based on the volume of crude oil available for transport on our pipelines, the demand for refined products, refinery or pipeline downtime and the availability of alternate sources of crude oil for the refineries we serve.

 

                Our shippers determine the amount of crude oil we transport on our pipelines, but we influence these volumes through the level and type of service we provide and the rates we charge. Our rates need to be competitive to transportation alternatives, which are mostly other pipelines.

 

19



 

                The tariff rates we charge on Line 2000 and the Line 63 system are regulated by the California Public Utilities Commission (the “CPUC”). Tariffs on Line 2000 are established based on market considerations, subject to certain contractual limitations. Tariffs on Line 63, which are cost-of-service based tariffs, are based upon the costs to operate and maintain the pipeline, as well as charges for the depreciation of the capital investment in the pipeline and the authorized rate of return. The tariff rates charged on our U.S. Rocky Mountain pipelines are regulated by either the FERC or the Wyoming Public Service Commission, generally under a cost-of-service approach.

 

                On May 1, 2004, we increased the tariff rates on Line 2000 by approximately 6%, based on a contractually agreed index of cost changes.  This index is reviewed annually. In April 2005, the CPUC approved an increase of approximately 4.8% in the tariff rate on Line 2000 effective May 1, 2005. Effective November 1, 2004, we increased the tariff rates on our Line 63 system by 9.5%.  This increase was the first for Line 63 since 2001.  These tariff rate increases partially mitigate the impact of declining throughput.

 

                The availability of crude oil for transportation on our pipelines is dependent, in part, on the amount of drilling and enhanced recovery activity in the production fields we serve in our West Coast operations and in parts of our Rocky Mountain operations. With the passage of time, production of crude oil in an individual well naturally declines, which can in the short term be offset, in whole or in part, by additional drilling or the implementation of recovery enhancement measures. In the San Joaquin Valley and in the California Outer Continental Shelf (“OCS”), total production is generally declining.

 

In March 2005, Shell Oil completed the sale of its Bakersfield refinery to Flying J, Inc.  We believe we are well positioned to benefit from the refinery’s continued operation and we are working with Flying J to deliver additional volumes of crude oil to the Bakersfield refinery and deliver volumes from the refinery south to the Los Angeles Basin.

 

                In the Rocky Mountains, our pipelines are connected to Canadian sources of crude oil, and in 2004 we completed the acquisition of the Rangeland system, giving us greater access to significant supplies of Canadian crude oil, including synthetic crude oil, which we believe will replace any long term U.S. Rocky Mountain production declines and meet growing demand in the U.S. Rocky Mountain region.  It appears in recent months that production in the U.S. Rocky Mountains may be increasing with the increased amount of natural gas related drilling, which results in increased volumes of crude oil and condensate.  We believe, however, that the longer term production of crude oil will resume its historical decline.

 

                Storage and Distribution

 

                We provide storage and distribution services to refineries in the Los Angeles Basin through our Pacific Terminals (“PT”) storage and distribution system. The fundamental items impacting our storage and distribution revenue are the amount of storage capacity we have under lease, the lease rates for that capacity and the length of each lease. Demand for crude oil storage capacity tends to be more stable over time, and leases for crude oil storage capacity are usually long term (more than one year). Demand for storage capacity for other dark products is less stable, and varies depending on, among other things, refinery production runs and maintenance activities. Leases for dark products storage capacity are usually short term (less that one year). One of our business goals is to convert a number of dark products tanks to more flexible crude oil service (which can also accommodate other dark products); we currently await permit approvals for one such tank conversion and plan to convert a second tank in 2005.

 

                While PT’s rates are regulated by the CPUC, the CPUC has authorized PT to establish its rates based on market conditions through negotiated contracts.

 

                Pipeline Buy/Sell Transportation

 

                Throughput on our Rangeland system, which was acquired in the second quarter of 2004, varies with many of the same factors described in “Pipeline Transportation” above.  In addition, following completion of our Edmonton initiation station, scheduled for completion in the fourth quarter of 2005, throughput will vary with our success in attracting new supplies of synthetic crude oil to our system.

 

We are making significant changes to the revenue-generating capability of the Rangeland system by (i) combining and fully integrating all of our Canadian and U.S. Rocky Mountain pipeline assets under common management, (ii) establishing connections with other pipelines, thereby expanding the throughput capacity of the Rangeland system, and (iii) constructing a pump station and receiving terminal in Edmonton, Alberta.  The development of the new receiving terminal and pump station, which will provide access to synthetic and other types of Canadian crude oil, continues to progress.  Construction of this facility, together with additional tanks along the pipeline corridor, is expected to be complete by the fourth quarter of 2005.

 

20



 

                The Rangeland system operates as a proprietary system and, therefore, we take title to the crude oil that is gathered and transported. Pursuant to a transportation service agreement between two of our subsidiaries, Rangeland Marketing Company (“RMC”) and Rangeland Pipeline Partnership, RMC controls the entire capacity of Rangeland pipeline. Customers who wish to transport product on Rangeland pipeline must either: (i) sell product to RMC at an inlet point and repurchase such product at agreed upon delivery points for the price paid at the inlet to the pipeline plus an established location differential; or (ii) sell product to RMC at the inlet to the pipeline without repurchasing product from RMC.

