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Form 8-K PLAINS ALL AMERICAN PIPE For: Feb 04

February 4, 2015 4:14 PM EST

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) � February�4, 2015

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
incorporation)

(Commission File Number)

(IRS Employer Identification No.)

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 February�4, 2015.

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

Plains All American Pipeline, L.P. (the �Partnership�) today issued a press release reporting its fourth-quarter and full-year 2014 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 also providing detailed guidance for financial performance for the first quarter and full year of 2015.� In accordance with General Instruction B.2. of Form�8-K, the information presented herein under Item 2.02 and 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.

Disclosure of First Quarter and Full Year 2015 Guidance

We based our guidance for the three-month period ending March�31, 2015 and twelve-month period ending December�31, 2015 on assumptions and estimates that we believe are reasonable, given our assessment of historical trends (modified for changes in market conditions, including an assumption that crude oil prices will not meaningfully increase from current levels during 2015 which we expect to result in reduced drilling activity and reduced oil production growth), 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 NGL 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 February�3, 2015. We undertake no obligation to publicly update or revise any forward-looking statements.

To supplement our financial information presented in accordance with GAAP, management uses additional measures known as �non-GAAP financial measures� in its evaluation of past performance and prospects for the future.� Management believes that the presentation of such additional financial measures provides useful information to investors regarding our financial condition and results of operations because these measures, when used in conjunction with related GAAP financial measures, (i)�provide additional information about our core operations and ability to generate and distribute cash flow, (ii)�provide investors with the financial analytical framework upon which management bases financial, operational, compensation and planning decisions and (iii)�present measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations.� EBITDA (as defined below in Note 1 to the �Operating and Financial Guidance� table) is a non-GAAP financial measure. Net income represents one of the two most directly comparable GAAP measures to EBITDA. In Note 9 below, we reconcile net income to EBITDA and adjusted EBITDA for the 2015 guidance periods presented. Cash flows from operating activities is the other most comparable GAAP measure. We do not, however, reconcile cash flows from operating activities to EBITDA, because such reconciliations are impractical for forecasted periods. We encourage you to visit our website at www.plainsallamerican.com (in particular the section under Investor Relations entitled �Guidance and Non-GAAP Reconciliations�), which presents a historical reconciliation of EBITDA as well as certain other commonly used non-GAAP financial measures. These measures may exclude, for example, (i)�charges for obligations that are expected to be settled with the issuance of equity instruments, (ii)�the mark-to-market of derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), (iii)�inventory valuation adjustments, (iv)�items that are not indicative of our core operating results and business outlook and/or (v)�other items that we believe should be excluded in understanding our core operating performance. We have defined all such items as �Selected Items Impacting Comparability.�� Due to the nature of the selected items, certain selected items impacting comparability may impact certain non-GAAP financial measures, referred to as adjusted results, but not impact other non-GAAP financial measures.

2



Plains All American Pipeline, L.P.

Operating and Financial Guidance

(in millions, except per unit data)

Guidance�(a)

3�Months�Ending

12�Months�Ending

Mar�31,�2015

Dec�31,�2015

Low

High

Low

High

Segment Profit

Net revenues (including equity earnings from unconsolidated entities)

$

999

$

1,047

$

4,029

$

4,189

Field operating costs

(375

)

(366

)

(1,488

)

(1,458

)

General and administrative expenses

(86

)

(83

)

(338

)

(328

)

538

598

2,203

2,403

Depreciation and amortization expense

(106

)

(102

)

(438

)

(422

)

Interest expense, net

(106

)

(102

)

(428

)

(412

)

Income tax expense

(39

)

(35

)

(102

)

(86

)

Other income / (expense), net

Net Income

287

359

1,235

1,483

Net income attributable to noncontrolling interests

(1

)

(1

)

(3

)

(3

)

Net Income Attributable to PAA

$

286

$

358

$

1,232

$

1,480

Net Income to Limited Partners (b)

$

146

$

217

$

632

$

875

Basic Net Income Per Limited Partner Unit (b)

Weighted Average Units Outstanding

378

378

387

387

Net Income Per Unit

$

0.38

$

0.57

$

1.62

$

2.25

Diluted Net Income Per Limited Partner Unit (b)

Weighted Average Units Outstanding

380

380

389

389

Net Income Per Unit

$

0.38

$

0.56

$

1.61

$

2.23

EBITDA

$

538

$

598

$

2,203

$

2,403

Selected Items Impacting Comparability

Equity-indexed compensation expense

$

(12

)

$

(12

)

$

(47

)

$

(47

)

Selected Items Impacting Comparability of Net Income attributable to PAA

$

(12

)

$

(12

)

$

(47

)

$

(47

)

Excluding Selected Items Impacting Comparability

Adjusted Segment Profit

Transportation

$

241

$

253

$

1,190

$

1,230

Facilities

126

138

570

610

Supply and Logistics

183

219

490

610

Other income, net

Adjusted EBITDA

$

550

$

610

$

2,250

$

2,450

Adjusted Net Income Attributable to PAA

$

298

$

370

$

1,279

$

1,527

Basic Adjusted Net Income Per Limited Partner Unit (b)

$

0.41

$

0.60

$

1.74

$

2.37

Diluted Adjusted Net Income Per Limited Partner Unit (b)

$

0.41

$

0.60

$

1.73

$

2.35


(a)������������������������������������� The assumed average foreign exchange rate is $1.20 Canadian to $1.00 U.S. for the three-month period ending March�31, 2015 and the twelve-month period ending December�31, 2015.� The rate as of February�3, 2015 was $1.25 Canadian to $1.00 U.S. A $0.05 change in such average FX rate will impact annual adjusted EBITDA by approximately $10 million.

(b)������������������������������������ We calculate net income available to limited partners based on the distributions pertaining to the current period�s net income. After adjusting for the appropriate period�s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner, limited partners and participating securities in accordance with the contractual terms of the partnership agreement and as further prescribed under the two-class method.

3



Notes and Significant Assumptions:

1. Definitions.

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

DCF

Distributable Cash Flow

Bbls/d

Barrels per day

Mcf

Thousand cubic feet

Bcf

Billion cubic feet

LTIP

Long-Term Incentive Plan

NGL

Natural gas liquids. Includes ethane and natural gasoline products as well as propane and butane, which are often referred to as liquefied petroleum gas (LPG). When used in this document NGL refers to all NGL products including LPG.

FX

Foreign currency exchange

G&A

General and administrative

General partner (GP)

As the context requires, �general partner� or �GP� 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.

2.������������� Operating Segments. We manage our operations through three operating segments: �Transportation, Facilities and Supply and Logistics. 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 NGL on pipelines, gathering systems, trucks and barges. The Transportation segment generates revenue through a combination of tariffs, third-party pipeline capacity agreements and other transportation fees. Our transportation segment also includes our equity earnings from investments in Settoon Towing and the White Cliffs, Eagle Ford, BridgeTex, Butte and Frontier pipeline systems, in which we own interests ranging from 22% to 50%.� We account for these investments under the equity method of accounting.

Pipeline volume estimates are based on historical trends, anticipated future operating performance and assumed completion of capital projects. Actual volumes will be influenced by maintenance schedules at refineries, drilling and completion activity levels, production trends, weather and other natural occurrences including hurricanes, changes in the quantity of inventory held in tanks, variations due to market structure and other external factors beyond our control. We forecast adjusted segment profit 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 transportation volumes and highlights major systems that are significant either in total volumes transported or in contribution to total Transportation segment profit.

