UNITED STATES
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)—November 4, 2009

 

Plains All American Pipeline, L.P.

(Exact name of registrant as specified in its charter)

 

DELAWARE

 

1-14569

 

76-0582150

(State or other jurisdiction of

 

(Commission File Number)

 

(IRS Employer Identification No.)

incorporation)

 

 

 

 

 

333 Clay Street, Suite 1600, Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

 

Registrant’s telephone number, including area code 713-646-4100

 

 

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

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

 

o

Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

 

o

Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

 

o

Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

 

o

Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

 



 

Item 9.01. Financial Statements and Exhibits

 

(d)              Exhibit 99.1 — Press Release dated November 4, 2009.

 

Item 2.02 and Item 7.01.  Results of Operations and Financial Condition; Regulation FD Disclosure

 

Plains All American Pipeline, L.P. (the “Partnership or Plains”) today issued a press release reporting its third-quarter 2009 results.  We are furnishing the press release, attached as Exhibit 99.1, pursuant to Item 2.02 and Item 7.01 of Form 8-K.  Pursuant to Item 7.01 we are providing updated detailed guidance for financial performance for the fourth quarter of calendar year 2009 with resulting performance for the full calendar year of 2009 (which supersedes guidance pertaining to 2009 contained in our Form 8-K furnished on August 5, 2009) and we are providing preliminary guidance for calendar year 2010.  In accordance with General Instruction B.2. of Form 8-K, the information presented herein under this Item 7.01 shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), nor shall it be deemed incorporated by reference in any filing under the Exchange Act or Securities Act of 1933, as amended, except as expressly set forth by specific reference in such a filing.

 

Update of Fourth Quarter 2009 Guidance; Disclosure of Full Year 2010 Preliminary Guidance

 

EBIT and EBITDA (each as defined below in Note 1 to the “Operating and Financial Guidance” table) are non-GAAP financial measures. Net income and cash flows from operating activities are the most directly comparable GAAP measures to EBIT and EBITDA. In Note 10 below, we reconcile net income to EBIT and EBITDA for the 2009 guidance periods presented. It is, however, impractical to reconcile EBIT and EBITDA to cash flows from operating activities for a forecasted period. We encourage you to visit our website at www.paalp.com (in particular the section entitled “Non-GAAP Reconciliation”), which presents an historical reconciliation of certain commonly used non-GAAP financial measures, including EBIT and EBITDA. We present EBIT and EBITDA because we believe they provide additional information with respect to both the performance of our fundamental business activities and our ability to meet our future debt service, capital expenditures and working capital requirements. We also believe that debt holders commonly use EBITDA to analyze partnership performance. In addition, we have highlighted the impact of our equity compensation plans, inventory valuation adjustments net of gains and losses from related derivative activities, gains and losses from other derivative activities, foreign currency revaluations and loss on senior notes on Segment Profit, EBITDA, Net Income and Net Income per Basic and Diluted Limited Partner Unit.

 

The following guidance for the three months and twelve months ending December 31, 2009, as well as the preliminary guidance for calendar year 2010, is based on assumptions and estimates that we believe are reasonable given our assessment of historical trends (modified for changes in market conditions), business cycles and other reasonably available information. Projections covering multi-quarter periods contemplate inter-period changes in future performance resulting from new expansion projects, seasonal operational changes (such as LPG sales) and acquisition synergies. Our assumptions and future performance, however, are both subject to a wide range of business risks and uncertainties, so we can provide no assurance that actual performance will fall within the guidance ranges. Please refer to information under the caption “Forward-Looking Statements and Associated Risks” below. These risks and uncertainties, as well as other unforeseeable 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 November 3, 2009. We undertake no obligation to publicly update or revise any forward-looking statements.

 

2



 

Plains All American Pipeline, L.P.