 

                Virtually all of the pipelines that comprise the Rangeland system are subject to the jurisdiction of the Alberta Energy Utilities Board (“EUB”). A short segment of the Rangeland system that connects to the Western Corridor system at the U.S.- Canadian border is subject to the jurisdiction of the Canadian National Energy Board (“NEB”). Neither the EUB nor the NEB will generally review rates set by a crude oil pipeline operator unless it receives a complaint relating to transportation rates.

 

                Effective December 1, 2004, we increased the location differentials on the Rangeland pipeline by an average of 10.8%.

 

Gathering and Blending

 

                Through our Pacific Marketing and Transportation (“PMT”) subsidiary, we purchase, gather, blend and resell crude oil in California’s San Joaquin Valley. Our PMT gathering and blending system is a proprietary intrastate operation that is not regulated by the CPUC or the FERC. It is complementary to our West Coast pipeline transportation business. The gathering network effectively extends our pipeline network to capture supplies of crude oil for transportation on our trunk pipelines to Los Angeles that might not otherwise be shipped through our pipelines.

 

                The contribution of our PMT gathering and blending operations is, for several reasons, a variable part of our income. First, it varies with the price differential between the cost of the varying grades of crude oil and natural gasoline that PMT buys for use in its blending operations, and the price of the blended crude oil it sells. Costs and sales prices are generally impacted by crude oil prices, as well as by local supply and demand forces, including regulations affecting refined product specifications. Second, it varies with the price differential between crude oil purchased on one price basis and sold on a different price basis. Finally, it varies with the volumes gathered and blended. We seek to control these variations through our risk management policy, which provides specific guidelines for our crude oil marketing and hedging activities and requires oversight by our senior management.

 

                Our blending margins are a function of the cost of the heavy and light crude oils and natural gasoline that we buy and blend, relative to the price of the blended crude oil we sell.  Blending margins exceeded their historical averages in the first eight months of 2004; however, since September 2004, blending margins have been below their historical averages.  Since September 2004, foreign imports of crude oil into the Los Angeles Basin have been highly discounted relative to West Texas Intermediate (“WTI”) prices, which reduced demand for and prices of local California crude oil, including crude oil gathered and blended by us in the San Joaquin Valley. As the demand for and price of our blended crude oil has fallen, we have taken action to cancel certain purchase contracts and to reduce the volume we gather, blend and sell.  In addition, margins on one particular contract declined as the difference between purchases made on a WTI price basis and sales made on a West Coast price basis deviated from historical norms over the period from September 2004 through March 2005. This contract expired on March 31, 2005.

 

                Acquisitions and New Projects

 

                We intend to continue to pursue acquisitions and new projects for development of additional midstream assets, including pipeline, storage and terminal facilities. We also intend to expand, principally by acquisition, into the refined product and natural gas storage and transportation businesses.  We expect the acquisitions and new projects to be accretive to our cash flow and complement our existing businesses. We expect to fund acquisitions and new projects with a combination of debt and additional Partnership units, including common units. We expect to maintain a debt to total capitalization ratio of approximately 50% over time.

 

Operating Expenses

 

                A substantial portion of the operating expenses we incur, including the cost of field and support personnel, maintenance, control systems, telecommunications, rights-of-way and insurance, varies little with changes in throughput. Certain of our costs do, however, vary with throughput, the most material being the cost of power used to run pump stations along our pipelines. Major maintenance costs can also vary depending on a particular asset’s age and/or regulatory requirements, such as mandatory inspections at defined intervals. Unanticipated costs can include the costs of cleanup of any release of oil to the extent not covered by insurance.

 

Employees

 

                We do not have any employees, except in Canada.  Our Managing General Partner provides employees to conduct our U.S. operations.  We and our Managing General Partner collectively employ approximately 315 individuals who directly support our

 

21



 

operations. We consider employee relations to be good. None of these employees are subject to a collective bargaining agreement. Our Managing General Partner does not conduct any business other than with respect to the Partnership. All expenses incurred by our Managing General Partner are charged to us. Please read “Note 3 - Related Party Transactions” in the footnotes to the condensed consolidated financial statement.

 

                Impact of Foreign Exchange Rates

 

                Assets and liabilities of our Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using the average exchange rate during the reporting period. The reported cash flow of our Canadian operations is based on the U.S. dollar equivalent of such amounts measured in Canadian dollars. The results of our Canadian operations and distributions from our Canadian subsidiaries to the Partnership may vary in U.S. dollar terms based on fluctuations in currency exchange rates irrespective of our Canadian subsidiaries’ underlying operating results.  In addition, the amount of monies we repatriate from Canada will vary with fluctuations in currency exchange rates and may impact the cash available for distribution to our unitholders.

 

Critical Accounting Policies and Estimates

 

                Our consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States, which require management to make estimates and assumptions that affect the reported amounts of the assets and liabilities and disclosures of contingent assets and liabilities as of the date of the balance sheet, as well as the reported amounts of revenue and expenses during the reporting period. We routinely make estimates and judgments about the carrying value of our assets and liabilities that are not readily apparent from other sources. Such estimates and judgments are evaluated and modified as necessary on an ongoing basis. We believe that of our significant accounting policies (see “Note 1, Significant Accounting Policies,” to our consolidated financial statements in our annual report on Form 10-K for the year ended December 31, 2004) and estimates, the following may involve a higher degree of judgment and complexity:

 

                                                              We routinely apply the provisions of purchase accounting when recording our acquisitions. Application of purchase accounting requires that we estimate the fair value of the individual assets acquired and liabilities assumed. The valuation of the fair value of the assets involves a number of judgments and estimates. In our major acquisitions to date, we have engaged an outside valuation firm to provide us with an appraisal report, which we utilized in determining the purchase price allocation. The allocation of the purchase price to different asset classes impacts the depreciation expense we subsequently record. The principal assets we have acquired to date are property, pipelines, storage tanks and equipment.