4



Guidance

Three�Months

Twelve�Months

Ending

Ending

Mar�31,�2015

Dec�31,�2015

Average Daily Volumes (MBbls/d)

Crude Oil Pipelines

All American

30

35

Bakken Area Systems

160

165

Basin / Mesa / Sunrise

900

945

BridgeTex

85

110

Cactus

90

Capline

160

160

Eagle Ford Area Systems

255

310

Line 63 / 2000

155

160

Manito

45

45

Mid-Continent Area Systems

375

365

Permian Basin Area Systems

810

965

Rainbow

120

130

Rangeland

70

70

Salt Lake City Area Systems

135

140

South Saskatchewan

65

65

White Cliffs

50

55

Other

740

785

NGL Pipelines

Co-Ed

65

65

Other

100

110

�4,320

4,770

Trucking

140

140

�4,460

4,910

Segment Profit per Barrel ($/Bbl)

Excluding Selected Items Impacting Comparability

$

0.62

(1)

$

0.68

(1)


(1)������������ Mid-point of guidance.

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, NGL and natural gas, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. The Facilities segment generates revenue through a combination of month-to-month and multi-year agreements and processing arrangements.

Revenues generated in this segment primarily include (i)�fees that are generated from storage capacity agreements, (ii)�terminal throughput fees that are generated when we receive crude oil, refined products or NGL from one connecting source and deliver the applicable product to another connecting carrier, (iii)�loading and unloading fees at our rail terminals, (iv)�fees from�NGL fractionation and isomerization, (v)�fees from natural gas and condensate processing services and (vi)�fees associated with natural gas park and loan activities, interruptible storage services and wheeling and balancing services.� Adjusted segment profit is forecasted 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.

5



Guidance

Three�Months

Twelve�Months

Ending

Ending

Mar�31,�2015

Dec�31,�2015

Operating Data

Crude Oil, Refined Products, and NGL Terminalling and Storage (MMBbls/Mo.)

97

98

Rail Load / Unload Volumes (MBbls/d)

265

350

Natural Gas Storage (Bcf/Mo.)

97

97

NGL Fractionation (MBbls/d)

95

90

Facilities Activities Total

Avg. Capacity (MMBbls/Mo.) (1)

124

128

Segment Profit per Barrel ($/Bbl)

Excluding Selected Items Impacting Comparability

$

0.35

(2)

$

0.38

(2)


(1)������������ Calculated as the sum of: (i)�crude oil, refined products and NGL terminalling and storage capacity; (ii)�rail load and unload volumes multiplied by the number of days in the period and divided by the number of months in the period; (iii)�natural gas storage working capacity divided by 6 to account for the 6:1 mcf of natural gas to crude Btu equivalent ratio and further divided by 1,000 to convert to monthly volumes in millions; and (iv)�NGL fractionation 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.�������������������������� Supply and Logistics. Our Supply and Logistics segment operations generally consist of the following merchant-related activities:

����������������� the purchase of U.S. and Canadian crude oil at the wellhead, the bulk purchase of crude oil at pipeline, terminal and rail facilities, and the purchase of cargos at their load port and various other locations in transit;

����������������� the storage of inventory during contango market conditions and the seasonal storage of NGL and natural gas;

����������������� the purchase of NGL from producers, refiners, processors and other marketers;

����������������� the resale or exchange of crude oil and NGL at various points along the distribution chain to refiners or other resellers;

����������������� the transportation of crude oil and NGL on trucks, barges, railcars, pipelines and ocean-going vessels from various delivery points, market hub locations or directly to end users such as refineries, processors and fractionation facilities; and

����������������� the purchase and sale of natural gas.

We characterize a substantial portion of our baseline profit generated by our Supply and Logistics segment as fee equivalent. This portion of the segment profit is generated by the purchase and resale of crude oil on an index-related basis, which results in us generating a gross margin for such activities.� This gross margin is reduced by the transportation, facilities and other logistical costs associated with delivering the crude oil to market and carrying costs for hedged inventory as well as any operating and G&A expenses.� The level of profit associated with a portion of the other activities we conduct in the Supply and Logistics segment is influenced by overall market structure and the degree of market volatility as well as variable operating expenses. Forecasted operating results for the three-month period ending March�31, 2015 and for the twelve-month period ending December�31, 2015 reflect current and anticipated market structure as well as seasonal, weather-related and other anticipated variations in crude oil, NGL and natural gas sales. Variations in weather, market structure or volatility could cause actual results to differ materially from forecasted results.

6



We forecast adjusted 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 hedged inventory, based on current and anticipated market conditions. Actual volumes are influenced by temporary market-driven storage and withdrawal of crude oil, maintenance schedules at refineries, actual production levels, 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 and quality differentials as well as contract structure. Accordingly, the projected segment profit per barrel can vary significantly even if aggregate volumes are in line with the forecasted levels.

Guidance

Three�Months

Twelve�Months

Ending

Ending

Mar�31,�2015

Dec�31,�2015

Average Daily Volumes (MBbls/d)

Crude Oil Lease Gathering Purchases

965

980

NGL Sales

290

210

1,255

1,190

Segment Profit per Barrel ($/Bbl)

Excluding Selected Items Impacting Comparability

$

1.78

(1)

$

1.27

(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 also vary due to gains and losses on intermittent sales of assets, asset retirement obligations, asset impairments, acceleration of depreciation or foreign exchange rates.

4.������������� 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 we may commit to after the date hereof. We forecast capital expenditures during the calendar year of 2015 to be approximately $1.85 billion for expansion projects with an additional $205 to $225 million for maintenance capital projects.� The following are some of the more notable projects and forecasted expenditures for the year ending December�31, 2015:

Calendar�2015

(in�millions)

Expansion Capital

Permian Basin Area Projects

$365

Ft. Sask Facility Projects / NGL Line

290

Rail Terminal Projects (1)

240

Diamond Pipeline

165

Cactus Pipeline

85

Eagle Ford JV Project

85

Red River Pipeline (Cushing to Longview)

80

Cowboy Pipeline (Cheyenne to Carr)

50

Eagle Ford Area Projects

35

Line 63 Reactivation

30

Cushing Terminal Expansions

25

Other Projects

400

$1,850

Potential Adjustments for Timing / Scope Refinement (2)

- $100 + $100

Total Projected Expansion Capital Expenditures

$1,750 - $1,950

Maintenance Capital Expenditures

$205 - $225


(1)������������ Includes railcar purchases and projects located in or near St. James, LA and Kerrobert, Canada.

(2)������������ Potential variation to current capital costs estimates may result from (i)�changes to project design, (ii)�final cost of materials and labor and (iii)�timing of incurrence of costs due to uncontrollable factors such as permits, regulatory approvals and weather.

7



5.������������� Capital Structure. This guidance is based on our capital structure as of December�31, 2014 and adjusted for estimated equity issuances and senior note offerings to fund our capital program.

6.������������� Interest Expense. Debt balances are projected based on estimated cash flows, estimated distribution rates, estimated capital expenditures for maintenance and expansion projects, anticipated equity proceeds, 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 LIBOR curve as of late January�2015.

Interest expense is net of amounts capitalized for expansion capital projects and does not include interest on borrowings for hedged inventory. We treat interest on hedged inventory borrowings as carrying costs of crude oil, NGL, and natural gas and include it in purchases and related costs. Interest expense includes an assumed fixed rate senior note offering in 2015.