Operating and Financial Guidance

(in millions, except per unit data)

 

 

 

Actual

 

Guidance (1)

 

 

 

9 Months

 

3 Months Ending

 

12 Months Ending

 

 

 

Ended

 

December 31, 2009

 

December 31, 2009

 

 

 

9/30/2009

 

Low

 

High

 

Low

 

High

 

Segment Profit

 

 

 

 

 

 

 

 

 

 

 

Net revenues (including equity earnings from unconsolidated entities)

 

$

1,419

 

$

448

 

$

465

 

$

1,867

 

$

1,884

 

Field operating costs

 

(474

)

(163

)

(158

)

(637

)

(632

)

General and administrative expenses

 

(153

)

(57

)

(54

)

(210

)

(207

)

 

 

792

 

228

 

253

 

1,020

 

1,045

 

Depreciation and amortization expense

 

(173

)

(63

)

(61

)

(236

)

(234

)

Interest expense, net

 

(165

)

(61

)

(59

)

(226

)

(224

)

Income tax expense

 

(1

)

(2

)

(2

)

(3

)

(3

)

Other income (expense), net

 

17

 

(3

)

(3

)

14

 

14

 

Net Income

 

$

470

 

$

99

 

$

128

 

$

569

 

$

598

 

Less: Net income attributable to noncontrolling interest

 

(1

)

 

 

(1

)

(1

)

Net Income attributable to Plains

 

$

469

 

$

99

 

$

128

 

$

568

 

$

597

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income to Limited Partners

 

$

370

 

$

61

 

$

90

 

$

431

 

$

460

 

Basic Net Income Per Limited Partner Unit

 

 

 

 

 

 

 

 

 

 

 

Weighted Average Units Outstanding

 

128

 

136

 

136

 

130

 

130

 

Net Income Per Unit

 

$

2.84

 

$

0.45

 

$

0.66

 

$

3.26

 

$

3.48

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted Net Income Per Limited Partner Unit

 

 

 

 

 

 

 

 

 

 

 

Weighted Average Units Outstanding

 

129

 

137

 

137

 

131

 

131

 

Net Income Per Unit

 

$

2.82

 

$

0.45

 

$

0.65

 

$

3.23

 

$

3.46

 

 

 

 

 

 

 

 

 

 

 

 

 

EBIT

 

$

635

 

$

162

 

$

189

 

$

797

 

$

824

 

EBITDA

 

$

808

 

$

225

 

$

250

 

$

1,033

 

$

1,058

 

 

 

 

 

 

 

 

 

 

 

 

 

Selected Items Impacting Comparability

 

 

 

 

 

 

 

 

 

 

 

Equity compensation charge

 

$

(36

)

$

(11

)

$

(11

)

$

(47

)

$

(47

)

Inventory valuation adjustments net of gains and (losses) from related derivative activities

 

24

 

 

 

24

 

24

 

Gains (losses) from other derivative activities

 

54

 

 

 

54

 

54

 

Net gain on purchase of remaining 50% interest in PNGS

 

9

 

 

 

9

 

9

 

Loss on extinguishment of 7.125% notes

 

 

(4

)

(4

)

(4

)

(4

)

Net gain on foreign currency revaluation

 

12

 

 

 

12

 

12

 

 

 

$

 63

 

$

(15

)

$

(15

)

$

48

 

$

48

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Excluding Selected Items Impacting Comparability

 

 

 

 

 

 

 

 

 

 

 

Adjusted Segment Profit

 

 

 

 

 

 

 

 

 

 

 

Transportation

 

$

373

 

$

130

 

$

136

 

$

503

 

$

509

 

Facilities

 

161

 

59

 

63

 

220

 

224

 

Marketing

 

203

 

50

 

65

 

253

 

268

 

Other Income (Expense), net

 

8

 

1

 

1

 

9

 

9

 

Adjusted EBITDA

 

$

745

 

$

240

 

$

265

 

$

985

 

$

1,010

 

Adjusted Net Income

 

$

406

 

$

114

 

$

143

 

$

520

 

$

549

 

Adjusted Basic Net Income per Limited Partner Unit

 

$

2.35

 

$

0.56

 

$

0.77

 

$

2.90

 

$

3.12

 

Adjusted Diluted Net Income per Limited Partner Unit

 

$

2.33

 

$

0.56

 

$

0.76

 

$

2.88

 

$

3.10

 

 

 

 

 

 

 

 

 

 

 

 

 

 


(1)                    The projected average foreign exchange rate was based on actual rates for October 2009 and $1.08 CAD to $1 USD for the remainder of 2009. The rate as of November 3, 2009 was $1.07 CAD to $1 USD.