 

                                                              We depreciate the components of our property and equipment on a straight-line basis over the estimated useful lives of the assets. The estimates of the assets’ useful lives require our judgment and our knowledge of the assets being depreciated. When necessary, the assets’ useful lives are revised and the impact on depreciation is treated on a prospective basis.

 

                                                              We accrue an estimate of the undiscounted costs of environmental remediation for work at identified sites where an assessment has indicated it is probable that cleanup costs are or will be required and may be reasonably estimated. In making these estimates, we consider information that is currently available, existing technology, enacted laws and regulations, and our estimates of the timing of the required remedial actions. We may use outside environmental consultants to assist us in making these estimates.  We also are required to estimate the amount of any probable recoveries, including insurance recoveries.  In addition, generally accepted accounting principles require us to establish liabilities for the costs of asset retirement obligations when the retirement date is determinable. We will record such liabilities only when such date is determinable.

 

                                                              From time to time, a shipper or group of shippers may initiate a regulatory proceeding or other action, challenging the tariffs we charge or have charged. In such cases, we assess the proceeding on an ongoing basis as to its likely outcome, in order to determine whether to accrue for a future expense. We use outside regulatory lawyers and financial experts to assist us in these assessments.

 

                                                              Our inventory of crude oil for our PMT gathering and blending operations, our Canadian operations and any inventory earned through our tariffs for the transportation of crude oil in our common carrier pipelines is carried on our books at the lower of cost or market value, unless it is hedged, in which case it is carried at market. On any unhedged portion, we are exposed to the potential for a write-down to market value.

 

22



 

Results of Operations

 

Three Months Ended March 31, 2005 Compared to Three Months Ended March 31, 2004

 

Summary

 

Net income for the three months ended March 31, 2005 was $3.4 million, or $0.17 per diluted limited partner unit compared, to $8.1 million, or $0.31 per diluted limited partner unit, for the three months ended March 31, 2004.

 

                Net income for the three months ended March 31, 2005 includes the operations of the Rangeland system after its acquisition on May 11, 2004 and its expansion by acquisition of the MAPL pipeline on June 30, 2004.

 

                Internally, in our analysis of operating results, we consider the impact of unusual items that we believe affect comparability between periods.  We also believe that providing a discussion and analysis of our results that is comparable year over year, provides a more accurate and thorough analysis of our results of operations.  We have also provided a reconciliation of net income to the results of our operations, excluding those unusual items, in the table below.  Following is a discussion of each of the unusual items that impacted the results of our operations.

 

                Oil Release on Line 63.  On March 23, 2005, a release of approximately 3,400 barrels of crude oil occurred on PPS’s Line 63 as a result of a landslide induced by heavy rainfall in northern Los Angeles County.  As discussed in “Recent Developments” above, for the three months ended March 31, 2005, we accrued $13.5 million to remediate the area, together with related costs.  Additionally, we have recorded $11.5 in receivables for amounts we believe to be recoverable under our insurance policy.  The net expense recorded was $2.0 million.  The discussion in “Recent Developments” describes the nature of these estimates and the potential for these estimates to increase or decrease in future periods.

 

Accelerated long-term incentive plan compensation expense.  On March 3, 2005, in connection with the change in control of our General Partner, all restricted units outstanding under the Long-term Incentive Plan immediately vested.  As a result, for the three months ended March 31, 2005, we recognized $3.1 million in compensation expense.

 

Transaction costs.  Pursuant to an Ancillary Agreement, LBP and The Anschutz Corporation reimbursed us $2.4 million for the cost of a consent solicitation to the holders of our Senior Notes to amend the indenture governing the Senior Notes and for severance and other costs incurred in connection with the sale of our General Partner.  The Partnership was required by generally accepted accounting principles to record $0.6 million as capitalized deferred financing costs and $1.8 million as an expense. The reimbursements were recorded as a partner’s capital contribution.

 

                The following table is reconciliation of net income to the results of our operations, excluding the items mentioned above:

 

 

 

Three Months Ended March 31,

 

 

 

 

 

 

 

2005

 

2004

 

Change

 

Percent

 

 

 

(In thousands)

 

 

 

Net income

 

$

3,421

 

$

8,077

 

$

(4,656

)

-58

%

Add: Line 63 oil release costs

 

2,000

 

 

2,000

 

 

Accelerated long-term incentive plan compensation expense

 

3,115

 

 

3,115

 

 

Transaction costs

 

1,807

 

 

1,807

 

 

 

 

$

10,343

 

$

8,077

 

$

2,266

 

28

%

 

 

 

 

 

 

 

 

 

 

Diluted weighted average limited partner units

 

29,673

 

25,149

 

4,524

 

18

%

 

                The improvement in the results of operations, excluding the effect of the unusual items mentioned above, reflects the benefit of (i) higher pipeline transportation revenues on the West Coast and Rocky Mountain pipelines, (ii) the operations of the Rangeland system acquired in May 2004, and (iii) cost savings for Pacific Terminals.  These increases were partially offset by significantly lower gathering and blending margins, which were below average in the three months ended March 31, 2005 and above average in the three months ended March 31, 2004.  There were 29.7 million weighted average limited partner units outstanding in the three months ended March 31, 2005, approximately 18% more limited partner units than the 25.0 million weighted average units outstanding in the three months ended March 31, 2004, due to the sale of additional common units to partially fund the acquisition of the Rangeland system, including the MAPL pipeline.