7.������������ Income Taxes. We expect our Canadian income tax expense to be approximately $37 million and $94 million for the three-month period ending March�31, 2015 and twelve-month period ending December�31, 2015, respectively, of which approximately $31 million and $81 million, respectively, is classified as a current income tax expense.� For the twelve-month period ending December�31, 2015 we expect to have deferred tax expense of $13 million.� All or part of the annual income tax expense of $94 million may result in a tax credit to our equity holders.

8.������������� Equity-Indexed Compensation Plans. The majority of grants outstanding under our various equity-indexed compensation plans contain vesting criteria that are based on a combination of performance benchmarks and service periods. The grants will vest in various percentages, typically on the later to occur of specified vesting dates and the dates on which minimum distribution levels are reached. Among the various grants outstanding as of February�3, 2015, estimated vesting dates range from February�2015 to August�2019 and annualized benchmark distribution levels range from $2.075 to $3.20.

On January�8, 2015, we declared an annualized distribution of $2.70 payable on February�13, 2015 to our unitholders of record as of January�30, 2015. For the purposes of guidance, we have made the assessment that an annualized $2.90 distribution level is probable of occurring, and accordingly, guidance includes an accrual over the applicable service period at an assumed market price of $50 per unit as well as an accrual associated with awards that will vest on a certain date. The actual amount of equity-indexed compensation expense 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 vesting date, (iii)�our then current probability assessment regarding distributions, and (iv)�new equity-indexed compensation award grants, including the timing of such grant issuances. For example, a $2 change in the unit price would change the first-quarter equity-indexed compensation expense by approximately $5 million and the full year equity-indexed compensation expense by approximately $6 million.� Therefore, actual net income could differ from our projections.

9.������������� Reconciliation of Net Income to EBITDA and Adjusted EBITDA. The following table reconciles net income to EBITDA and Adjusted EBITDA for the three-month period ending March�31, 2015 and the twelve-month period ending December�31, 2015.

Guidance

3�Months�Ending

12�Months�Ending

Mar�31,�2015

Dec�31,�2015

Low

High

Low

High

Reconciliation to EBITDA and Adjusted EBITDA

Net Income

$

287

$

359

$

1,235

$

1,483

Interest expense, net

106

102

428

412

Income tax expense

39

35

102

86

Depreciation and amortization

106

102

438

422

EBITDA

$

538

$

598

$

2,203

$

2,403

Selected Items Impacting Comparability of EBITDA

12

12

47

47

Adjusted EBITDA

$

550

$

610

$

2,250

$

2,450

8



10.������ Implied DCF. The following table reconciles adjusted EBITDA to implied DCF for the three-month period ending March�31, 2015 and the twelve-month period ending December�31, 2015.

Mid-Point�Guidance

Three�Months

Twelve�Months

Ending

Ending

Mar�31,�2015

Dec�31,�2015

Adjusted EBITDA

$

580

$

2,350

Interest expense, net

(104

)

(420

)

Current income tax expense

(31

)

(81

)

Maintenance capital expenditures

(54

)

(215

)

Other, net

6

6

Implied DCF

$

397

$

1,640

9



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 incorporating the words �anticipate,� �believe,� �estimate,� �expect,� �plan,� �intend� and �forecast,� as well as similar expressions and statements regarding our business strategy, plans and objectives for future operations. The absence of such words, expressions or statements, however, does not mean that the statements are not forward-looking. Any such forward-looking statements reflect our current views with respect to future events, based on what we believe to be reasonable assumptions. Certain factors could cause actual results or outcomes to differ materially from the results or outcomes anticipated in the forward-looking statements. The most important of these factors include, but are not limited to:

����������������� failure to implement or capitalize, or delays in implementing or capitalizing, on planned growth projects;

����������������� declines in the volume of crude oil, refined product and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our facilities, whether due to declines in production from existing oil and gas reserves, failure to develop or slowdown in the development of additional oil and gas reserves, whether from reduced cash flow to fund drilling or the inability to access capital, or other factors;

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

����������������� environmental liabilities or events that are not covered by an indemnity, insurance or existing 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 effects of competition;

����������������� the occurrence of a natural disaster, catastrophe, terrorist attack or other event, including attacks on our electronic and computer systems;

����������������� tightened capital markets or other factors that increase our cost of capital or limit 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;

����������������� weather interference with business operations or project construction, including the impact of extreme weather events or conditions;

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

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

����������������� the currency exchange rate of the Canadian dollar;

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

����������������� 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;

����������������� the effectiveness of our risk management activities;

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

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

����������������� non-utilization of our assets and facilities;

����������������� increased costs, or lack of availability, of insurance;

10



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

����������������� risks related to the development and operation of our facilities, including our ability to satisfy our contractual obligations to our customers at our facilities;

����������������� factors affecting demand for natural gas and natural gas storage services and rates;

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

����������������� other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil and refined products, as well as in the storage of natural gas and the processing, transportation, fractionation, storage and marketing of natural gas liquids.

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.

11



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: February�4, 2015

By:

/s/ Sharon Spurlin

Name:

Sharon Spurlin

Title:

Vice President and Treasurer

12


Exhibit�99.1

FOR IMMEDIATE RELEASE

Plains All American Pipeline, L.P. and Plains GP Holdings Report Fourth-Quarter and Full-Year 2014 Results

(Houston � February�4, 2015) Plains All American Pipeline, L.P. (NYSE: PAA) and Plains GP Holdings (NYSE: PAGP) today reported fourth-quarter and full-year 2014 results.

Plains All American Pipeline, L.P.

Summary Financial Information (1)�(unaudited)

(in millions, except per unit data)

Three�Months�Ended

Twelve�Months�Ended

December�31,

%

December�31,

%

2014

2013

Change

2014

2013

Change

Net income attributable to PAA

$

389

$

309

26%

$

1,384

$

1,361

2%

Diluted net income per limited partner unit

$

0.67

$

0.58

16%

$

2.38

$

2.80

-15%

EBITDA

$

664

$

526

26%

$

2,289

$

2,168

6%

Three�Months�Ended

Twelve�Months�Ended

December�31,

%

December�31,

%

2014

2013

Change

2014

2013

Change

Adjusted net income attributable to PAA

$

362

$

371

-2%

$

1,347

$

1,466

-8%

Diluted adjusted net income per limited partner unit

$

0.60

$

0.76

-21%

$

2.28

$

3.10

-26%

Adjusted EBITDA

$

594

$

595

0%

$

2,200

$

2,292

-4%

Distribution per unit declared for the period

$

0.6750

$

0.6150

9.8%


(1)������������������������������������ PAA�s reported results include the impact of items that affect comparability between reporting periods. The impact of certain of these items is excluded from adjusted results.� See the section of this release entitled �Non-GAAP Financial Measures and Selected Items Impacting Comparability� and the tables attached hereto for information regarding certain selected items that PAA believes impact comparability of financial results between reporting periods, as well as for information regarding non-GAAP financial measures (such as adjusted EBITDA) and their reconciliation to the most directly comparable measures as reported in accordance with GAAP.

�2014 represents another year of solid execution for PAA, as we delivered results in line with to slightly ahead of the midpoint of our guidance for both the fourth quarter and full year, excluding the impact of a fourth quarter acquisition,� stated Greg L. Armstrong, Chairman and CEO of Plains All American.� �These results were underpinned by solid performance in our Transportation and Supply and Logistics segments.�

Armstrong noted that following PAA�s November�earnings conference call, crude oil and natural gas liquids prices decreased approximately 40%, which resulted in significant reductions in the outlook for producer drilling activities in 2015 � in many cases ranging from 30% to 40% below 2014 levels.

