News Column

PLAINS ALL AMERICAN PIPELINE LP - 10-Q - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

August 8, 2014

Introduction

The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical Consolidated Financial Statements and accompanying notes and Management's Discussion and Analysis of Financial Condition and Results of Operations as presented in our 2013 Annual Report on Form 10-K. For more detailed information regarding the basis of presentation for the following financial information, see the condensed consolidated financial statements and related notes that are contained in Part I, Item 1 of this Quarterly Report on Form 10-Q.



Our discussion and analysis includes the following:

Executive Summary Acquisitions and Internal Growth Projects Results of Operations Liquidity and Capital Resources Off-Balance Sheet Arrangements Recent Accounting Pronouncements Critical Accounting Policies and Estimates Forward-Looking Statements Executive Summary Company Overview We own and operate midstream energy infrastructure and provide logistics services for crude oil, NGL, natural gas and refined products. We own 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. We were formed in 1998, and our operations are conducted directly and indirectly through our operating subsidiaries and are managed through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics.



Overview of Operating Results, Capital Investments and Significant Activities

During the first six months of 2014, we recognized net income attributable to PAA of approximately $671 million, or $1.18 per diluted limited partner unit, as compared to net income attributable to PAA of approximately $821 million, or $1.84 per diluted limited partner unit, recognized during the first six months of 2013. These decreases were primarily driven by less favorable crude oil market conditions experienced during the 2014 period, most notably during the comparative first quarter period, which provided fewer opportunities for above-baseline crude oil margins in our Supply and Logistics segment. In addition, our Facilities and Supply and Logistics segments were negatively impacted by costs incurred in our natural gas storage activities to manage deliverability requirements in conjunction with the severe cold weather experienced during the first several months of 2014. However, such decreases were partially offset by favorable results from our Transportation segment, largely due to the continued increase in North American crude oil production and our related, recently completed internal growth projects. 28 --------------------------------------------------------------------------------



Table of Contents

Acquisitions and Internal Growth Projects

The following table summarizes our capital expenditures for acquisitions, internal growth projects and maintenance capital for the periods indicated (in millions): Six Months Ended June 30, 2014 2013 Acquisition capital $ 2 $ 1 Internal growth projects 1,012 830 Maintenance capital 95 82 Total $ 1,109$ 913 Internal Growth Projects The following table summarizes our more notable projects in progress during 2014 and the forecasted expenditures for the year ending December 31, 2014 (in millions): Projects 2014 Permian Basin Area Projects $480 Cactus Pipeline 350 Rail Terminal Projects (1) 220 Ft. Sask Facility Projects / NGL Line 135 Western Oklahoma Extension 80 Eagle Ford JV Project 65 Mississippian Lime Pipeline 50 White Cliffs Expansion 40 Line 63 Reactivation 35 Natural Gas Storage Expansions 35 Other Projects 460 $1,950



Potential Adjustments for Timing / Scope Refinement (2) -$100 + $100 Total Projected Expansion Capital Expenditures

$1,850 - $2,050 -------------------------------------------------------------------------------- (1) Includes projects located in or near Bakersfield, CA;



Carr, CO; Van Hook, ND; and Kerrobert, Canada.

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



Analysis of Operating Segments

We manage our operations through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. Our Chief Operating Decision Maker (our Chief Executive Officer) evaluates such segment performance based on a variety of measures including segment profit, segment volumes, segment profit per barrel and maintenance capital investment. See Note 18 to our Consolidated Financial Statements included in Part IV of our 2013 Annual Report on Form 10-K for further discussion of how we evaluate segment profit. 29 --------------------------------------------------------------------------------



Table of Contents

The following table sets forth an overview of our consolidated financial results calculated in accordance with GAAP (in millions, except per unit amounts):

Favorable/ Favorable/ Three Months Ended (Unfavorable) Six Months Ended (Unfavorable) June 30, Variance June 30, Variance 2014 2013 $ % 2014 2013 $ % Transportation segment profit $ 221$ 160$ 61 38 % $ 427$ 323$ 104 32 % Facilities segment profit 134 149 (15 ) (10 )% 288 300 (12 ) (4 )% Supply and Logistics segment profit 133 176 (43 ) (24 )% 382 610 (228 ) (37 )% Total segment profit 488 485 3 1 % 1,097 1,233 (136 ) (11 )% Depreciation and amortization (100 ) (91 ) (9 ) (10 )% (196 ) (173 ) (23 ) (13 )% Interest expense, net (82 ) (75 ) (7 ) (9 )% (161 ) (152 ) (9 ) (6 )% Other income/(expense), net 4 (1 ) 5 500 % 2 (1 ) 3 300 % Income tax expense (22 ) (18 ) (4 ) (22 )% (70 ) (70 ) - - % Net income 288 300 (12 ) (4 )% 672 837 (165 ) (20 )% Net income attributable to noncontrolling interests (1 ) (8 ) 7 88 % (1 ) (16 ) 15 94 % Net income attributable to PAA $ 287$ 292$ (5 ) (2 )% $ 671$ 821$ (150 ) (18 )% Net income attributable to PAA: Basic net income per limited partner unit $ 0.45$ 0.58$ (0.13 ) (22 )% $ 1.19$ 1.85$ (0.66 ) (36 )% Diluted net income per limited partner unit $ 0.45$ 0.57$ (0.12 ) (21 )% $ 1.18$ 1.84$ (0.66 ) (36 )% Basic weighted average units outstanding 365 340 25 7 % 363 338 25 7 % Diluted weighted average units outstanding 367 342 25 7 % 365 341 24 7 % Non-GAAP Financial Measures To supplement our financial information presented in accordance with GAAP, management uses additional measures that are known as "non-GAAP financial measures" in its evaluation of past performance and prospects for the future. The primary additional measures used by management are adjusted earnings before interest, taxes, depreciation and amortization ("adjusted EBITDA") and implied distributable cash flow ("DCF"). 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 adjustment of derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), (iii) items that are not indicative of our core operating results and business outlook and/or (iv) other items that we believe should be excluded in understanding our core operating performance. We have defined all such items hereinafter as "Selected Items Impacting Comparability." These additional financial measures are reconciled to the most directly comparable measures as reported in accordance with GAAP, and should be viewed in addition to, and not in lieu of, our condensed consolidated financial statements and footnotes. 30 --------------------------------------------------------------------------------



