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))

Actual

Guidance (1)

6 Months

3 Months Ending

3 Months Ending

12 Months Ending

Ended

September 30, 2008

December 31, 2008

December 31, 2008

06/30/08

Low

High

Low

High

Low

High

Segment Profit

Net revenues (including equity earnings from unconsolidated entities)

$

702

$

407

$

421

$

425

$

443

$

1,534

$

1,566

Field operating costs

(297

)

(168

)

(164

)

(159

)

(154

)

(624

)

(615

)

General and administrative expenses

(90

)

(44

)

(42

)

(44

)

(42

)

(178

)

(174

)

315

195

215

222

247

732

777

Depreciation and amortization expense

(100

)

(54

)

(52

)

(57

)

(56

)

(211

)

(208

)

Interest expense, net

(91

)

(52

)

(50

)

(53

)

(52

)

(196

)

(193

)

Income tax expense

(3

)

(5

)

(4

)

(6

)

(5

)

(14

)

(12

)

Other income (expense), net

12

—

—

—

—

12

12

Net Income

$

133

$

84

$

109

$

106

$

134

$

323

$

376

Net Income to Limited Partners

$

83

$

53

$

77

$

75

$

101

$

211

$

261

Basic Net Income Per Limited Partner Unit

Weighted Average Units Outstanding

118

123

123

123

123

120

120

Net Income Per Unit

$

0.70

$

0.43

$

0.63

$

0.61

$

0.82

$

1.76

$

2.18

Diluted Net Income Per Limited Partner Unit

Weighted Average Units Outstanding

119

124

124

124

124

124

121

Net Income Per Unit

$

0.69

$

0.43

$

0.62

$

0.60

$

0.81

$

1.74

$

2.16

EBIT

$

227

$

141

$

163

$

165

$

191

$

533

$

581

EBITDA

$

327

$

195

$

215

$

222

$

247

$

744

$

789

Selected Items Impacting Comparability

 Equity compensation charge

$

(21

)

$

(10

)

$

(10

)

$

(8

)

$

(8

)

$

(39

)

$

(39

)

 Acquisition related hedging activity

11

—

—

—

—

11

11

 SFAS 133 Mark-to-Market Adjustment

(92

)

—

—

—

—

(92

)

(92

)

$

(102

)

$

(10

)

$

(10

)

$

(8

)

$

(8

)

$

(120

)

$

(120

)

Excluding Selected Items Impacting Comparability

 Adjusted Segment Profit

Transportation

$

206

$

111

$

117

$

117

$

123

$

434

$

446

Facilities

71

40

42

41

45

152

158

Marketing

151

54

66

72

87

277

304

Other Income (Expense), net

1

—

—

—

—

1

1

 Adjusted EBITDA

$

429

$

205

$

225

$

230

$

255

$

864

$

909

 Adjusted Net Income

$

235

$

94

$

119

$

114

$

142

$

443

$

496

 Adjusted Basic Net Income per Limited Partner Unit

$

1.54

$

0.51

$

0.71

$

0.67

$

0.89

$

2.74

$

3.16

 Adjusted Diluted Net Income per Limited Partner Unit

$

1.53

$

0.51

$

0.70

$

0.67

$

0.88

$

2.72

$

3.13

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 purchases, 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

FX

Foreign currency exchange

General partner

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.

Calender 2008

Actual

Guidance

Six Months

Three Months

Three Months

Twelve Months

Ended

Ending

Ending

Ending

June 30

September 30

December 31

December 31

Average Daily Volumes (000 Bbls/d)

All American

45

46

46

45

Basin

370

360

360

365

Capline

218

245

235

229

Line 63 / 2000

161

150

150

155

Salt Lake City Area Systems (1)

96

95

100

97

West Texas / New Mexico Area Systems (1)

402

400

400

401

Rainbow

66

195

195

130

Manito

70

75

75

73

Rangeland

60

55

55

58

Refined Products

111

110

120

113

Other

1,206

1,184

1,189

1,199

2,805

2,915

2,925

2,865

Trucking

93

105

110

101

2,898

3,020

3,035

2,966

Average Segment Profit ($/Bbl)

Excluding Selected Items Impacting Comparability

$

0.39

$

0.41

⁽²⁾

$

0.43

⁽²⁾

$

0.41

⁽²⁾

(1)

The aggregate of multiple systems in the respective areas.

(2)

Mid-point of guidance.

Calendar 2008

Actual

Guidance

Six Months

Three Months

Three Months

Twelve Months

Ended

Ending

Ending

Ending

June 30

September 30

December 31

December 31, 2008

Operating Data

Crude oil, refined products and LPG storage (MMBbls/Mo.)⁽¹⁾

54

55

59

56

Natural Gas Storage (Bcf/Mo.)

13

13

14

14

LPG Processing (MBbl/d)

16

20

19

18

Facilities Activities Total ⁽²⁾

Avg. Capacity (MMBbls/Mo.)