 

3



 

Notes and Significant Assumptions:

 

1.                                 Definitions.

 

EBIT

Earnings before interest and taxes

EBITDA

Earnings before interest, taxes and depreciation and amortization expense

Segment Profit

Net revenues (including equity earnings, as applicable) less field operating costs and segment general and administrative expenses

Bbls/d

Barrels per day

Bcf

Billion cubic feet

LTIP

Long-Term Incentive Plan

LPG

Liquefied petroleum gas and other natural gas-related petroleum products (primarily propane and butane)

FX

Foreign currency exchange

General partner (GP)

As the context requires, “general partner” refers to any or all of (i) PAA GP LLC, the owner of our 2% general partner interest, (ii) Plains AAP, L.P., the sole member of PAA GP LLC and owner of our incentive distribution rights and (iii) Plains All American GP LLC, the general partner of Plains AAP, L.P.

Class B units

Class B units of Plains AAP, L.P.

 

2.                                  Business Segments.  We manage our operations through three operating segments: (i) Transportation, (ii) Facilities and (iii) Marketing. The following is a brief explanation of the operating activities for each segment as well as key metrics.

 

a.               Transportation.   Our transportation segment operations generally consist of fee-based activities associated with transporting crude oil and refined products on pipelines, gathering systems, trucks and barges. We generate revenue through a combination of tariffs, third-party leases of pipeline capacity and transportation fees. We also include in this segment our equity earnings from our investment in the Butte and Frontier pipeline systems and Settoon Towing, in which we own non-controlling interests.

 

Pipeline volume estimates are based on historical trends, anticipated future operating performance and completion of internal growth projects. Volumes are influenced by maintenance schedules at refineries, production declines, weather and other natural disasters including hurricanes, changes in the quantity of inventory held in tanks, and other external factors beyond our control. Segment profit is forecast using the volume assumptions in the table below, priced at forecasted tariff rates, less estimated field operating costs and G&A expenses. Field operating costs do not include depreciation. Actual segment profit could vary materially depending on the level and mix of volumes transported or expenses incurred during the period.

 

The following table summarizes our total pipeline volumes and highlights major systems that are significant either in total volumes transported or in contribution to total transportation segment profit.

 

 

 

Actual

 

2009 Guidance

 

 

 

Nine Months

 

Three Months

 

Twelve Months

 

 

 

Ended

 

Ending

 

Ending

 

 

 

September 30,

 

December 31,

 

December 31,

 

Average Daily Volumes (000 Bbls/d)

 

 

 

 

 

 

 

All American

 

40

 

42

 

41

 

Basin

 

389

 

385

 

388

 

Capline

 

205

 

190

 

201

 

Line 63 / 2000

 

136

 

135

 

136

 

Salt Lake City Area Systems (1)

 

132

 

140

 

134

 

West Texas / New Mexico Area Systems (1)

 

375

 

365

 

372

 

Rainbow

 

184

 

185

 

184

 

Manito

 

62

 

65

 

63

 

Rangeland

 

54

 

50

 

53

 

Refined Products

 

96

 

100

 

97

 

Other

 

1,207

 

1,228

 

1,212

 

 

 

2,880

 

2,885

 

2,881

 

Trucking

 

84

 

100

 

88

 

 

 

2,964

 

2,985

 

2,969

 

Segment Profit per Barrel ($/Bbl)

 

 

 

 

 

 

 

Excluding Selected Items Impacting Comparability

 

$

0.46

 

$

0.48

(2)

$

0.47

(2)

 


(1)   The aggregate of multiple systems in the respective areas.