Table of Contents

The following table sets forth non-GAAP financial measures that are reconciled to the most directly comparable GAAP measures (in millions):

Favorable/ Favorable/ Three Months Ended (Unfavorable) Six Months Ended (Unfavorable) June 30, Variance June 30, Variance 2014 2013 $ % 2014 2013 $ % Net income $ 288$ 300$ (12 ) (4 )% $ 672$ 837$ (165 ) (20 )% Add: Depreciation and amortization 100 91 9 10 % 196 173 23 13 % Income tax expense 22 18 4 22 % 70 70 - - % Interest expense, net 82 75 7 9 % 161 152 9 6 % EBITDA $ 492$ 484$ 8 2 % $ 1,099$ 1,232$ (133 ) (11 )% Selected Items Impacting Comparability of EBITDA Gains/(losses) from derivative activities net of inventory valuation adjustments (1) $ (14 )$ 26$ (40 ) (154 )% $ 50$ 50 $ - - % Equity-indexed compensation expense (2) (17 ) (16 ) (1 ) (6 )% (36 ) (39 ) 3 8 % Net gain/(loss) on foreign currency revaluation (3) 11 (4 ) 15 375 % 6 4 2 50 % Selected Items Impacting Comparability of EBITDA $ (20 )$ 6$ (26 ) (433 )% $ 20$ 15$ 5 33 % EBITDA $ 492$ 484$ 8 2 % $ 1,099$ 1,232$ (133 ) (11 )% Selected Items Impacting Comparability of EBITDA 20 (6 ) 26 433 % (20 ) (15 ) (5 ) (33 )% Adjusted EBITDA $ 512$ 478$ 34 7 % $ 1,079$ 1,217$ (138 ) (11 )% Adjusted EBITDA $ 512$ 478$ 34 7 % $ 1,079$ 1,217$ (138 ) (11 )% Interest expense, net (82 ) (75 ) (7 ) (9 )% (161 ) (152 ) (9 ) (6 )% Maintenance capital (4) (48 ) (39 ) (9 ) (23 )% (95 ) (82 ) (13 ) (16 )% Current income tax expense (16 ) (8 ) (8 ) (100 )% (52 ) (53 ) 1 2 % Equity earnings in unconsolidated entities, net of distributions 2 (1 ) 3 300 % 7 (1 ) 8 800 % Distributions to noncontrolling interests (5) (1 ) (13 ) 12 92 % (2 ) (25 ) 23 92 % Implied DCF $ 367$ 342$ 25 7 % $ 776$ 904$ (128 ) (14 )% Less: Distributions paid (5) (360 ) (296 ) (704 ) (581 ) DCF Excess/(Shortage) (6) $ 7$ 46$ 72$ 323

-------------------------------------------------------------------------------- (1) We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results of operations, we identify the earnings that were recognized during the period related to derivative instruments for which the identified underlying transaction does not occur in the current period and exclude the related gains and losses in determining Adjusted EBITDA. We also exclude the impact of corresponding inventory valuation adjustments, as applicable. See Note 10 to our condensed consolidated financial statements for a comprehensive discussion regarding our derivatives and risk management activities. 31

--------------------------------------------------------------------------------



Table of Contents

(2) Our total equity-indexed compensation expense includes expense associated with awards that will or may be settled in units and awards that will or may be settled in cash. The awards that will or may be settled in units are included in our diluted earnings per unit calculation when the applicable performance criteria have been met. We consider the compensation expense associated with these awards as a selected item impacting comparability as the dilutive impact of the outstanding awards is included in our diluted earnings per unit calculation and the majority of the awards are expected to be settled in units. The portion of compensation expense associated with awards that are certain to be settled in cash is not considered a selected item impacting comparability. See Note 15 to our Consolidated Financial Statements included in Part IV of our 2013 Annual Report on Form 10-K for a comprehensive discussion regarding our equity-indexed compensation plans. (3) During the three and six months ended June 30, 2014 and 2013, there were fluctuations in the value of the Canadian dollar ("CAD") to the U.S. dollar ("USD"), resulting in gains and losses that were not related to our core operating results for the period and were thus classified as selected items impacting comparability. See Note 10 to our condensed consolidated financial statements for further discussion regarding our currency exchange rate risk hedging activities.



(4) Maintenance capital expenditures are defined as capital expenditures for the replacement of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets.

(5) Includes distributions that pertain to the current period's net income and are paid in the subsequent period.

(6) Excess DCF is retained to establish reserves for future distributions, capital expenditures and other partnership purposes.

Transportation Segment 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 leases of pipeline capacity and other transportation fees. The following table sets forth operating results from our Transportation segment for the periods indicated: Favorable/ Favorable/ Three Months Ended (Unfavorable) Six Months Ended (Unfavorable) Operating Results (1) June 30, Variance June 30, Variance



(in millions, except per barrel data) 2014 2013 $

% 2014 2013 $ % Revenues Tariff activities $ 356$ 310$ 46 15 % $ 691 $ 629$ 62 10 % Trucking 56 55 1 2 % 107 103 4 4 % Total Transportation revenues 412 365 47 13 % 798 732 66 9 % Costs and Expenses Trucking costs (41 ) (39 ) (2 ) (5 )% (78 ) (74 ) (4 ) (5 )% Field operating costs (excluding equity-indexed compensation expense) (137 ) (138 ) 1 1 % (265 ) (270 ) 5 2 % Equity-indexed compensation expense - operations (2) (5 ) (4 ) (1 ) (25 )% (10 ) (13 ) 3 23 % Segment general and administrative expenses (3) (excluding equity- indexed compensation expense) (21 ) (26 ) 5 19 % (43 ) (49 ) 6 12 % Equity-indexed compensation expense - general and administrative (2) (10 ) (9 ) (1 ) (11 )% (19 ) (26 ) 7 27 % Equity earnings in unconsolidated entities 23 11 12 109 % 44 23 21 91 % Segment profit $ 221$ 160$ 61 38 % $ 427 $ 323$ 104 32 % Maintenance capital $ 42$ 23 $