�PAA is well positioned to manage through industry down cycles; however, we are not immune to the adverse impacts of a major step change in commodity prices that is accompanied by a similar change in producers� activity levels.� Accordingly, we have reduced the midpoint of our acquisition adjusted EBITDA guidance for 2015 by 6.5%, from just over $2.5 billion, as furnished on November�5th, to $2.35 billion and revised our distribution growth target for 2015.� We are currently targeting distribution growth for PAA of 7% for 2015, which would equate to a distribution increase for PAGP of approximately 21%.�

Armstrong stated that the updated guidance midpoint represented an increase of approximately 7% over 2014 results and is based on 2015 WTI oil prices hovering around $50 per barrel for all of 2015 and the expectation that producer drilling activities will be materially reduced relative to 2014.� WTI prices averaged approximately $93 per barrel in 2014.

�While the duration of the current down-cycle is unknown, our confidence in the North American crude oil resource base and its ultimate development remains high. As we look ahead, PAA remains well positioned to continue to grow and strengthen its business through organic growth projects and also to actively pursue attractive acquisition opportunities.� For 2015, we are targeting an expansion capital plan of $1.85 billion, down approximately 9% from the $2.03 billion spent in 2014.� Importantly, PAA enters 2015 with a strong balance sheet, credit metrics that are consistent with or favorable to our targeted levels and $3.6 billion of committed liquidity.�

� more �

333 Clay Street, Suite�1600��������� Houston, Texas 77002��������� (713) 646-4100 / (866) 809-1291



Page 2

The following table summarizes selected PAA financial information by segment for the fourth quarter and full year of 2014:

Summary of Selected Financial Data by Segment (1)�(unaudited)

(in millions)

Three�Months�Ended

Three�Months�Ended

December�31,�2014

December�31,�2013

Transportation

Facilities

Supply�and
Logistics

Transportation

Facilities

Supply�and
Logistics

Reported segment profit

$

267

$

149

$

249

$

207

$

170

$

149

Selected items impacting the comparability of segment profit (2)

3

2

(76

)

7

(1

)

60

Adjusted segment profit

$

270

$

151

$

173

$

214

$

169

$

209

Percentage change in adjusted segment profit versus 2013 period

26

%

-11

%

-17

%

Twelve�Months�Ended

Twelve�Months�Ended

December�31,�2014

December�31,�2013

Transportation

Facilities

Supply�and
Logistics

Transportation

Facilities

Supply�and
Logistics

Reported segment profit

$

925

$

584

$

782

$

729

$

616

$

822

Selected items impacting the comparability of segment profit (2)

25

13

(131

)

31

13

71

Adjusted segment profit

$

950

$

597

$

651

$

760

$

629

$

893

Percentage change in adjusted segment profit versus 2013 period

25

%

-5

%

-27

%


(1)����������� PAA�s reported results include the impact of items that affect comparability between reporting periods. The impact of certain of these items is excluded from adjusted results. See the section of this release entitled �Non-GAAP Financial Measures and Selected Items Impacting Comparability� and the tables attached hereto for information regarding certain selected items that PAA believes impact comparability of financial results between reporting periods.

(2)����������� Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability.

Fourth-quarter 2014 Transportation adjusted segment profit increased 26% versus comparable 2013 results. This increase was primarily driven by higher crude oil pipeline volumes associated with North American crude oil production and recently completed organic growth projects, increased tariff rates on certain of our crude oil pipelines and the acquisition of a 50% interest in the BridgeTex pipeline completed in November�2014.

Fourth-quarter 2014 Facilities adjusted segment profit decreased 11% versus comparable 2013 results.� This decrease was primarily due to the impact of recontracting capacity originally contracted at higher rates within our natural gas storage operations.

� more �

333 Clay Street, Suite�1600��������� Houston, Texas 77002��������� (713) 646-4100 / (866) 809-1291



Page 3

Fourth-quarter 2014 Supply and Logistics adjusted segment profit decreased by approximately 17% relative to comparable 2013 results. This decrease was primarily related to less favorable NGL and crude oil market conditions in the fourth quarter of 2014 compared to the same 2013 period.� These impacts were partially offset by growth in crude oil lease gathering volumes.

Plains GP Holdings

PAGP�s sole assets are its ownership interest in PAA�s general partner and incentive distribution rights.� As the control entity of PAA, PAGP consolidates PAA�s results into its financial statements, which is reflected in the condensed consolidating balance sheet and income statement included at the end of this release.� Information regarding PAGP�s distributions is reflected below:

Summary Financial Information

Q4�2014

Q3�2014

Q4�2013
(non-prorated)�
(1)

Distribution per share declared for the period

$

0.20300

$

0.19075

$

0.15979

Q4 2014 distribution percentage growth over previous benchmarks

6.4

%

27.0

%


(1)����������� Reflects a full fourth quarter 2013 distribution per Class�A share (before proration), assuming PAGP�s ownership interest in PAA�s general partner was for the full fourth quarter of 2013.

Conference Call

PAA and PAGP will hold a conference call on February�5, 2015 (see details below).� Prior to this conference call, PAA will furnish a current report on Form�8-K, which will include material in this news release as well as PAA�s financial and operational guidance for the first quarter and full year of 2015.� A copy of the Form�8-K will be available at www.plainsallamerican.com, where PAA and PAGP routinely post important information.

The PAA and PAGP conference call will be held at 10:00�a.m. EST on Thursday, February�5, 2015 to discuss the following items:

1.������������� PAA�s fourth-quarter and full-year 2014 performance;

2.������������� The status of major expansion projects;

3.������������� Capitalization and liquidity;

4.������������� Financial and operating guidance for the first quarter and full year of 2015; and

5.������������� PAA�s and PAGP�s outlook for the future.

Conference Call Access Instructions

To access the Internet webcast of the conference call, please go to www.plainsallamerican.com, choose �Investor Relations,� and then choose �Events and Presentations.�� Following the live webcast, the call will be archived for a period of sixty (60) days on the website.

� more �

333 Clay Street, Suite�1600��������� Houston, Texas 77002��������� (713) 646-4100 / (866) 809-1291



Page 4

Alternatively, access to the live conference call is available by dialing toll free (800) 230-1085. International callers should dial (612) 288-0340.� No password is required.� The slide presentation accompanying the conference call will be available a few minutes prior to the call under the �Events and Presentations� tab of the PAA and PAGP Investor Relations sections of the above referenced website.

Telephonic Replay Instructions

To listen to a telephonic replay of the conference call, please dial (800) 475-6701, or (320) 365-3844 for international callers, and enter replay access code 349000.� The replay will be available beginning Thursday, February�5, 2015, at approximately 12:00�p.m. EST and will continue until 11:59�p.m. EST on March�5, 2015.

Non-GAAP Financial Measures and Selected Items Impacting Comparability

To supplement our financial information presented in accordance with GAAP, management uses additional measures that are known as �non-GAAP financial measures� (such as adjusted EBITDA and implied distributable cash flow (�DCF�)) in its evaluation of past performance and prospects for the future. Management believes that the presentation of such additional financial measures provides useful information to investors regarding our performance and results of operations because these measures, when used in conjunction with related GAAP financial measures, (i)�provide additional information about our core operating performance and ability to generate and distribute cash flow, (ii)�provide investors with the financial analytical framework upon which management bases financial, operational, compensation and planning decisions and (iii)�present measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These measures may exclude, for example, (i)�charges for obligations that are expected to be settled with the issuance of equity instruments, (ii)�the mark-to-market of derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), (iii) inventory valuation adjustments, (iv)�items that are not indicative of our core operating results and business outlook and/or (v)�other items that we believe should be excluded in understanding our core operating performance. We have defined all such items as �Selected Items Impacting Comparability.�� We consider an understanding of these selected items impacting comparability to be material to the evaluation of our operating results and prospects.