(2)   Mid-point of guidance.

 

4



 

b.              Facilities.  Our facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services for crude oil, refined products, LPG and natural gas, as well as LPG fractionation and isomerization services. We generate revenue through a combination of month-to-month and multi-year leases and processing arrangements.  On September 3, 2009, we acquired the remaining 50% indirect interest in PAA Natural Gas Storage, LLC. (“PNGS”).  As a result of the transaction, PAA now owns 100% of PNGS’s natural gas storage business and related operating entities, which is now accounted for on a consolidated basis beginning in September 2009.  PAA historically accounted for its 50% indirect interest in PNGS under the equity method.

 

Segment profit is forecast using the volume assumptions in the table below, priced at forecasted rates, less estimated field operating costs and G&A expenses. Field operating costs do not include depreciation.

 

 

 

Actual

 

2009 Guidance

 

 

 

Nine Months

 

Three Months

 

Twelve Months

 

 

 

Ended

 

Ending

 

Ending

 

 

 

September 30,

 

December 31,

 

December 31,

 

Operating Data

 

 

 

 

 

 

 

Crude oil, refined products and LPG storage (MMBbls/Mo.)

 

56

 

56

 

56

 

Natural Gas Storage (Bcf/Mo.)

 

21

 

40

 

26

 

LPG Processing (MBbl/d)

 

16

 

17

 

16

 

Facilities Activities Total (1)

 

 

 

 

 

 

 

Avg. Capacity (MMBbls/Mo.)

 

60

 

64

 

61

 

 

 

 

 

 

 

 

 

Segment Profit per Barrel ($/Bbl)

 

 

 

 

 

 

 

Excluding Selected Items Impacting Comparability

 

$

0.30

 

$

0.32

(2)

$

0.30

(2)

 


(1)        Calculated as the sum of: (i) crude oil, refined products and LPG storage capacity; (ii) natural gas storage capacity divided by 6 to account for the 6:1 mcf of gas to barrel of crude oil ratio; and (iii) LPG processing volumes multiplied by the number of days in the period and divided by the number of months in the period.

(2)        Mid-point of guidance.

 

c.               Marketing.  Our marketing segment operations generally consist of the following merchant activities:

 

·

the purchase of U.S. and Canadian crude oil at the wellhead and the bulk purchase of crude oil at pipeline and terminal facilities, as well as the purchase of foreign cargoes at their load port and various other locations in transit;

 

 

·

the storage of inventory during contango market conditions and the seasonal storage of LPG;

 

 

·

the purchase of refined products and LPG from producers, refiners and other marketers;

 

 

·

the resale or exchange of crude oil, refined products and LPG at various points along the distribution chain to refiners or other resellers to maximize profits; and

 

 

·

the transportation of crude oil, refined products and LPG on trucks, barges, railcars, pipelines and ocean-going vessels to our terminals and third-party terminals.

 

The level of profit in the marketing segment is influenced by overall market structure and the degree of volatility in the crude oil market as well as variable operating expenses. Forecasted operating results for the remainder of 2009 reflect the current market structure and seasonal, weather-related variations in LPG sales. Variations in weather, market structure or volatility could cause actual results to differ materially from forecasted results.

 

We forecast segment profit using the volume assumptions stated below, as well as estimates of unit margins, field operating costs, G&A expenses and carrying costs for contango inventory, based on current and anticipated market conditions.  Volumes are influenced by temporary market-driven storage and withdrawal of oil, maintenance schedules at refineries, production declines, weather, and other external factors beyond our control.  Field operating costs do not include depreciation. Realized unit margins for any given lease-gathered barrel could vary significantly based on a variety of factors including location, quality and contract structure.  Accordingly, the projected segment profit per barrel can vary significantly even if aggregate volumes are in line with the forecasted levels.