(19 ) (83 )% $ 76 $ 55$ (21 ) (38 )% Segment profit per barrel

$ 0.62$ 0.49$ 0.13 27 % $ 0.61$ 0.49$ 0.12 24 % 32

--------------------------------------------------------------------------------

Table of Contents Favorable/ Favorable/ Three Months Ended



(Unfavorable) Six Months Ended (Unfavorable) Average Daily Volumes

June 30, Variance June 30, Variance



(in thousands of barrels per day) (4) 2014 2013 Volumes

% 2014 2013 Volumes % Tariff activities Crude Oil Pipelines All American 38 38 - - % 36 39 (3 ) (8 )% Bakken Area Systems 145 130 15 12 % 138 127 11 9 % Basin / Mesa 714 680 34 5 % 729 702 27 4 % Capline 121 158 (37 ) (23 )% 123 157 (34 ) (22 )% Eagle Ford Area Systems 209 74 135 182 % 199 61 138 226 % Line 63 / Line 2000 106 108 (2 ) (2 )% 116 113 3 3 % Manito 44 46 (2 )



(4 )% 44 46 (2 ) (4 )% Mid-Continent Area Systems

360 282 78



28 % 338 287 51 18 % Permian Basin Area Systems

759 548 211 39 % 759 513 246 48 % Rainbow 108 125 (17 ) (14 )% 114 124 (10 ) (8 )% Rangeland 65 56 9



16 % 67 62 5 8 % Salt Lake City Area Systems

130 131 (1 ) (1 )% 131 133 (2 ) (2 )% South Saskatchewan 58 33 25 76 % 61 46 15 33 % White Cliffs 24 21 3 14 % 24 21 3 14 % Other 745 739 6 1 % 703 737 (34 ) (5 )% NGL Pipelines Co-Ed 55 51 4 8 % 56 54 2 4 % Other 123 165 (42 )



(25 )% 119 186 (67 ) (36 )% Refined Products Pipelines

- 110 (110 ) (100 )% - 105 (105 ) (100 )% Tariff activities total 3,804 3,495 309 9 % 3,757 3,513 244 7 % Trucking 127 108 19



18 % 129 109 20 18 % Transportation segment total

3,931 3,603 328 9 % 3,886 3,622 264 7 %

--------------------------------------------------------------------------------

(1) Revenues and costs and expenses include intersegment amounts. (2) Equity-indexed compensation expense shown in the table above includes expenses associated with awards that will or may be settled in units and awards that will or may be settled in cash. See Note 15 to our Consolidated Financial Statements included in Part IV of our 2013 Annual Report on Form 10-K for additional discussion regarding our equity-indexed compensation plans. (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) Volumes associated with assets employed through acquisitions and internal growth projects represent total volumes (attributable to our interest) for the number of days we employed the assets divided by the number of days in the period. Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The segment profit generated by our tariff and other fee-related activities depends on the volumes transported on the pipeline and the level of the tariff and other fees charged as well as the fixed and variable field costs of operating the pipeline. Revenue from our pipeline capacity leases generally reflects a negotiated amount.



The following is a discussion of items impacting Transportation segment profit and segment profit per barrel for the periods indicated.

Operating Revenues and Volumes. As noted in the table above, our total Transportation segment revenues, net of trucking costs, and volumes increased for both the three and six months ended June 30, 2014 compared to the three and six months ended June 30, 2013. Our Transportation segment results for the comparative periods were impacted by the following: 33 --------------------------------------------------------------------------------