 

23



 

                Segment Information

 

                The following is a discussion of segment operating income.  Segment operating income does not include general and administrative expenses, accelerated long-term incentive compensation plan expense and transaction costs as these items are not allocated to the West Coast and Rocky Mountain business units.

 

 

 

Three Months Ended March 31,

 

 

 

 

 

West Coast

 

2005

 

2004

 

Change

 

Percent

 

 

 

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating income

 

$

9,743

 

$

12,255

 

$

(2,512

)

-20

%

Add: Line 63 oil release cost

 

2,000

 

 

2,000

 

 

 

 

$

11,743

 

$

12,255

 

$

(512

)

-4

%

Operating data:

 

 

 

 

 

 

 

 

 

Pipeline throughput (bpd)

 

138.5

 

133.6

 

4.9

 

4

%

 

                For the three months ended March 31, 2005, operating income excluding the effect of the net accrual of $2.0 million for the Line 63 oil release costs, was $11.7 million, compared to $12.3 million for the three months ended March 31, 2004.   West Coast pipeline volumes for the three months ended March 31, 2005 were approximately 4% higher than the first quarter of 2004. During the first quarter of 2004, volumes were impacted by a significant amount of Los Angeles area refinery maintenance, resulting in lower volumes moving south to Los Angeles. For the three months ended March 2005, the Partnership also experienced incremental revenue from increased tariffs on Line 63 and Line 2000 implemented in 2004. During the three months ended March 2005, Pacific Terminals also experienced increased storage revenues due to higher rates of tank utilization and cost savings in vapor recovery costs due to the installation of vapor treating equipment that was installed at the end of 2004. These increases in operating income were offset by additional costs incurred to address earth movement and stream erosion problems at other locations along both Line 63 and Line 2000, caused by heavy rainfall. PMT gathering and blending margins were also lower in the first quarter of 2005 due to pricing pressures from steeply discounted crude oil imports and the interruption of a scheduled sale due to the Line 63 crude oil release.  We consider this gathering and blending activity to be complementary to our pipeline transportation operations.

 

 

 

Three Months ended March 31,

 

 

 

 

 

Rocky Mountains

 

2005

 

2004

 

Change

 

Percent

 

 

 

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating income

 

$

9,578

 

$

3,641

 

$

5,937

 

163

%

Operating data (bpd):

 

 

 

 

 

 

 

 

 

Rangeland pipeline system:

 

 

 

 

 

 

 

 

 

Sundre—North

 

21.4

 

 

 

 

 

Sundre—South

 

48.2

 

 

 

 

 

Western Corridor system

 

22.5

 

16.0

 

6.5

 

41

%

Salt Lake City Core system

 

108.7

 

105.9

 

2.8

 

3

%

Frontier pipeline

 

38.3

 

43.9

 

(5.6

)

-13

%

 

                For the three months ended March 31, 2005, operating income was $9.6 million compared, to $3.6 million for the three months ended March 31, 2004.   The increase included the results of the Rangeland system which was acquired in the second quarter of 2004.  In addition, increased market share for pipeline shipments of crude oil to Billings, Montana and increased demand by the Salt Lake City, Utah, refineries, helped drive higher pipeline volumes on the U.S. Rocky Mountain systems other than Frontier pipeline.  Frontier pipeline volumes in 2005 were affected by a shortage of synthetic crude oil supply caused by a fire at a Suncor Energy, Inc. facility in December 2004. Shippers have now replaced these volumes with other types of crude oil and volumes are expected to return to normal levels in the second quarter of this year.

 

24



 

Statement of Income—Discussion and Analysis

 

 

 

Three months ended March 31,

 

 

 

 

 

Revenues

 

2005

 

2004

 

Change

 

Percent

 

 

 

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Pipeline transportation revenue

 

$

28,037

 

$

24,727

 

$

3,310

 

13

%

Storage and distribution revenue

 

10,322

 

10,123

 

199

 

2

%

Pipeline buy/sell transportation revenue

 

9,106

 

 

9,106

 

 

Crude oil sales, net of purchases:

 

 

 

 

 

 

 

 

 

Crude oil sales

 

116,173

 

85,927

 

30,246

 

35

%

Crude oil purchases

 

(114,391

)

(81,115

)

33,276

 

41

%

Crude oil sales, net of purchases

 

1,782

 

4,812

 

(3,030

)

-63

%

 

 

 

 

 

 

 

 

 

 

Net revenue

 

$

49,247

 

$

39,662

 

$

9,585

 

24

%

 

                Increased pipeline transportation revenues were realized by both our West Coast and U.S. Rocky Mountain pipelines. Higher volumes and increased tariff rates increased West Coast revenues. Volumes on the U.S. Rocky Mountain pipelines were higher due to increased demand by refineries in Billings, Montana, Casper, Wyoming and Salt Lake City, Utah area refineries.