 

5



 

 

 

Actual

 

2009 Guidance

 

 

 

Nine Months

 

Three Months

 

Twelve Months

 

 

 

Ended

 

Ending

 

Ending

 

 

 

September 30,

 

December 31,

 

December 31,

 

Average Daily Volumes (MBbl/d)

 

 

 

 

 

 

 

Crude oil lease gathering purchases

 

619

 

600

 

614

 

LPG sales

 

88

 

150

 

104

 

Refined products sales

 

34

 

35

 

34

 

Waterborne foreign crude oil imported

 

54

 

60

 

56

 

 

 

795

 

845

 

808

 

 

 

 

 

 

 

 

 

Segment Profit per Barrel ($/Bbl)

 

 

 

 

 

 

 

Excluding Selected Items Impacting Comparability

 

$

0.93

 

$

0.74

(1)

$

0.88

(1)

 


(1)                                     Mid-point of guidance.

 

3.                                       Depreciation and Amortization.   We forecast depreciation and amortization based on our existing depreciable assets, forecasted capital expenditures and projected in-service dates.   Depreciation may vary during any one period due to gains and losses on intermittent sales of assets, asset retirement obligations, or asset impairments.

 

4.                                       Selected Items Impacting Comparability.   Our operating results are impacted by items that affect comparability between reporting periods, such as the equity compensation benefit or charge associated with our long-term incentive programs.  In addition, our actual results will reflect certain mark-to-market items such as gains and losses related to derivative activities, gains and losses from unrealized foreign currency transactions, and inventory valuation adjustments.  Our adjusted results exclude these selected items impacting comparability until such time as the underlying and offsetting physical transaction settles.  Although the economics of these transactions as a whole are embedded in our guidance presented here, our selected items impacting comparability for future periods do not reflect these items as there is no accurate way to forecast the timing and magnitude of their ultimate effect.  The magnitude of these items depends on market prices and exchange rates at a point in time.  Accordingly, our actual results could differ materially from our projections.

 

5.                                       Acquisitions and Other Capital Expenditures.   Although acquisitions constitute a key element of our growth strategy, the forecasted results and associated estimates do not include any forecasts for acquisitions to which we may commit after the date hereof. We forecast capital expenditures during calendar 2009 to be approximately $380 million for expansion projects with an additional $85 to $95 million for maintenance capital projects. During the first nine months of 2009, we invested $261 million and $56 million, respectively, for expansion and maintenance capital projects.  Following are some of the more notable projects and forecasted expenditures for the year:

 

 

 

Calendar 2009

 

 

 

(in millions)

 

Expansion Capital

 

 

 

· St. James Phase III (1)

 

$

73

 

· Rangeland tankage and connections

 

35

 

· Kerrobert pumping project

 

34

 

· Cushing Phase VII

 

29

 

· Patoka Phase II & III

 

20

 

· Nipisi storage and truck terminal

 

20

 

· Pier 400

 

18

 

· Pine Prairie

 

15

 

· Salt Lake City pipeline

 

14

 

· Paulsboro

 

12

 

· Other projects, including acquisition related expansion projects (2)

 

110

 

 

 

380

 

Maintenance Capital

 

85 -   95

 

Total Projected Capital Expenditures (excluding acquisitions)

 

$

465 - 475

 

 


(1)                                     Includes a dock and condensate tanks.

(2)                                     Primarily pipeline connections, upgrades and truck stations, new tank construction and refurbishing, and carry-over of projects started in 2008.

 

6



 

6.                                       Capital Structure.  This guidance is based on our capital structure as of September 30, 2009 as adjusted for the retirement on October 5, 2009 of the 7.125% Senior Notes due June 2014.

 

7.                                       Interest Expense.   Debt balances are projected based on estimated cash flows, estimated distribution rates, forecasted acquisitions and capital expenditures for maintenance and expansion projects, expected timing of collections and payments, and forecasted levels of inventory and other working capital sources and uses.  Interest rate assumptions for variable rate debt are based on the current forward LIBOR curve.