Although we present selected items that we consider in evaluating our performance, you should also be aware that the items presented do not represent all items that affect comparability between the periods presented. Variations in our operating results are also caused by changes in volumes, prices, exchange rates, mechanical interruptions, acquisitions and numerous other factors. These types of variations are not separately identified in this release, but will be discussed, as applicable, in management�s discussion and analysis of operating results in our Annual Report on Form�10-K.

Adjusted EBITDA and other non-GAAP financial measures are reconciled to the most comparable measures as reported in accordance with GAAP for the periods presented in the tables attached to this release, and should be viewed in addition to, and not in lieu of, our Consolidated Financial Statements and notes thereto. In addition, PAA maintains on its website (www.plainsallamerican.com) a reconciliation of adjusted EBITDA and certain commonly used non-GAAP financial information to the most comparable GAAP measures. To access the information, investors should click on �Plains All American Pipeline, L.P.� under the �Investor Relations� link on the home page, select the �Guidance�& Non-GAAP Reconciliations� link and navigate to the �Non-GAAP Reconciliations� tab.

� more �

333 Clay Street, Suite�1600��������� Houston, Texas 77002��������� (713) 646-4100 / (866) 809-1291



Page 5

Forward Looking Statements

Except for the historical information contained herein, the matters discussed in this release consist of forward-looking statements that involve certain risks and uncertainties that could cause actual results or outcomes to differ materially from results or outcomes anticipated in the forward-looking statements. These risks and uncertainties include, among other things, failure to implement or capitalize, or delays in implementing or capitalizing, on planned growth projects; declines in the volume of crude oil, refined product and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our facilities, whether due to declines in production from existing oil and gas reserves, failure to develop or slowdown in the development of additional oil and gas reserves, whether from reduced cash flow to fund drilling or the inability to access capital, or other factors; unanticipated changes in crude oil market structure, grade differentials and volatility (or lack thereof); environmental liabilities or events that are not covered by an indemnity, insurance or existing 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 effects of competition; the occurrence of a natural disaster, catastrophe, terrorist attack or other event, including attacks on our electronic and computer systems; tightened capital markets or other factors that increase our cost of capital or limit 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; weather interference with business operations or project construction, including the impact of extreme weather events or conditions; continued creditworthiness of, and performance by, our counterparties, including financial institutions and trading companies with which we do business; maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties; the currency exchange rate of the Canadian dollar; the availability of, and our ability to consummate, acquisition or combination opportunities; 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; the effectiveness of our risk management activities; shortages or cost increases of supplies, materials or labor; the impact of current and future laws, rulings, governmental regulations, accounting standards and statements and related interpretations; non-utilization of our assets and facilities; 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; risks related to the development and operation of our facilities, including our ability to satisfy our contractual obligations to our customers at our facilities; factors affecting demand for natural gas and natural gas storage services and rates; general economic, market or business conditions and the amplification of other risks caused by volatile financial markets, capital constraints and pervasive liquidity concerns; and other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil and refined products, as well as in the storage of natural gas and the processing, transportation, fractionation, storage and marketing of natural gas liquids as discussed in the Partnerships� filings with the Securities and Exchange Commission.

� more �

333 Clay Street, Suite�1600��������� Houston, Texas 77002��������� (713) 646-4100 / (866) 809-1291



Page 6

Plains All American Pipeline, L.P. is a publicly traded master limited partnership that owns and operates midstream energy infrastructure and provides logistics services for crude oil, natural gas liquids (�NGL�), natural gas and refined products. PAA owns an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. On average, PAA handles over 4.1 million barrels per day of crude oil and NGL on its pipelines. PAA is headquartered in Houston, Texas.

Plains GP Holdings is a publicly traded entity that owns an interest in the general partner and incentive distribution rights of Plains All American Pipeline, L.P., one of the largest energy infrastructure and logistics companies in North America. PAGP is headquartered in Houston, Texas.

� more �

333 Clay Street, Suite�1600��������� Houston, Texas 77002��������� (713) 646-4100 / (866) 809-1291



Page 7

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

Three�Months�Ended

Twelve�Months�Ended

December�31,

December�31,

2014

2013

2014

2013

REVENUES

$

9,459

$

10,631

$

43,464

$

42,249

COSTS AND EXPENSES

Purchases and related costs

8,384

9,731

39,500

38,465

Field operating costs

378

312

1,456

1,322

General and administrative expenses

67

84

325

359

Depreciation and amortization

100

110

392

375

Total costs and expenses

8,929

10,237

41,673

40,521

OPERATING INCOME

530

394

1,791

1,728

OTHER INCOME/(EXPENSE)

Equity earnings in unconsolidated entities

35

22

108

64

Interest expense, net

(93

)

(79

)

(340

)

(303

)

Other income/(expense), net

(1

)

(2

)

1

INCOME BEFORE TAX

471

337

1,557

1,490

Current income tax expense

(9

)

(31

)

(71

)

(100

)

Deferred income tax benefit/(expense)

(72

)

12

(100

)

1

NET INCOME

390

318

1,386

1,391

Net income attributable to noncontrolling interests

(1

)

(9

)

(2

)

(30

)

NET INCOME ATTRIBUTABLE TO PAA

$

389

$

309

$

1,384

$

1,361

NET INCOME ATTRIBUTABLE TO PAA:

LIMITED PARTNERS

$

253

$

203

$

884

$

967

GENERAL PARTNER

$

136

$

106

$

500

$

394

BASIC NET INCOME PER LIMITED PARTNER UNIT

$

0.67

$

0.59

$

2.39

$

2.82

DILUTED NET INCOME PER LIMITED PARTNER UNIT

$

0.67

$

0.58

$

2.38

$

2.80

BASIC WEIGHTED AVERAGE LIMITED PARTNER UNITS OUTSTANDING

373

344

367

341

DILUTED WEIGHTED AVERAGE LIMITED PARTNER UNITS OUTSTANDING

375

346

369

343

ADJUSTED RESULTS

(in millions, except per unit data)

Three�Months�Ended

Twelve�Months�Ended

December�31,

December�31,

2014

2013

2014

2013

ADJUSTED NET INCOME ATTRIBUTABLE TO PAA

$

362

$

371

$

1,347

$

1,466

DILUTED ADJUSTED NET INCOME PER LIMITED PARTNER UNIT

$

0.60

$

0.76

$

2.28

$

3.10

ADJUSTED EBITDA

$

594

$

595

$

2,200

$

2,292

� more �

333 Clay Street, Suite�1600��������� Houston, Texas 77002��������� (713) 646-4100 / (866) 809-1291



Page 8

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

CONDENSED CONSOLIDATED BALANCE SHEET DATA

(in millions)

December�31,

December�31,

2014

2013

ASSETS

Current assets

$

4,179

$

4,964

Property and equipment, net

12,272

10,819

Goodwill

2,465

2,503

Investments in unconsolidated entities

1,735

485

Linefill and base gas

930

798

Long-term inventory

186

251

Other, net

489

540

Total assets

$

22,256

$

20,360

LIABILITIES AND PARTNERS� CAPITAL

Current liabilities

$

4,755

$

5,411

Senior notes, net of unamortized discount

8,757

6,710

Other long-term debt

5

5

Other long-term liabilities and deferred credits

548

531

Total liabilities

14,065

12,657

Partners� capital excluding noncontrolling interests

8,133

7,644

Noncontrolling interests

58

59

Total partners� capital

8,191

7,703

Total liabilities and partners� capital

$

22,256

$

20,360

DEBT CAPITALIZATION RATIOS

(in millions)