 

                Storage and distribution revenues on the Pacific Terminals storage and distribution system were marginally higher compared to the same period in 2004 due to an increase in storage rates per barrel.

 

                Pipeline buy/sell transportation revenues of $9.1 million reflect the revenues of the Rangeland system, which was acquired on May 11, 2004.

 

                The decrease in net crude oil sales for the three months ended March 31, 2005 was primarily the result of lower margin blending activities in our West Coast operations, particularly due to competitive pricing pressures as a result of cheaper foreign crude entering the West Coast markets. Higher oil prices increased gross sales and purchases values. We consider this gathering and blending activity to be complementary to our pipeline transportation operations.

 

 

 

Three Months ended March  31,

 

 

 

 

 

Expenses

 

2005

 

2004

 

Change

 

Percent

 

 

 

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses

 

$

21,754

 

$

18,917

 

$

2,837

 

15

%

Line 63 oil release costs

 

2,000

 

 

2,000

 

 

General and administrative expense

 

5,172

 

3,854

 

1,318

 

34

%

Transaction costs

 

1,807

 

 

1,807

 

 

Accelerated long-term incentive plan compensation expense

 

3,115

 

 

3,115

 

 

Depreciation and amortization

 

6,529

 

5,242

 

1,287

 

25

%

 

 

$

40,377

 

$

28,013

 

$

12,364

 

44

%

 

                The increase in operating expense was related primarily to the acquisition of the Rangeland system on May 11, 2004.  Operating expenses in the West Coast were also higher as a result of unscheduled repairs and maintenance and pipeline relocation expenses on Line 2000 and Line 63 resulting from earth movements and creek washouts caused by recent heavy rains.

 

               The Line 63 oil release costs are discussed in “Recent Developments” above.

 

                The increase in general and administrative expense was associated with the integration of the Rangeland acquisition, certain expensed costs for the Pier 400 project and costs for compliance with the Sarbanes-Oxley Act.  These items were not applicable in the corresponding period of 2004.

 

                Transaction costs are discussed in “Recent Developments” above.

 

                On March 3, 2005, in connection with the change in control of the General Partner, all restricted units outstanding under the Long-term Incentive Plan immediately vested.  For the three months ended March 31, 2005, we recognized $3.1 million in compensation expense as a result.

 

25



 

                The increase in depreciation and amortization includes $1.5 million for depreciation on the Rangeland system.  These increases were partly offset by lower depreciation on other assets reflecting assets that have now been fully depreciated.

 

 

 

Three Months ended March 31,

 

 

 

 

 

Other Income and Expense

 

2005

 

2004

 

Change

 

Percent

 

 

 

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

Share of net income of Frontier

 

$

357

 

$

393

 

$

(36

)

-9

%

 

 

 

 

 

 

 

 

 

 

Interest expense

 

$

5,598

 

$

4,126

 

$

1,472

 

35

%

 

 

 

 

 

 

 

 

 

 

Other income

 

$

353

 

$

161

 

$

192

 

119

%

 

 

 

 

 

 

 

 

 

 

Income tax expense

 

$

561

 

$

 

$

561

 

 

 

                The decrease in our share of Frontier’s net income was mainly attributable to decreased pipeline volumes as a result of a shortage of synthetic crude supply caused by a fire at a Suncor Energy, Inc. facility in December 2004. Shippers have now replaced these volumes with other types of crude oil and volumes are expected to return to normal levels in the second quarter of the year.

 

                The increase in interest expense was due to borrowings incurred to partially fund the acquisition of the Rangeland system. Our weighted average borrowings during the three months ended March 31, 2005 were $358 million compared to $304 million in the corresponding period in 2004. In addition, floating interest rates were higher in 2005, at a weighted average interest rate of 6.3% for the period ended March 31, 2005 compared to a weighted average interest rate of 5.5% for the corresponding period in 2004.

 

                Other income of $0.4 million for the period ended March 31, 2005 was $0.2 million greater than the corresponding period in 2004 due to increased interest income and other items.

 

                The income tax expense for the three months ended March 31, 2005 relates to the income of the Rangeland system acquired in the second quarter of 2004.  Our Canadian subsidiaries are taxable entities, and certain kinds of repatriation of funds into the U.S. are subject to Canadian withholding tax.  Additionally, we recorded deferred tax liabilities in connection with the purchase of our Canadian subsidiaries, which we recover periodically in earnings.

 

Liquidity and Capital Resources

 

                We believe that cash generated from operations, together with our cash balance and our unutilized borrowing capacity, will be sufficient to meet our planned distributions, our working capital requirements, our remaining costs for the Line 63 oil release remediation and related costs, and our anticipated sustaining capital expenditures in the next three years.  We expect to extend or replace our revolving credit facilities, which mature in mid-2007.

 

                We intend to finance our future acquisitions and development projects, including our Pier 400 project, with issuances of debt and equity securities. We expect to maintain a debt to total capitalization ratio of approximately 50% over time.

 

                We have filed an application with the CPUC to sell surplus Pacific Terminals properties, which we believe are worth approximately $10 million.