Table of Contents

North American Crude Oil Production and Related Expansion Projects - The increase in North American crude oil production has had a favorable impact on volumes and revenues on our existing pipeline systems and has also provided opportunities for midstream infrastructure development in production growth areas. The resulting increases in volumes for the three and six months ended June 30, 2014 over the comparable 2013 periods were most notably on our Permian Basin, Eagle Ford and Mid-Continent Area Systems and our Basin and Mesa pipelines. We estimate that increased production combined with our recently completed internal growth projects increased revenues by over $25 million and $50 million for the three and six months ended June 30, 2014, respectively, compared to the three and six months ended June 30, 2013. Loss Allowance Revenue - As is common in the industry, our tariffs incorporate a loss allowance factor that is intended to offset losses due to evaporation, measurement and other losses in transit. We value the variance of allowance volumes to actual losses at the estimated net realizable value (including the impact of gains and losses from derivative-related activities) at the time the variance occurred and the result is recorded as either an increase or decrease to tariff revenues. The loss allowance revenue increased by approximately $20 million and $30 million, respectively, for the three and six months ended June 30, 2014 compared to the three and six months ended June 30, 2013 driven primarily by higher volumes, as well as a higher average realized price per barrel (including the impact of gains and losses from derivative-related activities). Rate Changes - Revenues on our pipelines are impacted by various rate changes that may occur during the period. These primarily include the indexing of rates on our FERC regulated pipelines, rate increases or decreases on our intrastate and Canadian pipelines or other negotiated rate changes. We estimate that the net impact of rate changes on our pipelines increased revenues by approximately $11 million and $18 million for the three and six months ended June 30, 2014, respectively, compared to the three and six months ended June 30, 2013. Sale of Refined Products Pipelines - We sold certain refined products pipeline systems and related assets in July 2013 and November 2013. As we did not own these assets during the three and six months ended June 30, 2014, our revenues were lower by approximately $10 million and $20 million, respectively, and volumes were lower by 110,000 and 105,000 barrels per day, respectively, as compared to the three and six months ended June 30, 2013. Foreign Exchange Impact - Revenues and expenses from our Canadian based subsidiaries, which use the Canadian dollar as their functional currency, are translated at the prevailing average exchange rates for each month. The average CAD to USD exchange rates for the three months ended June 30, 2014 and 2013 were $1.09 CAD: $1.00 USD and $1.02 CAD: $1.00 USD, respectively. The average CAD to USD exchange rates for the six months ended June 30, 2014 and 2013 were $1.10 CAD: $1.00 USD and $1.02 CAD: $1.00 USD, respectively. Therefore, revenues from our Canadian pipeline systems and trucking operations were unfavorably impacted by approximately $6 million and $15 million for the three and six months ended June 30, 2014, respectively, compared to the three and six months ended June 30, 2013 due to the depreciation of the Canadian dollar relative to the U.S. dollar. Additional noteworthy volume and revenue variances on our pipelines for the three and six months ended June 30, 2014 compared to the three and six months ended June 30, 2013 were (i) decreased volumes and revenues on certain of our NGL pipelines due to (a) the discontinuation of an agreement in 2014 to transport volumes on a pipeline and (b) the impact of netting joint venture related volumes to our share on a pipeline during 2014, which did not affect revenues, (ii) decreased volumes and revenues on the Capline pipeline due to refinery turnaround in the first half of 2014, (iii) increased volumes and revenues on our Rangeland, South Saskatchewan and Co-Ed pipelines, as these pipelines were shut down during a portion of the second quarter of 2013 due to high river flow rates and flooding in the surrounding area and (iv) a net decrease in volumes on our crude oil pipelines included in "Other" in the table above for the six month comparable period, a majority of which was related to (a) pipelines subject to long-term lease commitments with annual service payments whereby volumes may fluctuate, but such fluctuations did not have a meaningful impact on revenue and (b) pipelines impacted by third-party connection shut-downs and line repairs, which also did not have a significant impact on revenues for the period, partially offset by incremental volumes and revenues from our Gulf Coast pipeline, which was placed into service in April 2014. Field Operating Costs. Field operating costs (excluding equity-indexed compensation expenses) decreased during the three and six months ended June 30, 2014 compared to the three and six months ended June 30, 2013 due to higher environmental remediation costs in 2013, partially offset by increases due to (i) a change in classification of certain costs from General and Administrative expenses, and (ii) a general increase in expenses due to growth. 34 --------------------------------------------------------------------------------



Table of Contents

General and Administrative Expenses. General and administrative expenses (excluding equity-indexed compensation expenses) decreased during the three and six months ended June 30, 2014 compared to the three and six months ended June 30, 2013 primarily due to (i) a change in classification of certain costs to Field Operating Costs and (ii) higher costs in 2013 associated with the sale of certain refined products pipeline systems and related assets. Maintenance Capital. Maintenance capital consists of capital expenditures for the replacement of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. The increase in maintenance capital for the three and six months ended June 30, 2014 compared to the three and six months ended June 30, 2013 is primarily due to increased investments on integrity-related projects. Equity-Indexed Compensation Expense. On a consolidated basis across all segments, equity-indexed compensation expense increased for the three months ended June 30, 2014 compared to the same period in 2013, primarily due to the impact of the increase in unit price during the period compared to a decrease in unit price for the same period in 2013. Consolidated equity-indexed compensation expense decreased for the six months ended June 30, 2014 compared to the same period in 2013, primarily due to a less significant impact of the increase in unit price during the six months ended June 30, 2014 compared to the same period in 2013. See Note 15 to our Consolidated Financial Statements included in Part IV of our 2013 Annual Report on Form 10-K for additional information regarding our equity-indexed compensation plans. Equity Earnings in Unconsolidated Entities. The favorable variance in equity earnings in unconsolidated entities for the three and six months ended June 30, 2014 compared to the three and six months ended June 30, 2013 was largely due to increased throughput on the Eagle Ford joint venture pipeline as a result of increased production, as discussed above. Facilities Segment 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. The following table sets forth operating results from our Facilities segment for the periods indicated: Favorable/ Favorable/ Three Months Ended (Unfavorable) Six Months Ended (Unfavorable) Operating Results (1) June 30, Variance June 30, Variance (in millions, except per barrel data) 2014 2013 $ % 2014 2013 $ % Revenues $ 277$ 262$ 15 6 % $ 576$ 529$ 47 9 % Natural gas sales (2) - 86 (86 ) (100 )% - 174 (174 ) (100 )% Storage related costs (natural gas related) (12 ) (3 )



(9 ) (300 )% (38 ) (9 ) (29 ) (322 )% Natural gas sales costs (2)

- (80 ) 80 100 % - (165 ) 165 100 % Field operating costs (excluding equity-indexed compensation expense) (106 ) (94 )



(12 ) (13 )% (204 ) (180 ) (24 ) (13 )% Equity-indexed compensation expense - operations (3)

(2 ) - (2 ) N/A (2 ) (1 ) (1 ) (100 )% Segment general and administrative expenses (4) (excluding equity- indexed compensation expense) (16 ) (16 ) - - % (29 ) (32 ) 3 9 % Equity-indexed compensation expense - general and administrative (3) (7 ) (6 ) (1 ) (17 )% (15 ) (16 ) 1 6 % Segment profit $ 134$ 149$ (15 ) (10 )% $ 288$ 300$ (12 ) (4 )% Maintenance capital $ 5$ 11 $



6 55 % $ 15$ 18$ 3 17 % Segment profit per barrel

$ 0.37$ 0.41$ (0.04 ) (10 )% $ 0.40$ 0.42$ (0.02 ) (5 )% 35

-------------------------------------------------------------------------------- Table of Contents Favorable/ Favorable/ Three Months Ended (Unfavorable) Six Months Ended (Unfavorable) June 30, Variance June 30, Variance Volumes (5) 2014 2013 Volumes % 2014 2013 Volumes %