 

Included in interest expense are commitment fees, amortization of long-term debt discounts or premiums, deferred amounts associated with terminated interest-rate hedges and interest on short-term debt for non-contango inventory (primarily hedged LPG inventory and New York Mercantile Exchange and IntercontinentalExchange margin deposits). Interest expense is net of amounts capitalized for major expansion capital projects and does not include interest on borrowings for inventory stored in a contango market. We treat interest on contango-related borrowings as carrying costs of crude oil and include it in purchases and related costs.

 

8.                                       Net Income per Unit.   Basic net income per limited partner unit is calculated by dividing net income allocated to limited partners by the basic weighted average units outstanding during the period.

 

 

 

Actual

 

Guidance (in millions, except per unit data)

 

 

 

9 Months

 

3 Months Ending

 

12 Months Ending

 

 

 

Ended

 

December 31, 2009

 

December 31, 2009

 

 

 

09/30/09

 

Low

 

High

 

Low

 

High

 

Numerator for basic and diluted earnings per limited partner unit:

 

 

 

 

 

 

 

 

 

 

 

Net Income attributable to Plains

 

$

469

 

$

99

 

$

128

 

$

568

 

$

597

 

Less: General partners incentive distribution paid(1)

 

(92

)

(35

)

(35

)

(127

)

(127

)

Subtotal

 

377

 

64

 

93

 

441

 

470

 

Less: General partner 2% ownership (1)

 

(7

)

(3

)

(3

)

(10

)

(10

)

Net income available to limited partners

 

370

 

61

 

90

 

431

 

460

 

Adjustment in accordance with application of the two-class method for MLPs (1)

 

(8

)

 

 

(8

)

(8

)

Net income available to limited partners in accordance with application of the two-class method for MLPs

 

$

362

 

$

61

 

$

90

 

$

423

 

$

452

 

 

 

 

 

 

 

 

 

 

 

 

 

Denominator:

 

 

 

 

 

 

 

 

 

 

 

Basic weighted average number of limited partner units

 

128

 

136

 

136

 

130

 

130

 

Effect of dilutive securities:

 

 

 

 

 

 

 

 

 

 

 

Weighted average LTIP units

 

1

 

1

 

1

 

1

 

1

 

Diluted weighted average number of limited partner units

 

129

 

137

 

137

 

131

 

131

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic net income per limited partner unit

 

$

2.84

 

$

0.45

 

$

0.66

 

$

3.26

 

$

3.48

 

Diluted net income per limited partner unit

 

$

2.82

 

$

0.45

 

$

0.65

 

$

3.23

 

$

3.46

 

 


(1)        We allocate net income to our general partner based on the distribution paid during the current quarter (including the incentive distribution interest in excess of the 2% general partner interest).  Guidance issued by the FASB requires that the distribution pertaining to the current period’s net income, which is to be paid in the subsequent quarter, be utilized in the earnings per unit calculation. We reflect the impact of this difference as the “Adjustment in accordance with application of the two-class method for MLPs.”

 

In conjunction with the Pacific, Rainbow and PNGS acquisitions, our general partner reduced the amounts due it as incentive distributions by an aggregate amount of $83 million. Approximately $54 million of this reduction was realized as of September 30, 2009.  Incentive distributions will be reduced by $6 million for the balance of 2009, $16 million in 2010 and $7 million in 2011.

 

The relative amount of the incentive distribution varies directionally with the number of units outstanding and the level of the distribution on the units. Based on the current number of units outstanding, each $0.05 per unit annual increase or decrease in the distribution relative to forecasted amounts decreases or increases net income available for limited partners by approximately $7 million ($0.05 per unit) on an annualized basis.