 

                Our ability to satisfy our debt service obligations, fund planned capital expenditures, make acquisitions, develop projects and pay distributions to our unitholders will depend upon our future operating performance. Our operating performance is primarily dependent on the volume of crude oil transported through our pipelines and the capacity leased in our storage tanks as described in “Overview” above. Our operating performance is also affected by prevailing economic conditions in the crude oil industry and financial, business and other factors, some of which are beyond our control, which could significantly impact future results.

 

26



 

Operating, Investing and Financing Activities

 

 

 

Three Months Ended March 31,

 

 

 

 

 

2005

 

2004

 

Change

 

 

 

(In thousands)

 

 

 

(unaudited)

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

15,932

 

$

13,182

 

$

2,750

 

Net cash used in investing activities

 

(4,260

)

(12,333

)

8,073

 

Net cash provided by (used in) financing activities

 

(12,958

)

31,284

 

(44,242

)

 

                Net cash provided by operating activities

 

                The increase in the net cash from operating activities of $2.8 million, or 21%, was the result of the Rangeland system’s contribution to operating income, together with a decrease in cash used for working capital, partially offset by the cash portion of the accelerated vesting of units under the Long-term Incentive Plan and transaction costs.

 

                Net cash from operating activities for the three months ended March 31, 2005 was increased by approximately $4.5 million by working capital changes.  Increases in accounts payable and other accrued liabilities and accrued crude oil purchases more than offset an increase in crude oil inventory and crude oil sales receivables.  There was a significant increase in our inventory of crude oil for PMT, reflecting the deferral of a sale due to the downtime on Line 63 caused by the oil release and due to the timing of other sales.  The deferred delivery was made in April 2005 and other sales are occurring in the second quarter to reduce the inventory to a more normal level.  The sales pricing was either fixed or inventory balances were hedged at the end of March to eliminate any significant price risk.

 

                Net cash used in investing activities

 

                Capital expenditures were $4.4 million in the first quarter of 2005, of which $0.2 million related to sustaining capital projects, $2.3 million related to transition projects, $1.2 million related to expansion and $0.7 million was for our continued development of the Pier 400 Project. Capital expenditures for the three months ended March 31, 2004 were $2.4 million of which $0.5 million related to sustaining capital projects, $0.1 million related to the transition of the Pacific Terminals storage and distribution system, and $1.8 million related to expansion.  The 2004 period also includes $9.9 million related to a deposit paid and acquisition costs incurred for the Rangeland system and MAPL assets.

 

                Net cash provided by and used in financing activities

 

                Distributions of $15.1 million were made to the limited partners and the General Partner during the period ended March 31, 2005.  Additionally, TAC and LBP contributed $2.4 million to reimburse us for certain costs incurred in connection with the LB Acquisition. The amount of cash provided by financing activities in 2004, $31.3 million, includes net proceeds of $116.7 million from an equity offering completed on March 30, 2004, which was used to fund a portion of the acquisition of the Rangeland system, net repayment of $73.0 million under our revolving credit facility, and $12.4 million in distributions to the limited and general partner interests.

 

Capital Requirements

 

                Generally, our crude oil transportation and storage operations require investment to upgrade or enhance existing operations and to meet environmental and operational regulations. Our capital requirements consist primarily of:

 

sustaining capital expenditures to replace partially or fully depreciated assets in order to maintain the existing operating capacity or efficiency of our assets and extend their useful lives;

 

 

transitional capital expenditures to integrate acquired assets into our existing operations; and

 

 

expansion capital expenditures to expand or increase the efficiency of the existing operating capacity of our assets, whether through construction or acquisition, such as placing new storage tanks in service to increase our storage capabilities and revenue, and adding new pump stations or pipeline connections to increase our transportation throughput and revenue.

 

27



 

                We have forecasted total capital expenditures for our existing operations of $34.3 million for the remainder of 2005, including $3.1 million for the Pier 400 Project, $20.2 million for expansion projects, $7.7 million relating to the transition of the Rangeland system, $1.4 million for other transition capital projects, and $1.9 million for sustaining capital projects.

 

                Pier 400

 

                In February 2004, we completed an initial feasibility study for the development of a deepwater petroleum import terminal at Pier 400 and Terminal Island in the Port of Los Angeles (“POLA”) to handle marine receipts of crude oil and refinery feedstocks. We are developing the Pier 400 terminal to participate in the marine import business, which is growing as a result of a decline in imports from Alaska and the local production decline.  The Pacific Terminals storage and distribution assets also benefit by the increase in the marine import business.

 

We initiated the environmental review and permitting for the Pier 400 project in June 2004 and expect to have the permits necessary for construction to begin by the second quarter of 2006.  We entered into a project development agreement with two subsidiaries of Valero Energy Corporation (“Valero”) that defines the facilities that we are to construct in the POLA.  We and Valero have also signed a terminaling services agreement with a 30-year, 50,000 bpd volume commitment from Valero to support the terminal.  These agreements are subject to the satisfaction of various conditions.

 

                If the Pier 400 terminal receives the necessary governmental approvals and is successfully developed, a deepwater berth, high capacity transfer infrastructure and storage tanks will be constructed at Pier 400 and Terminal Island in the POLA, and a pipeline distribution system will be constructed to connect the terminal’s storage tanks to Valero’s Wilmington refinery and to our customers’ facilities in the Los Angeles Basin through our Pacific Terminals storage and distribution system. We would construct the transfer infrastructure, including a large diameter pipeline system for receiving bulk petroleum liquids from marine vessels, and the storage tanks.