December�31,

December�31,

2014

2013

Short-term debt

$

1,287

$

1,113

Long-term debt

8,762

6,715

Total debt

$

10,049

$

7,828

Long-term debt

$

8,762

$

6,715

Partners� capital

8,191

7,703

Total book capitalization

$

16,953

$

14,418

Total book capitalization, including short-term debt

$

18,240

$

15,531

Long-term debt-to-total book capitalization

52

%

47

%

Total debt-to-total book capitalization, including short-term debt

55

%

50

%

� more �

333 Clay Street, Suite�1600��������� Houston, Texas 77002��������� (713) 646-4100 / (866) 809-1291



Page 9

PLAINS�ALL�AMERICAN�PIPELINE,�L.P.�AND�SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

SELECTED FINANCIAL DATA BY SEGMENT

(in millions)

Three�Months�Ended

Three�Months�Ended

December�31,�2014

December�31,�2013

Supply�and

Supply�and

Transportation

Facilities

Logistics

Transportation

Facilities

Logistics

Revenues (1)

$

433

$

270

$

9,129

$

387

$

394

$

10,151

Purchases and related costs (1)

(35

)

(8

)

(8,711

)

(38

)

(116

)

(9,875

)

Field operating costs (1)�(2)

(142

)

(97

)

(141

)

(125

)

(89

)

(97

)

Equity-indexed compensation expense - operations

(1

)

(3

)

(1

)

Segment general and administrative expenses (2) (3)

(20

)

(14

)

(26

)

(29

)

(16

)

(23

)

Equity-indexed compensation expense - general and administrative

(3

)

(2

)

(2

)

(7

)

(2

)

(7

)

Equity earnings in unconsolidated entities

35

22

Reported segment profit

$

267

$

149

$

249

$

207

$

170

$

149

Selected items impacting comparability of segment profit (4)

3

2

(76

)

7

(1

)

60

Adjusted segment profit

$

270

$

151

$

173

$

214

$

169

$

209

Maintenance capital

$

54

$

17

$

2

$

36

$

13

$

3

Twelve�Months�Ended

Twelve�Months�Ended

December�31,�2014

December�31,�2013

Supply�and

Supply�and

Transportation

Facilities

Logistics

Transportation

Facilities

Logistics

Revenues (1)

$

1,655

$

1,127

$

42,150

$

1,498

$

1,377

$

40,696

Purchases and related costs (1)

(151

)

(55

)

(40,752

)

(147

)

(312

)

(39,315

)

Field operating costs (1) (2)

(560

)

(404

)

(481

)

(528

)

(362

)

(422

)

Equity-indexed compensation expense - operations

(15

)

(4

)

(2

)

(18

)

(2

)

(3

)

Segment general and administrative expenses (2) (3)

(83

)

(60

)

(105

)

(101

)

(63

)

(102

)

Equity-indexed compensation expense - general and administrative

(29

)

(20

)

(28

)

(39

)

(22

)

(32

)

Equity earnings in unconsolidated entities

108

64

Reported segment profit

$

925

$

584

$

782

$

729

$

616

$

822

Selected items impacting comparability of segment profit (4)

25

13

(131

)

31

13

71

Adjusted segment profit

$

950

$

597

$

651

$

760

$

629

$

893

Maintenance capital

$

165

$

52

$

7

$

123

$

38

$

15


(1)������������������������������������ Includes intersegment amounts.

(2)������������������������������������ Field operating costs and Segment general and administrative expenses exclude equity-indexed compensation expense, which is presented separately in the table above.

(3)������������������������������������ Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period.

(4)������������������������������������ Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability.

� more �

333 Clay Street, Suite�1600��������� Houston, Texas 77002��������� (713) 646-4100 / (866) 809-1291



Page 10

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

OPERATING DATA (1)

Three�Months�Ended

Twelve�Months�Ended

December�31,

December�31,

2014

2013

2014

2013

Transportation activities (average daily volumes in thousands of barrels per day):

Tariff activities

Crude Oil Pipelines

All American

36

40

37

40

Bakken Area Systems

157

135

149

131

Basin / Mesa / Sunrise

732

737

733

718

BridgeTex

55

14

Capline

182

144

152

151

Eagle Ford Area Systems

262

166

227

102

Line 63 / Line 2000

129

113

122

113

Manito

55

44

47

46

Mid-Continent Area Systems

370

293

348

281

Permian Basin Area Systems

764

703

765

581

Rainbow

117

120

112

124

Rangeland

65

64

65

60

Salt Lake City Area Systems

143

128

136

131

South Saskatchewan

66

57

62

51

White Cliffs

40

25

30

23

Other

829

688

767

725

NGL Pipelines

Co-Ed

61

58

58

56

Other

129

206

128

194

Refined Products Pipelines

9

68

Tariff activities total

4,192

3,730

3,952

3,595

Trucking

122

129

127

117

Transportation activities total

4,314

3,859

4,079

3,712

Facilities activities (average monthly volumes):

Crude oil, refined products and NGL terminalling and storage (average monthly capacity in millions of barrels)

95

94

95

94

Rail load / unload volumes (average volumes in thousands of barrels per day)

229

221

231

221

Natural gas storage (average monthly working capacity in billions of cubic feet)

97

97

97

96

NGL fractionation (average volumes in thousands of barrels per day)

103

89

96

96

Facilities activities total (average monthly volumes in millions of barrels) (2)

122

120

121

120

Supply and Logistics activities (average daily volumes in thousands of barrels per day):

Crude oil lease gathering purchases

999

870

949

859

NGL sales

268

272

208

215

Waterborne cargos

4

Supply and Logistics activities total

1,267

1,142

1,157

1,078


(1)������������������������������������ Volumes associated with assets employed through acquisitions and expansion capital represent total volumes (attributable to our interest) for the number of days or months we employed the assets divided by the number of days or months in the period.

(2)������������������������������������ Facilities activities total is calculated as the sum of: (i)�crude oil, refined products and NGL terminalling and storage capacity; (ii)�rail load and unload volumes multiplied by the number of days in the period and divided by the number of months in the period; (iii)�natural gas storage working capacity divided by 6 to account for the 6:1� mcf of natural gas to crude Btu equivalent ratio and further divided by 1,000 to convert to monthly volumes in millions; and (iv)�NGL fractionation volumes multiplied by the number of days in the period and divided by the number of months in the period.