Crude oil, refined products and NGL terminalling and storage (average monthly capacity in millions of barrels) 94 95 (1 ) (1 )% 95 94 1 1 % Rail load / unload volumes (average volumes in thousands of barrels per day) 224 231 (7 ) (3 )% 227 223 4 2 % Natural gas storage (average monthly capacity in billions of cubic feet) 97 97 - - % 97 95 2 2 % NGL fractionation (average volumes in thousands of barrels per day) 86 90 (4 ) (4 )% 89 95 (6 ) (6 )% Facilities segment total (average monthly volumes in millions of barrels) (6) 120 121 (1 ) (1 )% 121 120 1 1 %

--------------------------------------------------------------------------------

(1) Revenues and costs and expenses include intersegment amounts. (2) Effective January 1, 2014, our natural gas sales and costs, primarily attributable to the activities performed by our natural gas storage commercial optimization group, are reported in the Supply and Logistics segment. (3) Equity-indexed compensation expense shown in the table above includes expenses associated with awards that will or may be settled in units and awards that will or may be settled in cash. See Note 15 to our Consolidated Financial Statements included in Part IV of our 2013 Annual Report on Form 10-K for additional discussion regarding our equity-indexed compensation plans. (4) 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. (5) Volumes associated with assets employed through



acquisitions and internal growth projects represent total volumes for the number of months we employed the assets divided by the number of months in the period.

(6) Facilities segment 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 capacity divided by 6 to account for the 6:1 mcf of 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.



The following is a discussion of items impacting Facilities segment profit and segment profit per barrel for the periods indicated.

Operating Revenues and Volumes. As noted in the table above, our Facilities segment revenues, less storage related costs, for the three months ended June 30, 2014 were in line with our results as compared to the same period of 2013, while our segment revenues, less storage related costs, increased slightly for the six months ended June 30, 2014 compared to the six months ended June 30, 2013. Total volumes were relatively consistent over the periods presented. The significant variances in revenues between the comparative periods are discussed below: 36

--------------------------------------------------------------------------------



Table of Contents

NGL Fractionation, NGL Storage and Natural Gas Processing Activities -Increases in revenues from our NGL fractionation and storage and natural gas processing activities of approximately $5 million and $21 million, respectively, for the three and six months ended June 30, 2014 compared to the three and six months ended June 30, 2013, were largely driven by higher facility fee revenues due to rate increases at certain of our storage and fractionation facilities. These increases in NGL revenues include estimated unfavorable foreign currency impacts of approximately $5 million and $11 million for the three and six months ended June 30, 2014, respectively, as compared to the three and six months ended June 30, 2013 due to the depreciation of the Canadian dollar relative to the U.S. dollar. The average CAD to USD exchange rates for the three months ended June 30, 2014 and 2013 were $1.09 CAD: $1.00 USD and $1.02 CAD: $1.00 USD, respectively. The average CAD to USD exchange rates for the six months ended June 30, 2014 and 2013 were $1.10 CAD: $1.00 USD and $1.02 CAD: $1.00 USD, respectively. Natural Gas Storage Operations - Net revenues from our natural gas storage operations decreased by approximately $9 million and $21 million, respectively, for the three and six months ended June 30, 2014 compared to the three and six months ended June 30, 2013. The decrease for the three-month 2014 period was primarily due to decreased storage rates on contracts that renewed or replaced expiring contracts. The six-month 2014 period was further unfavorably impacted by costs incurred in our natural gas storage activities to manage deliverability requirements in conjunction with the extended period of severe cold weather experienced during the first several months of 2014. Rail Terminals -Revenues from rail load and unload activities increased by approximately $3 million for the six months ended June 30, 2014 compared to the same period in 2013, respectively. This increase was primarily due to new rail terminals that came online in the fourth quarter of 2013, partially offset by the unfavorable impact of rail congestion and weather-related issues at certain of our terminals. For the three month comparable period, the increase in revenues from the new rail terminals was offset by decreased volumes into our St. James facility as well as the unfavorable impact of congestion, resulting in relatively consistent revenues for the three months ended June 30, 2014 compared to the three months ended June 30, 2013. Crude Oil Storage and Condensate Processing Activities -Increased revenues from our crude oil storage and condensate processing activities of approximately $4 million and $5 million, respectively, for the three and six months ended June 30, 2014 compared to the three and six months ended June 30, 2013 were largely driven by the start-up and subsequent expansion of our Eagle Ford processing facility and increased throughput and expansions at certain of our Mid-Continent and Gulf Coast storage facilities. However, such results were partially offset by reduced revenues from storage facilities in California and the East Coast due to decreased demand, as well as the reclassification of certain of our Canadian storage facilities to our Transportation segment during the second quarter of 2014. Field Operating Costs. Field operating costs (excluding equity-indexed compensation expenses) increased during the three and six months ended June 30, 2014 compared to the three and six months ended June 30, 2013 due to (i) a change in classification of certain costs from General and Administrative expenses, (ii) increased utility costs due primarily to higher power and gas prices and (iii) increased maintenance and repairs costs. General and Administrative Expenses. General and administrative expenses (excluding equity-indexed compensation expenses) remained relatively consistent for the three months ended June 30, 2014 compared to the three months ended June 30, 2013 and decreased during the comparative six-month periods. These results reflect the net impact of a decrease in general and administrative expenses due to a change in classification of certain costs to Field Operating Costs during the 2014 periods partially offset by increased expenses resulting from overall growth in the segment. Equity-Indexed Compensation Expense. On a consolidated basis across all segments, equity-indexed compensation expense increased for the three months ended June 30, 2014 over the comparable 2013 period, and decreased for the six months ended June 30, 2014 compared to the six months ended June 30, 2013. See the discussion regarding such variances under "- Transportation Segment" above. Also, see Note 15 to our Consolidated Financial Statements included in Part IV of our 2013 Annual Report on Form 10-K for additional information regarding our equity-indexed compensation plans. Supply and Logistics Segment Our revenues from supply and logistics activities reflect the sale of gathered and bulk-purchased crude oil, as well as sales of NGL volumes purchased from suppliers and natural gas sales attributable to the activities performed by our natural gas storage commercial optimization group. We do not anticipate that future changes in revenues resulting from variances in commodity prices will be a primary driver of segment profit. Generally, we expect our segment profit to increase or decrease directionally with (i) increases or decreases in our Supply and Logistics segment volumes (which consist of lease gathering crude oil purchase volumes, NGL sales volumes and waterborne cargos), (ii) demand for lease gathering services we provide producers and (iii) the overall volatility and strength or weakness of market conditions and the allocation of our assets among our various risk management strategies. In addition, the execution of our risk management strategies in conjunction with our assets can provide upside in certain markets. 37