 

                Final construction of the Pier 400 project is subject to the completion of a land lease agreement with the POLA, receipt of environmental and other approval, securing additional customer commitments, updating engineering and project cost estimates, ongoing feasibility evaluation, and financing.  A final decision to proceed is expected to be made in the first quarter of 2006. We expect construction of the Pier 400 terminal to be completed and placed in service in 2007.

 

                We have capitalized approximately $11.2 million on the Pier 400 project through March 31, 2005, including $0.7 million for the three months ended March 31, 2005.  These expenditures include $6.3 million for emission reduction credits, an asset that is re-saleable if the project does not proceed.  We anticipate funding pre-construction costs through early-2006 from our revolving credit facility.  Construction of the Pier 400 terminal is expected to be financed through a combination of debt and proceeds from the issuance of additional partnership units, including common units.

 

Debt Obligations

 

                At March 31, 2005, our debt obligations include: (i) $52.0 million on our senior secured U.S. revolving credit facility, (ii) Cdn$65.0 million (U.S.$53.7 million) on our senior secured Canadian revolving credit facility, (iii) $246.9 million on our 71/8% Senior Notes, due June 2014, and (iv) Cdn$4.5 million (U.S.$3.7 million) payable to the seller of the MAPL assets. For further discussion of these debt obligations see “Note 4—Long-term Debt” to the accompanying condensed consolidated financial statements.

 

                As of March 31, 2005, $87 million of undrawn credit was available under the senior secured U.S. revolving credit facility and  Cdn$31 million of undrawn credit was available under the senior secured Canadian revolving credit facility.  With the consent of the administrative agent under the U.S. revolving credit facility, we can increase credit availability under the U.S. credit facility by up to an additional $62 million, based upon pro-forma EBITDA from future acquisitions.

 

Off-Balance Sheet Arrangements

 

                The Partnership has no off-balance sheet arrangements.

 

Accounting Pronouncements

 

                In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 123 (revised December 2004), Share-Based Payment (SFAS 123R).  This Statement is a revision of SFAS No. 123.  SFAS 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services.  SFAS 123R is effective for the Partnership as of the beginning of the first annual reporting period that begins after June 15, 2005.  The Partnership has not yet determined the impact of the adoption of SFAS 123R on the Partnership’s consolidated financial statements.

 

28



 

                On March 30, 2005 the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), to clarify the term conditional asset retirement obligation as that term is used in FASB Statement No. 143, Accounting for Asset Retirement Obligations. The Interpretation also clarifies when an entity has sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for the Partnership no later than the end of fiscal years ending after December 15, 2005.  The Partnership is in the process of determining the impact of FIN 47 on its financial statements.

 

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

 

                Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are interest rate risk and crude oil price risk. Debt we incur under our credit facilities bears variable interest at either the applicable base or prime rate, a rate based on LIBOR or a rate based on Canadian Bankers’ Acceptances. We have used and will continue to use from time to time derivative instruments to hedge our exposure to variable interest rates.  In addition, we have entered into swap agreements to convert a portion of our fixed rate Senior Notes into floating rate debt based on LIBOR.

 

                We use, on a limited basis, certain derivative instruments (principally futures and options) to hedge our exposure to market price volatility related to our inventory or future sales of crude oil. We do not enter into speculative derivative activities of any kind. The fair market values of derivative instruments are included in “Other Assets, net” in the accompanying consolidated balance sheets. In our PMT operations we purchase crude oil for subsequent blending, transportation and resale primarily in the Los Angeles Basin. Changes in the fair value of our derivative instruments related to crude oil inventory are recognized in net income. For the three months ended March 31, 2005 and 2004, “crude oil sales, net of purchases” were net of $1.0 million and $0.2 million in losses, respectively, reflecting changes in the fair value of PMT’s derivative instruments for its marketing activities. Losses on derivatives were generally offset by gains in physical crude oil inventory positions. In addition, changes in the fair value of our derivative instruments related to the future sale of crude oil that qualify as hedges for accounting purposes are deferred and reflected in “accumulated other comprehensive income,” a component of partners’ capital, until the related revenue is recognized in the consolidated statements of income. As of March 31, 2005, $1.3 million relating to the changes in the fair value of derivative instruments was included in “accumulated other comprehensive income.”

 

                In connection with the issuance of the Senior Notes, we entered into interest rate swap agreements with an aggregate notional principal amount of $80.0 million to receive interest at a fixed rate of 71/8% and to pay interest at an average variable rate of six month LIBOR plus 1.6681% (set in advance or in arrears depending on the swap transaction). The interest rate swaps mature June 15, 2014 and are callable at the same dates and terms as the Senior Notes. We designated these swaps as a hedge of the change in the Senior Notes fair value attributable to changes in the six month LIBOR interest rate. Changes in fair values of the interest rate swaps are recorded into earnings each period. Similarly, changes in the fair value of the underlying $80.0 million of Senior Notes, which are expected to be offsetting to changes in the fair value of the interest swaps, are recorded into earnings each period.  At March 31, 2005 we recorded an increase of $1.1 million in the fair value of interest rate swaps with an equal offsetting entry to the $80.0 million of Senior Notes. As of March 31, 2005, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be recognized.

