Edgar Filing: PLAINS ALL AMERICAN PIPELINE LP

Form 8-K

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of

the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported)—July 29, 2003

Plains All American Pipeline, L.P.

(Name of Registrant as specified in its charter)

DELAWARE	0-9808	76-0582150
(State or other jurisdiction	(Commission File Number)	(I.R.S. Employer
of incorporation or organization)		Identification No.)

333 Clay Street, Suite 1600

Houston, Texas 77002

(713) 646-4100

(Address, including zip code, and telephone number,

including area code, of Registrants principal executive offices)

N/A

(Former name or former address, if changed since last report.)

Item 7. Financial Statements and Exhibits

(c) Exhibit 99.1—Press Release dated July 29, 2003

Item 9 and 12. Regulation FD Disclosure; Results of Operations and Financial Condition

Plains All American Pipeline, L.P. (the “Partnership”) today issued a press release reporting its second quarter results. The Partnership is furnishing the press release, attached as Exhibit 99.1, pursuant to Item 9 and Item 12 of Form 8-K. The Partnership is also furnishing pursuant to Item 9 its projections of certain operating and financial results for the third and fourth quarter of 2003 and preliminary guidance for certain aspects of financial performance for 2004. In accordance with General Instructions B.2. and B.6. of Form 8-K, the information presented herein under Item 9 or Item 12, including Exhibit 99.1, shall not be deemed “filed” for purposes of Section 18 of the Securities Act of 1934, as amended, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such a filing.

Disclosure of Third and Fourth Quarter 2003 Forecasts; Update of Year 2003 Guidance

The following table reflects our actual results for the first six months of 2003 and management’s current range of guidance for operating and financial results for the third and fourth quarter of 2003. Management’s guidance is based on assumptions and estimates that management believes are reasonable based on its assessment of historical trends and business cycles and currently available information; however, management’s assumptions and our future performance are both subject to a wide range of business risks and uncertainties, so we cannot assure you that actual performance can or will fall within these guidance ranges. Please refer to the information under the caption “Forward-Looking Statements and Associated Risks” below. These risks and uncertainties could cause our actual results to differ materially from those in the following table. The operating and financial guidance provided below is given as of the date hereof, based on information known to us as of July 28, 2003. EBIT and EBITDA are non-GAAP financial measures, and are reconciled in the table below to Net Income. EBIT and EBITDA are impractical to reconcile to cash flows from operating activities for forecasted periods, but are reconciled for historical periods in the accompanying footnotes. Net Income and cash flows from operating activities are the most directly comparable GAAP measures for EBIT and EBITDA. The Partnership encourages you to visit Plains All American’s website at www.paalp.com, in particular the section entitled “Non-GAAP Reconciliation” that presents a historical reconciliation of certain non-GAAP financial measures that are commonly used, including EBIT and EBITDA. EBIT and EBITDA are presented because management believes they provide additional information with respect to both the performance of our fundamental business activities, as well as our ability to meet our future debt service, capital expenditures, and working capital requirements. Management also believes that debt holders commonly use EBITDA to analyze company performance.

Operating and Financial Guidance

(in thousands, except per unit data)

	YTD June 30, 2003 Actuals		Quarter Ended September 30, 2003				Quarter Ended December 31, 2003				Year Ended December 31, 2003
	YTD June 30, 2003 Actuals		Low		High		Low		High		Low		High
Gross Margin (excl deprec.):
Pipeline Operations	$	53,454	$	28,000	$	29,000	$	27,700	$	29,000	$	109,154	$	111,454
Gathering, Marketing, Terminalling & Storage		59,403		25,400		27,000		26,700		29,000		111,503		115,403

Total Gross Margin (excl depreciation)	$	112,857	$	53,400	$	56,000	$	54,400	$	58,000	$	220,657	$	226,857

G&A / Other Expenses		25,246		12,400		12,000		12,400		12,000		50,046		49,246


EBITDA	$	87,611	$	41,000	$	44,000	$	42,000	$	46,000	$	170,611	$	177,611

Depreciation & Amort.—Oper.		18,981		10,200		10,150		10,300		10,250		39,481		39,381
Depreciation & Amort.—G & A		3,195		1,700		1,650		1,700		1,650		6,595		6,495

EBIT	$	65,435	$	29,100	$	32,200	$	30,000	$	34,100	$	124,535	$	131,735

Interest Expense		17,686		9,200		9,000		9,400		9,200		36,286		35,886

Net Income	$	47,749	$	19,900	$	23,200	$	20,600	$	24,900	$	88,249	$	95,849

Net Income to Limited Partners	$	44,566	$	18,261	$	21,495	$	18,947	$	23,161	$	81,774	$	89,222
Weighted Avg Units Outstanding		51,200		52,223		52,223		52,223		52,223		51,882		51,882
Earnings Per Unit	$	0.87	$	0.35	$	0.41	$	0.36	$	0.44	$	1.58	$	1.72

Notes and Significant Assumptions:

EBITDA means Earnings Before Interest, Taxes, Depreciation, and Amortization. EBIT means EBITDA less Depreciation and Amortization. Gross margin excludes depreciation.

Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133). The forecast presented above does not include assumptions or projections with respect to potential gains or losses related to SFAS 133, as there is no accurate way to forecast these potential gains or losses. The potential gains or losses related to SFAS 133 could materially change reported net income (related primarily to non-cash, mark-to-market gains or losses). The net gain/loss due to SFAS 133 was a $0.2 million gain for the second quarter and a $1.1 million gain for the six months ending

June 30, 2003. Guidance for the full year 2003 includes only the $1.1 million gain recorded for the six months ending June 30, 2003.

Reconciliation of EBIT and EBITDA to cash flows from operating activities. The following table reconciles historical EBIT and EBITDA to historical cash flows from operating activities as of June 30, 2003:

Cash flow from operating activities reconciliation

(Historical)

	2003 YTD as of 06/30/03
Net cash provided by (used in) operating activities	176,088
Net change in assets and liabilities, net of acquisitions	(107,218	)
Other items not affecting cash flows from operating activities:
Allowance for doubtful accounts	(100	)
Change in derivative fair value	1,155
Interest expense	17,686

EBITDA	87,611
Depreciation and amortization—operations	(18,981	)
Depreciation and amortization—general and administrative	(3,195	)

EBIT	65,435

Pipeline Gross Margin. Pipeline volume and tariff estimates are based on historical operating performance and our outlook for future performance. Actual results could vary materially depending on volumes that are shipped. Average pipeline volumes are estimated to be approximately 920,000 barrels per day for the third quarter of 2003 (compared to

average 2Q03 volumes of 840,000). The overall increase in pipeline volumes is primarily associated with anticipated contributions from (1) acquisitions completed in the second quarter of 2003, (2) completion of an expansion of our Permian Basin System and (3) recovery of movements on our Milk River System (one of our lowest per barrel tariff pipelines), which decreased during the second quarter due to refinery turnarounds. Outer Continental Shelf (OCS) volumes (our highest per barrel tariff volumes) are estimated to make up approximately 6% of total daily volumes, or approximately 60,000 barrels per day (compared to average 2Q03 volumes of 63,000 barrels per day). Volumes on Basin Pipeline for the third quarter are forecast at approximately 270,000 barrels per day (compared to average 2Q03 volumes of 280,000 barrels per day). Average pipeline volumes are estimated to be approximately 925,000 barrels per day for the fourth quarter of 2003, with OCS volumes estimated to make up approximately 6% of these volumes, or approximately 60,000 barrels per day. Volumes on Basin Pipeline for the fourth quarter are forecast at approximately 270,000 barrels per day. Revenues are forecast using these volume assumptions, current tariffs and estimates of operating expenses, each of which management believes are reasonable. A 5,000 barrel per day variance in OCS volumes would have an approximate $0.8 million effect on gross margin for each quarter and an approximate $3.1 million effect on an annualized basis. An average 25,000 barrel per day variance in the Basin Pipeline System, which is equivalent to an approximate 9% volume variance on that pipeline system, would have an approximate $0.9 million effect on gross margin for each quarter and an approximate $3.6 million effect on an annualized basis.

Gathering, Marketing, Terminalling and Storage Gross Margin. Forecast volumes for Gathering & Marketing are approximately 520,000 barrels per day (approximately 440,000 barrels per day of lease gathered barrels and 80,000 barrels per day of bulk purchases) for the third quarter of 2003 (compared to average 2Q03 volumes of 513,000 barrels per day including 425,000 barrels per day of lease gathered barrels). Forecast volumes for Gathering & Marketing are approximately 525,000 barrels per day (approximately 445,000 barrels per day of lease gathered barrels) for the fourth quarter of 2003. Gross margin excluding depreciation is forecast using these volume assumptions and estimates of unit margins and operating expenses, each of which management believes are reasonable, based on current and anticipated market conditions. A 5,000 barrel per day variance in lease gathering volumes would have an approximate $0.2 million effect on gross margin for each quarter and an approximate $0.9 million effect on an annualized basis. A variance in bulk purchases would have a substantially lower effect on gross margin as these volumes carry lower margins than our lease gathering business.