� more �

333 Clay Street, Suite�1600��������� Houston, Texas 77002��������� (713) 646-4100 / (866) 809-1291



Page 11

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

COMPUTATION OF BASIC AND DILUTED NET INCOME PER LIMITED PARTNER UNIT

(in millions, except per unit data)

Three�Months�Ended

Twelve�Months�Ended

December�31,

December�31,

2014

2013

2014

2013

Basic Net Income per Limited Partner Unit

Net income attributable to PAA

$

389

$

309

$

1,384

$

1,361

Less: General partner�s incentive distribution (1)

(131

)

(102

)

(482

)

(375

)

Less: General partner 2% ownership (1)

(5

)

(4

)

(18

)

(19

)

Net income available to limited partners

253

203

884

967

Less: Undistributed earnings allocated and distributions to participating securities (1)

(2

)

(2

)

(6

)

(7

)

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

$

251

$

201

$

878

$

960

Basic weighted average limited partner units outstanding

373

344

367

341

Basic net income per limited partner unit

$

0.67

$

0.59

$

2.39

$

2.82

Diluted Net Income per Limited Partner Unit

Net income attributable to PAA

$

389

$

309

$

1,384

$

1,361

Less: General partner�s incentive distribution (1)

(131

)

(102

)

(482

)

(375

)

Less: General partner 2% ownership (1)

(5

)

(4

)

(18

)

(19

)

Net income available to limited partners

253

203

884

967

Less: Undistributed earnings allocated and distributions to participating securities (1)

(2

)

(2

)

(6

)

(6

)

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

$

251

$

201

$

878

$

961

Basic weighted average limited partner units outstanding

373

344

367

341

Effect of dilutive securities: Weighted average LTIP units (2)

2

2

2

2

Diluted weighted average limited partner units outstanding

375

346

369

343

Diluted net income per limited partner unit

$

0.67

$

0.58

$

2.38

$

2.80


(1)������������������������������������ We calculate net income available to limited partners based on the distributions pertaining to the current period�s net income.� After adjusting for the appropriate period�s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner, limited partners and participating securities in accordance with the contractual terms of the partnership agreement and as further prescribed under the two-class method.

(2)������������������������������������ Our Long-term Incentive Plan (�LTIP�) awards that contemplate the issuance of common units are considered dilutive unless (i)�vesting occurs only upon the satisfaction of a performance condition and (ii)�that performance condition has yet to be satisfied. LTIP awards that are deemed to be dilutive are reduced by a hypothetical unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.

� more �

333 Clay Street, Suite�1600��������� Houston, Texas 77002��������� (713) 646-4100 / (866) 809-1291



Page 12

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

SELECTED ITEMS IMPACTING COMPARABILITY

(in millions, except per unit data)

Three�Months�Ended

Twelve�Months�Ended

December�31,

December�31,

2014

2013

2014

2013

Selected Items Impacting Comparability - Income/(Loss) (1):

Gains/(losses) from derivative activities net of inventory valuation adjustments (2)

$

166

$

(51

)

$

243

$

(59

)

Long-term inventory valuation adjustments (3)

(85

)

(85

)

Equity-indexed compensation expense (4)

(8

)

(12

)

(56

)

(63

)

Net loss on foreign currency revaluation

(3

)

(7

)

(13

)

(1

)

Tax effect on selected items impacting comparability

(43

)

8

(52

)

16

Other (5)

2

Selected items impacting comparability of net income attributable to PAA

$

27

$

(62

)

$

37

$

(105

)

Impact to basic net income per limited partner unit

$

0.07

$

(0.17

)

$

0.10

$

(0.30

)

Impact to diluted net income per limited partner unit

$

0.07

$

(0.18

)

$

0.10

$

(0.30

)


(1)������������������������������������ Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability.

(2)������������������������������������ Includes mark-to-market gains and losses resulting from derivative instruments that are related to underlying activities in future periods or the reversal of mark-to-market gains and losses from the prior period, net of inventory valuation adjustments, as applicable.

(3)������������������������������������ Includes changes in the average cost of long-term inventory that result from fluctuations in market prices. Long-term inventory is comprised of minimum inventory requirements in third-party assets and other working inventory that is needed for our commercial operations.

(4)������������������������������������ Includes equity-indexed compensation expense associated with LTIP awards that will or may be settled in units, as the dilutive impact of these outstanding awards is included in our diluted net income per unit calculation and the majority of these awards are expected to be settled in units.

(5)������������������������������������ Includes other immaterial selected items impacting comparability, as well as the noncontrolling interests� portion of selected items.

� more �

333 Clay Street, Suite�1600��������� Houston, Texas 77002��������� (713) 646-4100 / (866) 809-1291



Page 13

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

COMPUTATION OF ADJUSTED BASIC AND DILUTED EARNINGS PER LIMITED PARTNER UNIT

(in millions, except per unit data)

Three�Months�Ended

Twelve�Months�Ended

December�31,

December�31,

2014

2013

2014

2013

Basic Adjusted Net Income per Limited Partner Unit

Net income attributable to PAA

$

389

$

309

$

1,384

$

1,361

Selected items impacting comparability of net income attributable�to�PAA�(1)

(27

)

62

(37

)

105

Adjusted net income attributable to PAA

362

371

1,347

1,466

Less: General partner�s incentive distribution (2)

(131

)

(102

)

(482

)

(375

)

Less: General partner 2% ownership (2)

(4

)

(5

)

(17

)

(22

)

Adjusted net income available to limited partners

227

264

848

1,069

Less: Undistributed earnings allocated and distributions to participating securities (2)

(2

)

(2

)

(6

)

(7

)

Adjusted limited partners� net income

$

225

$

262

$

842

$

1,062

Basic weighted average limited partner units outstanding

373

344

367

341

Basic adjusted net income per limited partner unit

$

0.60

$

0.76

$

2.29

$

3.12

Diluted Adjusted Net Income per Limited Partner Unit

Net income attributable to PAA

$

389

$

309

$

1,384

$

1,361

Selected items impacting comparability of net income attributable�to�PAA�(1)

(27

)

62

(37

)

105

Adjusted net income attributable to PAA

362

371

1,347

1,466

Less: General partner�s incentive distribution (2)

(131

)

(102

)

(482

)

(375

)

Less: General partner 2% ownership (2)

(4

)

(5

)

(17

)

(22

)

Adjusted net income available to limited partners

227

264

848

1,069

Less: Undistributed earnings allocated and distributions to participating securities (2)

(2

)

(2

)

(6

)

(5

)

Adjusted limited partners� net income

$

225

$

262

$

842

$

1,064

Diluted weighted average limited partner units outstanding

375

346

369

343

Diluted adjusted net income per limited partner unit

$

0.60

$

0.76

$

2.28

$

3.10


(1)������������ Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability.

(2)������������ We calculate adjusted net income available to limited partners based on the distributions pertaining to the current period�s net income.� After adjusting for the appropriate period�s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner, limited partners and participating securities in accordance with the contractual terms of the partnership agreement and as further prescribed under the two-class method.

� more �

333 Clay Street, Suite�1600��������� Houston, Texas 77002��������� (713) 646-4100 / (866) 809-1291



Page 14

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

FINANCIAL DATA RECONCILIATIONS

(in millions)

Three�Months�Ended

Twelve�Months�Ended

December�31,

December�31,

2014

2013

2014

2013

Net Income to Earnings Before Interest, Taxes, Depreciation and Amortization (�EBITDA�) and Excluding Selected Items Impacting Comparability (�Adjusted EBITDA�) Reconciliations

Net Income

$

390

$

318

$

1,386

$

1,391

Add: Interest expense, net

93

79

340

303

Add: Income tax expense

81

19

171

99

Add: Depreciation and amortization

100

110

392

375

EBITDA

$

664

$

526

$

2,289

$

2,168

Selected items impacting comparability of EBITDA (1)

(70

)

69

(89

)

124

Adjusted EBITDA

$

594

$

595

$

2,200

$

2,292


(1)������������������ Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability.

Three�Months�Ended

Twelve�Months�Ended

December�31,

December�31,

2014

2013

2014

2013

Adjusted EBITDA to Implied Distributable Cash Flow (�DCF�)

Adjusted EBITDA

$

594

$

595

$

2,200

$

2,292

Interest expense, net

(93

)

(79

)

(340

)

(303

)

Maintenance capital

(73

)

(52

)

(224

)

(176

)

Current income tax expense

(9

)

(31

)

(71

)

(100

)

Equity earnings in unconsolidated entities, net of distributions

(4

)

(3

)

(3

)

(10

)

Distributions to noncontrolling interests (1)

(1

)

(1

)

(3

)

(38

)

Implied DCF

$

414

$

429

$

1,559

$

1,665


(1)������������������ Includes distributions that pertain to the current period�s net income, which are paid in the subsequent period.