 

7



 

9.                                       Equity Compensation Plans.  The majority of grants outstanding under our equity compensation plans (LTIP and Class B units) contain vesting criteria that are based on a combination of performance benchmarks and service period. The grants will vest in various percentages, typically on the later to occur of specified earliest vesting dates and the dates on which minimum distribution levels are reached. Among the various grants outstanding as of November 4, 2009, estimated vesting dates range from May 2010 to May 2019 and annualized distribution levels range from $3.00 to $4.50. For some awards, a percentage of any units remaining unvested as of a date certain will vest on such date and all others are forfeited.

 

On October 19, 2009, we declared an annualized distribution of $3.68 payable on November 13, 2009 to our unitholders of record as of November 3, 2009. We have made the assessment that a $3.90 distribution level is probable of occurring and accordingly, for grants that vest at annualized distribution levels of $3.90 or less, guidance includes an accrual over the applicable service period at an assumed market price of approximately $50.00 per unit as well as the fair value associated with awards that will vest on a date certain.  The actual amount of equity compensation expense amortization in any given period will be directly influenced by (i) our unit price at the end of each reporting period, (ii) our unit price on the date of actual vesting, (iii) the amount of the amortization in the early years, (iv) the probability assessment of achieving future distribution rates, and (v) new equity compensation award grants. For example, a $3.00 change in the unit price assumption at September 30, 2009 would change the fourth-quarter equity compensation expense by approximately $5 million. Therefore, actual net income could differ materially from our projections.

 

10.                                 Reconciliation of Net Income to EBIT and EBITDA .   The following table reconciles net income to EBIT and EBITDA, for the three-month and twelve-month guidance ranges ending December 31, 2009.

 

 

 

3 Months Ending

 

12 Months Ending

 

 

 

December 31, 2009

 

December 31, 2009

 

 

 

Low

 

High

 

Low

 

High

 

 

 

 

 

 

 

 

 

 

 

Reconciliation to EBITDA

 

 

 

 

 

 

 

 

 

Net Income attributable to Plains

 

$

99

 

$

128

 

$

568

 

$

597

 

Interest expense

 

(61

)

(59

)

(226

)

(224

)

Income tax expense

 

(2

)

(2

)

(3

)

(3

)

EBIT

 

162

 

189

 

797

 

824

 

Depreciation and amortization

 

(63

)

(61

)

(236

)

(234

)

EBITDA

 

$

225

 

$

250

 

$

1,033

 

$

1,058

 

 

Preliminary Calendar 2010 Guidance

 

The following range for preliminary adjusted EBITDA guidance for 2010 is based on the following:

 

The low end of the range assumes —

·

a prolonged recovery from the current/recent U.S. economic recession, translating into a continuation of a weak U.S. economy throughout all of 2010;

·

Continuation of weak domestic demand for crude oil and transportation fuels (currently 10% below average consumption levels realized in 2005 to 2007);

·

Reduced import levels of crude oil (2009 year-to-date is 8% below 2005 to 2008 averages and currently is 12% below such averages);

·

Weak market structure for crude oil with limited structural volatility (thus anticipating the market will be either slightly backwardated or slightly contango); and

·

A continuation of the current abnormally tight grade differentials relative to average differentials experienced in the 2005 to 2008 period.

 

The high end of the range assumes —

·

The same overall economic and energy market conditions as the low end of the range for the first half of 2010, but incorporating a gradual recovery in the economy during the second half of 2010; and

·

An increase in the second half of 2010 of domestic consumption of crude oil and transportation fuels and crude oil imports and a resulting increase in structural volatility for crude oil and expanded grade differentials.