--------------------------------------------------------------------------------



Table of Contents

The following table sets forth operating results from our Supply and Logistics segment for the periods indicated:

Favorable/ Favorable/ Three Months Ended (Unfavorable) Six Months Ended (Unfavorable) Operating Results (1) (2) June 30, Variance June 30, Variance



(in millions, except per barrel data) 2014 2013 $

% 2014 2013 $ % Revenues $ 10,860$ 9,934 $



926 9 % $ 22,228$ 20,158$ 2,070 10 % Purchases and related costs (3)

(10,578 ) (9,614 ) (964 ) (10 )% (21,553 ) (19,249 ) (2,304 ) (12 )% Field operating costs (excluding equity- indexed compensation expense) (112 ) (109 ) (3 ) (3 )% (218 ) (224 ) 6 3 % Equity-indexed compensation expense - operations (4) (1 ) (1 ) - - % (2 ) (2 ) - - % Segment general and administrative expenses (5) (excluding equity- indexed compensation expense) (27 ) (27 ) - - % (53 ) (53 ) - - % Equity-indexed compensation expense - general and administrative (4) (9 ) (7 ) (2 ) (29 )% (20 ) (20 ) - - % Segment profit $ 133$ 176$ (43 ) (24 )% $ 382$ 610$ (228 ) (37 )% Maintenance capital $ 1 $ 5 $



4 80 % $ 4$ 9$ 5 56 % Segment profit per barrel

$ 1.37$ 1.89$ (0.52 ) (28 )% $ 1.89$ 3.11$ (1.22 ) (39 )% Favorable/ Favorable/ Three Months Ended (Unfavorable) Six Months Ended (Unfavorable) Average Daily Volumes June 30, Variance June 30, Variance



(in thousands of barrels per day) 2014 2013 Volumes %

2014 2013 Volumes %



Crude oil lease gathering purchases 931 853 78

9 % 912 855 57 7 % NGL sales 139 160 (21 ) (13 )% 205 221 (16 ) (7 )% Waterborne cargos - 7 (7 ) (100 )% - 6 (6 ) (100 )%



Supply and Logistics segment total 1,070 1,020 50

5 % 1,117 1,082 35 3 %



--------------------------------------------------------------------------------

(1) Revenues and costs include intersegment amounts.



(2) Prior to January 1, 2014, natural gas sales revenues and costs attributable to the activities performed by our natural gas storage commercial optimization group were reported in the Facilities segment.

(3) Purchases and related costs include interest expense (related to hedged inventory purchases) of approximately $5 million and $7 million for the three and six months ended June 30, 2014 and approximately $5 million and $10 million for the three and six months ended June 30, 2013, respectively. (4) Equity-indexed compensation expense shown in the table above includes expenses associated with awards that will or may be settled in units and awards that will or may be settled in cash. See Note 15 to our Consolidated Financial Statements included in Part IV of our 2013 Annual Report on Form 10-K for additional discussion regarding our equity-indexed compensation plans.



(5) 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.

The NYMEX West Texas Intermediate benchmark price of crude oil ranged from approximately $99 to $108 per barrel and $86 to $99 per barrel during the three months ended June 30, 2014 and 2013, respectively, and from $91 to $108 per barrel and $86 to $99 per barrel during the six months ended June 30, 2014 and 2013, respectively. Because the commodities that we buy and sell are generally indexed to the same pricing indices for both the sales and purchases, revenues and costs related to purchases will fluctuate with market prices. However, the margins related to those sales and purchases will not necessarily have a corresponding increase or decrease. The absolute amount of our revenues and purchases increased for the three and six months ended June 30, 2014 relative to the comparative periods, primarily resulting from increases in crude oil volumes in 2014, as well as increases in prices, primarily during the comparative three-month period. 38

--------------------------------------------------------------------------------



Table of Contents

Generally, we expect a base level of earnings from our Supply and Logistics segment from the assets employed by this segment. This base level may be optimized and enhanced when there is a high level of market volatility, favorable basis differentials and/or a steep contango or backwardated market structure. Also, our NGL marketing operations are sensitive to weather-related demand, particularly during the approximate five-month peak heating season of November through March, and temperature differences from period-to-period may have a significant effect on NGL demand and thus our financial performance.



The following is a discussion of items impacting Supply and Logistics segment profit and segment profit per barrel for the periods indicated.