 

                We are subject to risks resulting from interest rate fluctuations as the interest cost on our credit facilities and the $80 million interest swap on the Senior Notes are based on variable rates. If the LIBOR or Canadian Bankers’ Acceptance discount rates were to increase 1.0% for the remainder of 2005 as compared to the rate at December 31, 2004, our interest expense for the remainder of 2005 would increase $1.4 million based on our outstanding debt at March 31, 2005.

 

Fair Value of Financial Instruments

 

                The carrying amount and fair values of financial instruments are as follows:

 

 

 

March 31,

 

December 31,

 

 

 

2005

 

2004

 

 

 

Carrying

 

Fair

 

Carrying

 

Fair

 

 

 

Value

 

Value

 

Value

 

Value

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

Crude oil hedging futures

 

$

1,410

 

$

1,410

 

$

400

 

$

400

 

Fair value interest rate swaps

 

1,063

 

1,063

 

2,693

 

2,693

 

Long-term debt

 

356,369

 

366,020

 

357,163

 

373,265

 

 

As of March 31, 2005 and December 31, 2004, the carrying amounts of items comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. The carrying amounts of the revolving credit facilities

 

29



 

approximate fair value primarily because the interest rates fluctuate with prevailing market rates.  The interest rate on the Senior Notes is fixed and the fair value is determined from a broker’s price quote at March 31, 2005 and December 31, 2004.

                The carrying amount of derivative financial instruments represents the fair value as these instruments are recorded on the balance sheet at their fair value under SFAS 133. The Partnership’s fair values of crude oil hedging futures are based on Reuters quoted market prices on the NYMEX.  Interest rate swaps’ fair values are based on the prevailing market price at which the positions could be liquidated.

 

ITEM 4. Controls and Procedures

 

                                                Disclosure Controls and Procedures

 

                We have established disclosure controls and procedures to ensure that material information relating to the Partnership, including its consolidated subsidiaries, is made known to the officers who certify the Partnership’s financial reports and to other members of senior management and the Board of Directors.  In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

 

                Based on their evaluation as of March 31, 2005, the principal executive officer and principal financial officer of the Partnership have concluded that the Partnership’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”) are effective to ensure that the information required to be disclosed by the Partnership in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

 

                                                Internal Control Over Financial Reporting

 

                There has not been any change in our internal control over financial reporting that occurred during our quarterly period ended March 31, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

30



 

PART II. OTHER INFORMATION

 

ITEM 1. Legal Proceedings

 

                See discussion of legal proceedings in “Note 8—Contingencies” in the accompanying condensed consolidated financial statements.

 

ITEM 6. Exhibits

 

                The following documents are filed as exhibits to this quarterly filing:

 

Exhibit Number

 

Description

 

 

 

* Exhibit 31.1

 

Certification of Principal Executive Officer of Pacific Energy Management LLC, General Partner of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., as required by Rule 13a-14(a) of the Securities Exchange Act of 1934

* Exhibit 31.2

 

Certification of Principal Financial Officer of Pacific Energy Management LLC, General Partner of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., as required by Rule 13a-14(a) of the Securities Exchange Act of 1934

† Exhibit 32.1

 

Certification of Chief Executive Officer of Pacific Energy Management LLC, General Partner of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., pursuant to 18 U.S.C. §1350

† Exhibit 32.2

 

Certification of Chief Financial Officer of Pacific Energy Management LLC, General Partner of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., pursuant to 18 U.S.C. §1350


*                                         Filed herewith.

 

                                          Not considered to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

 

31



 

SIGNATURES

 

                Pursuant to the requirements of the Securities Exchange Act of 1934, the Partnership has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

PACIFIC ENERGY PARTNERS, L.P.

 

By: 

 

PACIFIC ENERGY GP, LP, its General Partner

 

By: 

PACIFIC ENERGY MANAGEMENT LLC, its General Partner

 

 

 

 

 

 

By: 

/S/ IRVIN TOOLE, JR.

 

 

 

Irvin Toole, Jr.

 

 

 

President, Chief Executive Officer

 

 

 

and Director

 

 

 

(Principal Executive Officer)

 

 

 

May 3, 2005

 

 

 

 

 

 

By: 

/S/ GERALD A. TYWONIUK

 

 

 

Gerald A. Tywoniuk

 

 

 

Senior Vice President, Chief Financial

 

 

 

Officer and Treasurer

 

 

 

(Principal Financial and Accounting Officer)

 

 

 

May 3, 2005

 

32



 

EXHIBIT INDEX

 

Exhibit Number

 

Description

 

 

 

* Exhibit 31.1

 

Certification of Principal Executive Officer of Pacific Energy Management LLC, General Partner of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., as required by Rule 13a-14(a) of the Securities Exchange Act of 1934

* Exhibit 31.2

 

Certification of Principal Financial Officer of Pacific Energy Management LLC, General Partner of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., as required by Rule 13a-14(a) of the Securities Exchange Act of 1934

† Exhibit 32.1

 

Certification of Chief Executive Officer of Pacific Energy Management LLC, General Partner of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., pursuant to 18 U.S.C. §1350

† Exhibit 32.2

 

Certification of Chief Financial Officer of Pacific Energy Management LLC, General Partner of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., pursuant to 18 U.S.C. §1350


*                                         Filed herewith.

 

                                          Not considered to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

 

33