Three�Months�Ended

Twelve�Months�Ended

December�31,

December�31,

2014

2013

2014

2013

Cash Flow from Operating Activities Reconciliation

EBITDA

$

664

$

526

$

2,289

$

2,168

Current income tax expense

(9

)

(31

)

(71

)

(100

)

Interest expense, net

(93

)

(79

)

(340

)

(303

)

Net change in assets and liabilities, net of acquisitions

156

(76

)

28

73

Other items to reconcile to cash flows from operating activities:

Equity-indexed compensation expense

8

20

98

116

Net cash provided by operating activities

$

726

$

360

$

2,004

$

1,954

� more �

333 Clay Street, Suite�1600��������� Houston, Texas 77002��������� (713) 646-4100 / (866) 809-1291



Page 15

PLAINS GP HOLDINGS AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(in millions, except per share data)

Three�Months�Ended

Twelve�Months�Ended

December�31,�2014

December�31,�2014

PAA

Consolidating
Adjustments�
(1)

PAGP

PAA

Consolidating
Adjustments�
(1)

PAGP

REVENUES

$

9,459

$

$

9,459

$

43,464

$

$

43,464

COSTS AND EXPENSES

Purchases and related costs

8,384

8,384

39,500

39,500

Field operating costs

378

378

1,456

1,456

General and administrative expenses

67

3

70

325

6

331

Depreciation and amortization

100

100

392

2

394

Total costs and expenses

8,929

3

8,932

41,673

8

41,681

OPERATING INCOME

530

(3

)

527

1,791

(8

)

1,783

OTHER INCOME/(EXPENSE)

Equity earnings in unconsolidated entities

35

35

108

108

Interest expense, net

(93

)

(3

)

(96

)

(340

)

(9

)

(349

)

Other expense, net

(1

)

(1

)

(2

)

(2

)

INCOME BEFORE TAX

471

(6

)

465

1,557

(17

)

1,540

Current income tax expense

(9

)

(9

)

(71

)

(71

)

Deferred income tax expense

(72

)

(14

)

(86

)

(100

)

(41

)

(141

)

NET INCOME

390

(20

)

370

1,386

(58

)

1,328

Net income attributable to noncontrolling interests

(1

)

(345

)

(346

)

(2

)

(1,256

)

(1,258

)

NET INCOME ATTRIBUTABLE TO PAGP

$

389

$

(365

)

$

24

$

1,384

$

(1,314

)

$

70

BASIC NET INCOME PER CLASS�A SHARE

$

0.14

$

0.48

DILUTED NET INCOME PER CLASS�A SHARE

$

0.13

$

0.47

BASIC WEIGHTED AVERAGE CLASS�A SHARES OUTSTANDING

172

145

DILUTED WEIGHTED AVERAGE CLASS�A SHARES OUTSTANDING

650

650


(1)������������������ Represents the aggregate consolidating adjustments necessary to produce consolidated financial statements for PAGP.

� more �

333 Clay Street, Suite�1600��������� Houston, Texas 77002��������� (713) 646-4100 / (866) 809-1291



Page 16

PLAINS GP HOLDINGS AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

CONDENSED CONSOLIDATING BALANCE SHEET DATA

(in millions)

December�31,�2014

PAA

Consolidating
Adjustments�
(1)

PAGP

ASSETS

Current assets

$

4,179

$

2

$

4,181

Property and equipment, net

12,272

20

12,292

Goodwill

2,465

2,465

Investments in unconsolidated entities

1,735

1,735

Deferred tax asset

1,705

1,705

Linefill and base gas

930

930

Long-term inventory

186

186

Other, net

489

489

Total assets

$

22,256

$

1,727

$

23,983

LIABILITIES AND PARTNERS� CAPITAL

Current liabilities

$

4,755

$

1

$

4,756

Senior notes, net of unamortized discount

8,757

8,757

Other long-term debt

5

536

541

Other long-term liabilities and deferred credits

548

548

Total liabilities

14,065

537

14,602

Partners� capital excluding noncontrolling interests

8,133

(6,476

)

1,657

Noncontrolling interests

58

7,666

7,724

Total partners� capital

8,191

1,190

9,381

Total liabilities and partners� capital

$

22,256

$

1,727

$

23,983


(1)������������������ Represents the aggregate consolidating adjustments necessary to produce consolidated financial statements for PAGP.

� more �

333 Clay Street, Suite�1600��������� Houston, Texas 77002��������� (713) 646-4100 / (866) 809-1291



Page 17

PLAINS GP HOLDINGS AND SUBSIDIARIES

DISTRIBUTION SUMMARY (unaudited)

Q4 2014 PAGP DISTRIBUTION SUMMARY

(in millions, except per unit and per share data)

Q4�2014�(1)

PAA Distribution/LP Unit

$

0.6750

GP Distribution/LP Unit

$

0.3614

Total Distribution/LP Unit

$

1.0364

PAA LP Units Outstanding at 1/30/15

376

Gross GP Distribution

$

141

Less: IDR Reduction

(6

)

Net Distribution from PAA to AAP (2)

$

136

Less: Debt Service

(2

)

Less: G&A Expense

(1

)

Cash Available for Distribution by AAP

$

133

Distributions to AAP Partners

Direct AAP Owners�& AAP Management (68.2% economic interest)

$

91

PAGP (31.8% economic interest)

42

Total distributions to AAP Partners

$

133

Distribution to PAGP Investors

$

42

PAGP Class�A Shares Outstanding at 1/30/15

207

PAGP Distribution/Class�A Share

$

0.20300


(1)������������������ Amounts may not recalculate due to rounding.

(2)������������������ Plains AAP, L.P. (�AAP�) is the general partner of PAA.

� more �

333 Clay Street, Suite�1600��������� Houston, Texas 77002��������� (713) 646-4100 / (866) 809-1291



Page 18

PLAINS GP HOLDINGS AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

COMPUTATION OF BASIC AND DILUTED NET INCOME PER CLASS�A SHARE

(in millions, except per share data)

Three�Months�Ended

Twelve�Months�Ended

December�31,�2014

December�31,�2014

Basic Net Income per Class�A Share

Net income attributable to PAGP

$

24

$

70

Basic weighted average Class�A shares outstanding

172

145

Basic net income per Class�A share

$

0.14

$

0.48

Diluted Net Income per Class�A Share

Numerator for diluted net income per Class�A share:

Net income attributable to PAGP

$

24

$

70

Incremental net income attributable to PAGP resulting from assumed conversion of AAP units and AAP Management units

58

235

Total

$

82

$

305

Denominator for diluted net income per Class�A share:

Basic weighted average number of Class�A shares outstanding

172

145

Dilutive shares resulting from assumed conversion of AAP units and AAP Management units

478

505

Effect of dilutive securities: Weighted average LTIP shares (1)

Diluted weighted average number of Class�A shares outstanding

650

650

Diluted net income per Class�A share

$

0.13

$

0.47


(1)������������������ As of December�31, 2014, there were less than 0.1 million weighted average dilutive LTIP shares outstanding.

Contacts:

Ryan Smith

Al Swanson

Director,�Investor Relations

Executive Vice President, CFO

(866) 809-1291

(800) 564-3036

###

333 Clay Street, Suite 1600��������� Houston, Texas 77002������� ��(713) 646-4100 / (866) 809-1291




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