Operating Revenues and Volumes. Our Supply and Logistics segment revenues, net of purchases and related costs, excluding gains and losses from certain derivative activities (see the "Impact from Certain Derivative Activities" section below), were relatively consistent for the three months ended June 30, 2014 compared to the three months ended June 30, 2013, while such results decreased year-over-year for the six month comparative periods presented. The following factors impacted revenues and volumes in the comparative periods: North American Crude Oil Production and Related Market Economics - The significant increase in oil and liquids-rich gas production growth in North America has generally created regional supply and demand imbalances, due to the lack of sufficient infrastructure to support the movement of such production, which increased certain crude oil location differentials. The lack of existing pipeline takeaway capacity and associated logistical challenges has created market conditions that provided opportunities to capture above-baseline margins in our supply and logistics activities over the last few years. The favorable impact of widening differentials in the second quarter of 2014 led to an increase in net revenues from our crude oil supply and logistics activities for the three months ended June 30, 2014 compared to the three months ended June 30, 2103. Net revenues from our crude oil supply and logistics activities decreased for the six months ended June 30, 2014 compared to the six months ended June 30, 2013, as there were fewer opportunities to capture above-baseline margins. We believe the fundamentals of our business remain strong as lease-gathered volumes for the three and six month periods ended June 30, 2014 increased by 9% and 7%, respectively, as compared to volumes in the same three and six month periods in 2013. However, as the midstream infrastructure continues to be developed, we believe a normalization of margins will continue to occur as the logistics challenges are addressed. (See Items 1 and 2 "Business and Properties-Description of Segments and Associated Assets-Supply and Logistics Segment-Impact of Commodity Price Volatility and Dynamic Market Conditions on Our Business Model" included in Part I of our 2013 Annual Report on Form 10-K for further discussion regarding our business model, including diversification and utilization of our asset base among varying demand- and supply-driven markets.) NGL Marketing Operations - Revenues and volumes from our NGL marketing operations decreased during the three and six months ended June 30, 2014 as compared to the three and six months ended June 30, 2013. These decreases were driven by (i) less favorable market conditions, most notably during the second quarter of 2014, (ii) higher costs during the 2014 periods, primarily due to increased facility fees, and (iii) lower butane supply during the three months ended June 30, 2014. Natural Gas Storage Commercial Optimization - Our natural gas storage commercial optimization activities for the six months ended June 30, 2014 were unfavorably impacted by costs incurred to manage deliverability requirements in conjunction with the extended period of severe cold weather experienced during the first quarter of 2014. Impact from Certain Derivative Activities. The mark-to-market valuation of certain of our derivative activities impacted our net revenues as shown in the table below (in millions): Three Months Ended Six Months Ended June 30, June 30, 2014 2013 Variance 2014 2013 Variance Gains/(losses) from certain derivative activities (1) $ (15 )$ 27$ (42 )$ 51$ 51 $ -

-------------------------------------------------------------------------------- (1) Includes mark-to-market and other gains and losses resulting from certain 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. These amounts are reduced by the net impact of inventory valuation adjustments attributable to inventory hedged by the related derivative and gains recognized in later periods on physical sales of inventory that was previously written down. See Note 10 to our condensed consolidated financial statements for a comprehensive discussion regarding our derivatives and risk management activities. 39

--------------------------------------------------------------------------------

Table of Contents



Field Operating Costs. The increase in field operating costs (excluding equity-indexed compensation expenses) for the three months ended June 30, 2014 compared to the three months ended June 30, 2013 was primarily due to an increase in trucking costs associated with higher crude oil lease gathered volumes.

Field operating costs (excluding equity-indexed compensation expenses) decreased for the six months ended June 30, 2014 compared to the six months ended June 30, 2013 primarily due to a decrease in third-party transportation costs in the first quarter of 2014 as compared to the first quarter of 2013. Equity-Indexed Compensation Expense. On a consolidated basis across all segments, equity-indexed compensation expense increased for the three months ended June 30, 2014 over the comparable 2013 period, and decreased for the six months ended June 30, 2014 compared to the six months ended June 30, 2013. See the discussion regarding such variances under "- Transportation Segment" above. Also, see Note 15 to our Consolidated Financial Statements included in Part IV of our 2013 Annual Report on Form 10-K for additional information regarding our equity-indexed compensation plans. Other Income and Expenses



Depreciation and Amortization

Depreciation and amortization expense increased by approximately $9 million and $23 million for the three and six months ended June 30, 2014, respectively, over the three and six months ended June 30, 2013. These increases in depreciation and amortization expense in the 2014 periods over the comparable 2013 periods were primarily due to an acceleration of depreciation on certain pipeline assets to reflect a change in their estimated useful lives, as well as various internal growth projects completed since June 30, 2013. Interest Expense Interest expense increased by approximately $7 million and $9 million for the three and six months ended June 30, 2014, respectively, over the three and six months ended June 30, 2013 as a result of higher average debt outstanding during the 2014 periods, primarily due to (i) our August 2013 issuance of $700 million, 3.85% senior notes and (ii) our April 2014 issuance of $700 million, 4.70% senior notes, partially offset by the maturity of our $250 million, 5.63% senior notes in December 2013. Other Income/(Expense), Net



Other income/(expense), net in each of the periods presented was primarily comprised of foreign currency gains or losses related to revaluations of CAD-denominated interest receivables associated with our intercompany notes and the impact of related foreign currency hedges.

Income Tax Expense Income tax expense increased by approximately $4 million for the three months ended June 30, 2014 compared to the three months ended June 30, 2013, primarily as a result of higher year over year Canadian tax expense.



Net Income attributable to Noncontrolling Interests

Net income attributable to noncontrolling interests decreased for the three and six months ended June 30, 2014 compared to the three and six months ended June 30, 2013 as a result of our completion of the PNG Merger on December 31, 2013, pursuant to which we acquired all of the noncontrolling interests in PNG. 40

--------------------------------------------------------------------------------



Table of Contents

Liquidity and Capital Resources

General Our primary sources of liquidity are (i) cash flow from operating activities, (ii) borrowings under the commercial paper program or credit facilities and (iii) funds received from sales of equity and debt securities. Our primary cash requirements include, but are not limited to (i) ordinary course of business uses, such as the payment of amounts related to the purchase of crude oil, NGL and other products and other expenses and interest payments on outstanding debt, (ii) expansion and maintenance activities, (iii) acquisitions of assets or businesses, (iv) repayment of principal on long-term debt and (v) distributions to our unitholders and general partner. We generally expect to fund our short-term cash requirements through cash flow generated from operating activities and/or borrowings under the commercial paper program or credit facilities. In addition, we generally expect to fund our long-term needs, such as those resulting from expansion activities or acquisitions and refinancing our long-term debt, through a variety of sources (either separately or in combination), which may include the sources mentioned above as funding for short-term needs and/or the issuance of additional equity or debt securities. As of June 30, 2014, we had a working capital deficit of approximately $255 million and approximately $2.2 billion of liquidity available to meet our ongoing operating, investing and financing needs as noted below (in millions): As of June 30, 2014 Availability under PAA senior unsecured revolving credit facility (1) $



1,586

Availability under PAA senior secured hedged inventory facility (1)

1,376

Less: Amounts outstanding under PAA commercial paper program (760 ) Subtotal 2,202 Cash and cash equivalents 27 Total $ 2,229

-------------------------------------------------------------------------------- (1) Represents availability prior to giving effect to



amounts

outstanding under the PAA commercial paper program. Borrowings under the PAA commercial paper program reduce available capacity under the facility.