General and Administrative Expense. G&A expense is forecast to be between $12.0 million and $12.4 million for the third quarter of 2003 and between $12.0 million and $12.4 million for the fourth quarter of 2003. This is based on current and forecast staffing levels and administrative requirements.

Interest Expense. Third quarter interest expense is forecast to be between $9.0 million and $9.2 million assuming an average debt balance of approximately $565 million and an average interest rate of approximately 6.4%, including our fixed rate debt, current interest rate hedges

on floating rate debt and commitment fees. Fourth quarter interest expense is forecast to be between $9.2 million and $9.4 million assuming an average debt balance of approximately $585 million and an average interest rate of approximately 6.4%, including our fixed rate debt, current interest rate hedges on floating rate debt and commitment fees. The forecast is based on estimated cash flow, current distribution rates, planned capital projects and line-fill purchases, planned sales of surplus equipment, forecast timing of collections and payments, and forecast levels of inventory and other working capital sources and uses, each of which management believes is reasonable.

Depreciation & Amortization. Depreciation and amortization is forecast based on our existing depreciable assets and forecast capital expenditures. Depreciation is computed using the straight-line method over estimated useful lives, which range from 5 years for office property and equipment to 40 years for certain crude oil terminals and facilities. Crude oil pipelines are depreciated over 30 years.

Units Outstanding. Our forecast is based on the 52,222,748 units currently outstanding. There are no dilutive securities or options issued or outstanding.

10.

Net Income per Unit. Net income per limited partner unit (basic and diluted) is calculated by dividing the net income allocated to limited partners by the weighted average units outstanding during the period. As noted below, the net income allocated to limited partners is impacted by the income allocated to the general partner and the amount of the incentive distribution paid to the general partner.

11.

Potential Effect of Changes in Capital Structure. Interest expense, net income and net income per unit estimates are based on our capital structure as of July 28, 2003. In keeping with our established financial growth strategy of financing acquisitions using a balance of equity and debt, we anticipate that we will issue equity in order to reduce a portion of any debt associated with any future acquisitions. Depending on the terms, any such equity issuance may dilute the net income per unit forecasts included in the foregoing table. In addition, we intend to monitor debt capital market conditions and may in the future issue additional senior unsecured notes, which may bear interest costs greater than the amount included in the foregoing guidance. Accordingly, the foregoing financial results and per unit estimates will change, depending on the timing and the terms of any debt or equity we actually issue. Additionally, financing transactions may result in our retiring some of our existing debt instruments, which could result in a charge to earnings of any unamortized debt issuance costs. We have not included any such potential charge in our forecast.

12.

Net Income to Limited Partners. The amount of income allocated to our limited partnership interests is 98% of the total partnership income after deducting the amount of the general partner’s incentive distribution. Based on a $2.20 annual distribution level and the current units outstanding, our general partner’s distribution is forecast to be approximately $7.4 million annually, of which $5.1 million is attributed to the incentive distribution rights. The amount of the incentive distribution changes based on the number of units outstanding and the level of the distribution on the units.

13.

Capital Expenditures. Expansion capital expenditures are forecast to be approximately $20.2 million for the second half of 2003. Maintenance capital expenditures are forecast to be approximately $4.2 million for the remainder of 2003, of which the majority is expected to be incurred in the third quarter.

14.

Potential Vesting under Long-Term Incentive Plan. We have not included in this table the effect of potential vesting of unit grants under our Long-Term Incentive Plan, which permits the grant of restricted units and unit options covering an aggregate of approximately 1.4 million units. Approximately 1.0 million restricted units (and no unit options) have been granted and are currently outstanding under the Plan. A restricted unit grant entitles the grantee to receive a common unit upon the vesting of the restricted unit. Subject to additional vesting requirements, restricted units may vest in the same proportion as the conversion of the partnership’s outstanding subordinated units into common units. Certain of the restricted unit grants contain additional vesting requirements tied to the partnership achieving targeted distribution thresholds, generally $2.10, $2.30 and $2.50 per unit, in equal proportions.

Under generally accepted accounting principles, we are required to recognize an expense for the vesting of the units when the financial tests for conversion of subordinated units and required distribution levels are met. The test associated with the conversion of subordinated units to common units is set forth in the partnership agreement and involves GAAP accounting concepts as well as complex and esoteric cash receipts and disbursement concepts that are indexed to the minimum annual distribution rate of $1.80 per limited partner unit.