57

58

62

58

Segment Profit per Barrel ($/Bbl)

Excluding Selected Items Impacting Comparability

$

0.21

$

0.24

⁽³⁾

$

0.23

⁽³⁾

$

0.22

⁽³⁾

(1)

Effective with the second quarter of 2008, facilities segment volumes with respect to crude oil and refined products are reported based on total shell capacity to provide uniform comparisons with respect to our activities for these products.  Previously, such volumes were reported based on a combination of shell capacity and working capacity depending on the terms of the third-party or intra-company lease agreements.  Natural gas and LPG volumes, which consist primarily of underground storage facilities, reflect working capacity as that is the primary basis upon which such facilities are leased. Corresponding metrics for prior periods have been conformed to this uniform approach.

(2)

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.

(3)

Mid-point of guidance.

Calendar 2008

Actual

Guidance

Six Months

Three Months

Three Months

Twelve Months

Ended

Ending

Ending

Ending

June 30

September 30

December 31

December 31, 2008

Average Daily Volumes (MBbl/d)

Crude Oil Lease Gathering

676

690

695

684

LPG Sales

93

75

125

97

Refined Products

22

27

30

25

Waterborne foreign crude imported

89

75

75

82

880

867

925

888

Segment Profit per Barrel ($/Bbl)

Excluding Selected Items Impacting Comparability

$

0.94

$

0.75

⁽¹⁾

$

0.93

⁽¹⁾

$

0.89

⁽¹⁾

3.

Depreciation and Amortization. We forecast depreciation and amortization based on our existing depreciable assets, forecasted capital expenditures and projected in-service dates. Depreciation is computed using the straight-line method over estimated useful lives, which range from 3 years (for office furniture and equipment) to 40 years (for certain pipelines, crude oil terminals and facilities) and includes gains and losses on the sale of assets.

4.

Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”). This guidance does not include assumptions or projections with respect to potential gains or losses related to derivatives accounted for under SFAS 133, as there is no accurate way to forecast these potential gains or losses. The potential gains or losses related to these derivatives (primarily mark-to-market adjustments) could cause actual net income to differ materially from our projections, as demonstrated by the $92 million SFAS 133 mark-to-market adjustment reported for the six months ended June 30, 2008, but will reverse in future periods as the offsetting physical transactions are settled.

5.

Capital Expenditures and Acquisitions.  Although acquisitions constitute a key element of our growth strategy, the forecasted results and associated estimates do not include any forecasts for acquisitions that may be made after the date hereof. Capital expenditures for expansion projects are forecasted to be approximately $460 million during calendar 2008, of which $256 million was spent in the first six months of 2008. Following are some of the more notable projects and forecasted expenditures for the year:

Calendar 2008

(in millions)

Expansion Capital

· Patoka tankage

$

46

· Paulsboro tankage

30

· Kerrobert mainline connection

21

· Fort Laramie tank expansion

22

· Pier 400⁽¹⁾

13

· West Hynes tankage

13

· Kerrobert facility

12

· Edmonton tankage and connections

11

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

292

460

Maintenance Capital

70

Total Projected Capital Expenditures (excluding acquisitions)

$

530

6.

Capital Structure. This guidance is based on our capital structure as of June  30, 2008.

7.

Interest Expense. Debt balances are projected based on estimated cash flows, current distribution rates, forecasted 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.

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 as part of the purchase price of crude oil.

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.  The following table reflects the anticipated impact of achieving our November 2008 annualized distribution goal of $3.61 to $3.66 per unit.

Guidance (in millions)

Three Months Ending

Three Months Ending

Twelve Months Ending

September 30, 2008

December 31, 2008

December 31, 2008

Low

High

Low

High

Low

High

Numerator for basic and diluted earnings per limited partner unit:

Net Income

$

84

$

109

$

106

$

134

$

323

$

376

General partners incentive distribution

(34

)

(34

)

(35

)

(37

)

(126

)

(128

)

General partners incentive distribution reduction

4

4

6

6

18

18

54

79

77

103

215

266

General partner 2% ownership

(1

)

(2

)

(2

)

(2

)

(4

)

(5

)

Net income available to limited partners

$

53

$

77

$

75

$

101

$

211

$

261

Denominator:

Denominator for basic earnings per limited partner unit-weighted average number of limited partner units

123

123

123

123

120

120

Effect of dilutive securities:
Weighted average LTIP units

1

1

1

1

1

1

Denominator for diluted earnings per limited partner unit-weighted average number of limited partner units

124

124

124

124

121

121

Basic net income per limited partner unit

$

0.43

$

0.63

$

0.61

$

0.82

$

1.76

$

2.18

Diluted net income per limited partner unit

$

0.43

$

0.62

$

0.60

$

0.81

$

1.74

$

2.16

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. The amount of income allocated to our limited partner interests is 98% of the total partnership income after deducting the amount of the general partner’s incentive distribution as adjusted for temporary reductions in the incentive distribution rights as discussed below. For the second half of 2008, our forecast incorporates the assumption that we will achieve the midpoint of our targeted distribution growth for 2008, which is based on an annualized distribution level in the fourth quarter of 2008 of $3.61 per unit to $3.66 per unit.