 

Preliminary Calendar 2010 Guidance (in millions)

 

 

 

Low

 

High

 

Adjusted EBITDA

 

$

1,000

 

$

1,080

 

Depreciation and amortization

 

(255

)

(245

)

Interest expense

 

(255

)

(245

)

Taxes

 

(15

)

(10

)

Adjusted Net Income

 

$

475

 

$

580

 

 

 

 

 

 

 

Maintenance Capital Expenditures

 

$

90

 

$

80

 

 

Our preliminary guidance for interest expense is based on our capital structure as of September 30, 2009 (adjusted for the retirement of the $250 million Senior Notes on October 5, 2009), the current market outlook for floating interest rates, approved capital projects for 2009 and the assumption that 2010 capital projects including base gas will range between $300 million to $400 million.  Our preliminary guidance for depreciation and amortization is based on projected depreciation from our present asset base, and continued development of our portfolio of projects.  Our preliminary guidance for maintenance capital expenditures is based on our

 

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estimate of the range of recurring expenditures that are expected to average approximately $85 million in any given year.  All amounts assume a foreign exchange rate of $1.10 CAD to $1.00 USD.  The adjusted net income and adjusted EBITDA shown above exclude selected items impacting comparability such as equity compensation and gains and losses related to derivative activities  (see note 4 above) as it is impractical to forecast such items.

 

Forward-Looking Statements and Associated Risks

 

All statements included in this report, other than statements of historical fact, are forward-looking statements, including, but not limited to, statements identified by the words “anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend” and “forecast,” as well as similar expressions and statements regarding our business strategy, plans and objectives of our management for future operations. The absence of these words, however, does not mean that the statements are not forward-looking. 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:

 

·

failure to implement or capitalize on planned internal growth projects;

 

 

·

maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties;

 

 

·

continued creditworthiness of, and performance by, our counterparties, including financial institutions and trading companies with which we do business;

 

 

·

the success of our risk management activities;

 

 

·

environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;

 

 

·

abrupt or severe declines or interruptions in outer continental shelf production located offshore California and transported on our pipeline systems;

 

 

·

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

 

 

·

the availability of adequate third-party production volumes for transportation and marketing in the areas in which we operate and other factors that could cause declines in volumes shipped on our pipelines by us and third-party shippers, such as declines in production from existing oil and gas reserves or failure to develop additional oil and gas reserves;

 

 

·

fluctuations in refinery capacity in areas supplied by our mainlines and other factors affecting demand for various grades of crude oil, refined products and natural gas and resulting changes in pricing conditions or transportation throughput requirements;

 

 

·

the availability of, and our ability to consummate, acquisition or combination opportunities,

 

 

·

our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, expansion projects, working capital requirements and the repayment or refinancing of indebtedness;

 

 

·

the successful integration and future performance of acquired assets or businesses and the risks associated with operating in lines of business that are distinct and separate from our historical operations;

 

 

·

unanticipated changes in crude oil market structure, grade differentials and volatility (or lack thereof);

 

 

·

the impact of current and future laws, rulings, governmental regulations, accounting standards and statements and related interpretations;

 

 

·

the effects of competition;

 

 

·

interruptions in service and fluctuations in tariffs or volumes on third-party pipelines;

 

 

·

increased costs or lack of availability of insurance;

 

 

·

fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plans;

 

9



 

·

the currency exchange rate of the Canadian dollar;

 

 

·

weather interference with business operations or project construction;

 

 

·

risks related to the development and operation of natural gas storage facilities;

 

 

·

future developments and circumstances at the time distributions are declared;

 

 

·

general economic, market or business conditions and the amplification of other risks caused by deteriorated financial markets, capital constraints and pervasive liquidity concerns; and

 

 

·

other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil, refined products and liquefied petroleum gas and other natural gas related petroleum products.

 

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.

 

10



 

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.

 

 

PLAINS ALL AMERICAN PIPELINE, L.P.

 

 

 

By:

PAA GP LLC, its general partner

 

 

 

 

By:

PLAINS AAP, L. P., its sole member

 

 

 

 

By:

PLAINS ALL AMERICAN GP LLC, its general partner

 

 

 

 

 

 

Date: November 4, 2009

By:

/s/ AL SWANSON

 

 

Name:

Al Swanson

 

 

Title:

Senior Vice President and
 Chief Financial Officer

 

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