Because of this complexity, it is difficult to forecast when the vesting of these restricted units will occur. However, at the current distribution level of $2.20 per unit, assuming the subordination conversion test is met, the costs associated with the vesting of up to approximately 825,000 units would be incurred or accrued in the fourth quarter of 2003 or the first half of 2004. At a distribution level of $2.30 to $2.49, the number of units would be approximately 913,000. At a distribution level at or above $2.50, the number of units would be approximately 1,000,000. Subject to providing employees holding a number of LTIP grants below a certain threshold the option to receive cash instead of units, which alternative is currently under consideration, we are currently planning to issue units to satisfy the first 975,000 restricted units vested and delivered (after any units withheld for taxes), and to purchase units in the open market to satisfy any vesting obligations in excess of that amount. Issuance of units would result in a non-cash compensation expense. Purchase of units would result in a cash charge to compensation expense. In addition, the “company match” portion of payroll taxes, plus the value of any units withheld for taxes, would result in a cash charge. The amount of the charge to expense will be determined by the unit price on the date vesting occurs multiplied by the number of units.

15.

Acquisitions. Although acquisitions comprise a key element of our growth strategy, these results and estimates do not include any assumptions or forecasts for any material acquisitions that may be made after the date hereof.

Preliminary Guidance for Year 2004

For 2004, we anticipate our EBITDA will range from $171 million to $178 million. This overall guidance is based on continued operating and financial performance of our existing assets under normalized market conditions, continuation of current shipments on the Basin Pipeline System and anticipated declines in shipments of OCS crude on our All American Pipeline system (assuming a 7% annual volume decline). The overall guidance also assumes the inclusion of recent acquisitions along with the successful integration and realization of cost savings and revenue synergies identified in our acquisition analysis. Based on this outlook and taking into account anticipated depreciation and amortization expense, we expect EBIT for 2004 will range from $123 million to $130 million. The potential effects of the long-term incentive plan (see paragraph 14 above) are not included in the guidance for 2004. EBIT and EBITDA are reconciled to net income using the midpoint of the applicable ranges as follows: EBITDA of $174.5 minus DD&A of $48 million results in EBIT of $126.5 million. EBIT less interest expense of $38.5 million equals net income of $88.0 million.

As noted in paragraph 11 above, our current capital structure may change as a result of issuing equity and from the possible issuance of senior unsecured notes. These financing transactions would affect net income. Additionally, the contemplated financing transactions may result in our retiring some of our existing debt instruments, which could result in a non-cash charge to earnings related to unamortized debt issuance costs. We have not included any such potential charge in our forecast.

Forward-Looking Statements And Associated Risks

All statements, other than statements of historical fact, included in this report are forward-looking statements, including, but not limited to, statements identified by the words “anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend” and “forecast” and similar expressions and statements regarding our business strategy, plans and objectives of our management for future operations. These statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions. Certain factors could cause actual results to differ materially from results anticipated in the forward-looking statements. These factors include, but are not limited to:

•

abrupt or severe production declines or production interruptions in outer continental shelf crude oil production located offshore California and transported on the All American Pipeline;

•

declines in volumes shipped on the Basin Pipeline and our other pipelines by third party shippers;

•

the availability of adequate supplies of and demand for crude oil in the areas in which we operate;

•

the effects of competition;

•

the success of our risk management activities;

•

the impact of crude oil price fluctuations;

•

the availability (or lack thereof) of acquisition or combination opportunities;

•

successful integration and future performance of acquired assets;

•

continued creditworthiness of, and performance by, our counterparties;

•

successful third-party drilling efforts in areas in which we operate pipelines or gather crude oil;

•

our levels of indebtedness and our ability to receive credit on satisfactory terms;

•

shortages or cost increases of power supplies, materials or labor;

•

weather interference with business operations or project construction;

•

the impact of current and future laws and governmental regulations;

•

the currency exchange rate of the Canadian dollar;

•

environmental liabilities that are not covered by an indemnity or insurance;

•

fluctuations in the debt and equity markets; and

•

general economic, market or business conditions.

We undertake no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in our filings with the Securities and Exchange Commission, which information is incorporated by reference herein.

SIGNATURES

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

Date: July 29, 2003	PLAINS ALL AMERICAN PIPELINE, L.P. By: Plains AAP, L. P., its general partner By: Plains All American GP LLC, its general partner

	By:	/s/ PHIL KRAMER
	Name: Phil Kramer Title: Executive Vice President and Chief Financial Officer

EXHIBIT INDEX

Exhibit

Number

Description

99.1

Press Release dated July 29, 2003