In conjunction with the Pacific and Rainbow acquisitions, the general partner reduced the amounts due it as incentive distributions by an aggregate amount of $75 million. Approximately $27.5 million of this reduction was realized as of May 15, 2008.  Incentive distributions will be reduced by $10 million for the second half of 2008, $21 million in 2009, $11 million in 2010 and $5 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, respectively, net income available for limited partners by approximately $6 million ($0.05 per unit) on an annualized basis.

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 August 5, 2008, estimated vesting dates range from May 2009 to January 2016 and minimum annualized distribution levels range from $2.80 to $4.50. For some awards, a percentage of any remaining units will vest on a date certain in 2011 or 2012 and all others are forfeited.

On July 14, 2008, we declared an annualized distribution of $3.55 payable on August 14, 2008 to our unitholders of record as of August 4, 2008. In addition to the current distribution level of $3.55, we have deemed probable that the $3.75 distribution level will be achieved. Accordingly, for grants that vest at annualized distribution levels of $3.75 or less, guidance includes an accrual over the applicable service period at an assumed market price of $45.11 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 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, 2008 would change the third-quarter equity compensation expense by approximately $5 million — $1 million for the current quarter and $4 million for the life-to-date adjustment to the liability accrued in prior periods. Therefore, actual net income could differ materially from our projections.

Included in equity compensation expense highlighted in selected items impacting comparability for 2008 is approximately $14 million of expense attributable to the Class B units. Since the economic burden of the Class B units is borne solely by the General Partner and not the Partnership, an amount equal to the expense will be reflected as a capital contribution and thus will result in a corresponding credit to Partners’ Capital in the financial statements of the Partnership.

10.

Reconciliation of EBITDA and EBIT to Net Income. The following table reconciles the three-month guidance range ending September 30 and December 31, 2008 and twelve months ending December 31, 2008 for EBITDA and EBIT to net income.

Guidance (in millions)

Three Months Ending

Three Months Ending

Twelve Months Ending

September 30, 2008

December 31, 2008

December 31, 2008

Low

High

Low

High

Low

High

Reconciliation to Net Income

EBITDA

$

195

$

215

$

222

$

247

$

744

$

789

Depreciation and amortization

54

52

57

56

211

208

EBIT

141

163

165

191

533

581

Interest expense

52

50

53

52

196

193

Income tax expense

5

4

6

5

14

12

Net Income

$

84

$

109

$

106

$

134

$

323

$

376

·

failure to implement or capitalize on planned internal growth projects;

·

the success of our risk management activities;

·

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

·

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;

·

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 access to capital to fund additional acquisitions and our ability to obtain debt or equity financing on satisfactory terms;

·

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 and volatility (or lack thereof);

·

the impact of current and future laws, rulings, governmental regulations and 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;

·

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

·

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.

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: August 6, 2008

By:

  /s/ AL SWANSON

Name:

Al Swanson

Title:

Senior Vice President-Finance

Contacts:

Roy I. Lamoreaux

Al Swanson

Manager, Investor Relations

Senior Vice President, Finance

713/646-4222 – 800/564-3036

713/646-4455 – 800/564-3036

333 Clay Street, Suite 1600

Houston, Texas 77002

713-646-4100 / 800-564-3036

333 Clay Street, Suite 1600

Houston, Texas 77002

713-646-4100 / 800-564-3036

Three Months Ended

Six Months Ended

June 30,

June 30,

2008

2007

2008

2007

(In millions, except per unit data)

(In millions, except per unit data)

Selected items impacting comparability

Equity compensation charge (1)

$

(15

)

$

(19

)

$

(21

)

$

(37

)

SFAS 133 mark-to-market adjustment (2)

(87

)

15

(92

)

(2

)

Gains on acquisition-related hedges

11

—

11

—

Deferred income tax expense

—

(11

)

—

(11

)

Selected items impacting comparability

(91

)

(15

)

(102

)

(50

)

Less: GP 2% portion of selected items impacting comparability

2

—

2

1

LP 98% portion of selected items impacting comparability

$

(89

)

$

(15

)

$

(100

)

$

(49

)

Impact to basic net income per limited partner unit

$

(0.74

)

$

(0.14

)

$

(0.84

)

$

(0.45

)

Impact to diluted net income per limited partner unit

$

(0.73

)

$

(0.13

)

$

(0.84

)

$

(0.45

)

333 Clay Street, Suite 1600

Houston, Texas 77002

713-646-4100 / 800-564-3036