We believe that we have, and will continue to have, the ability to access the commercial paper program and credit facilities, which we use to meet our short-term cash needs. We believe that our financial position remains strong and we have sufficient liquidity; however, extended disruptions in the financial markets and/or energy price volatility that adversely affect our business may have a materially adverse effect on our financial condition, results of operations or cash flows. Also, see "Risk Factors" in Item 1A of our 2013 Annual Report on Form 10-K for further discussion regarding such risks that may impact our liquidity and capital resources. Usage of the credit facilities, which provide the backstop for the commercial paper program, is subject to ongoing compliance with covenants. As of June 30, 2014, we were in compliance with all such covenants.



Cash Flow from Operating Activities

For a comprehensive discussion of the primary drivers of cash flow from operating activities, including the impact of varying market conditions and the timing of settlement of our derivative activities, see "Liquidity and Capital Resources-Cash Flow from Operating Activities" under Item 7 of our 2013 Annual Report on Form 10-K. Net cash provided by operating activities for the first six months of 2014 was approximately $963 million, primarily resulting from earnings from our operations. Additionally, we decreased our inventory levels (including margin balances required as part of our hedging activities) that were funded by our short-term debt, resulting in a positive impact on our cash provided by operating activities. Net cash provided by operating activities for the first six months of 2013 of approximately $1.3 billion also resulted primarily from earnings from our operations. In addition, we decreased the amount of our inventory during the first half of 2013, primarily due to the sale of NGL inventory related to product demand caused by increases in (i) heating requirements during the extended 2013 winter season, (ii) export activity that reduced overall product availability in the market and (iii) petrochemical demand, as well as the sale of crude oil inventory that had been stored during the contango market. The net proceeds received from liquidation of such inventory during the quarter were used to repay borrowings under our credit facilities and favorably impacted our cash flow from operating activities. 41 --------------------------------------------------------------------------------



Table of Contents

Acquisitions and Capital Expenditures

In addition to operating needs discussed above, we also use cash for acquisition activities and internal growth projects. We have made and will continue to make capital expenditures for acquisitions, expansion capital and maintenance capital. 2014 Capital Expansion Projects. See "-Acquisitions and Internal Growth Projects" for detail of our projected capital expenditures for the year ending December 31, 2014. We expect the majority of funding for our 2014 capital program will be provided by borrowings under the commercial paper program, our credit facilities and cash flow in excess of partnership distributions, as well as through our access to the capital markets for equity and debt as we deem necessary. Acquisitions. The price of acquisitions includes cash paid, assumed liabilities and net working capital items. Because of the non-cash items included in the total price of the acquisition and the timing of certain cash payments, the net cash paid may differ significantly from the total price of the acquisitions completed during the period. Historically, we have financed acquisitions primarily with cash generated by operations and the financing activities discussed below.



Equity and Debt Financing Activities

Our financing activities primarily relate to funding acquisitions, internal capital projects and refinancing our debt maturities, as well as short-term working capital and hedged inventory borrowings related to our NGL business and contango market activities. Our financing activities have primarily consisted of equity offerings, senior notes offerings and borrowings and repayments under the commercial paper program or the credit facilities, as well as payment of distributions to our unitholders and general partner. Registration Statements. We periodically access the capital markets for both equity and debt financing. We have filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to an aggregate of $2.0 billion of debt or equity securities ("Traditional Shelf"). All issuances of equity securities associated with our continuous offering program, as discussed further below, have been issued pursuant to the Traditional Shelf. At June 30, 2014, we had approximately $1.0 billion of unsold securities available under the Traditional Shelf. We also have access to a universal shelf registration statement ("WKSI Shelf"), which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs.



Continuous Offering Program. During the six months ended June 30, 2014, we issued an aggregate of approximately 8.1 million common units under our continuous offering program, generating net proceeds of approximately $453 million, including our general partner's proportionate capital contribution of approximately $9 million. The net proceeds from these sales were used for general partnership purposes.

Credit Agreements, Commercial Paper Program and Indentures. Our credit agreements (which impact our ability to access our commercial paper program because they provide the backstop that supports our short-term credit ratings) and the indentures governing our senior notes contain cross-default provisions. A default under our credit agreements would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with the provisions in our credit agreements, our ability to make distributions of available cash is not restricted. We were in compliance with the covenants contained in our credit agreements and indentures as of June 30, 2014. During the six months ended June 30, 2014 and 2013, we had net repayments on our credit agreements and commercial paper program of approximately $344 million and $186 million, respectively. The net repayments during both periods resulted primarily from cash flow from operating activities, including sales of inventory that was liquidated during the periods, as well as cash received from our debt and equity activities. In April 2014, we completed the issuance of $700 million, 4.70% senior notes due 2044 at a public offering price of 99.734%. Interest payments are due on June 15 and December 15 of each year, commencing on December 15, 2014. We used the net proceeds from this offering of approximately $691 million, after deducting the underwriting discount and offering expenses, to repay outstanding borrowings under our commercial paper program and for general partnership purposes. 42 --------------------------------------------------------------------------------



Distributions Paid to Our Unitholders, General Partner and Noncontrolling Interests

Distributions to our unitholders and general partner. We distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements. On August 14, 2014 we will pay a distribution of $0.6450 per limited partner unit, which represents a 9.8% increase over the distribution we paid in August 2013. See Note 8 to our condensed consolidated financial statements for details of distributions paid. Also, see Item 5. "Market for Registrant's Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities-Cash Distribution Policy" included in our 2013 Annual Report on Form 10-K for additional discussion on distributions. Distributions to noncontrolling interests. We paid approximately $1 million and $24 million for distributions to noncontrolling interests during the six months ended June 30, 2014 and 2013, respectively. The decrease in amounts paid is due to our completion of the purchase of all of the noncontrolling interests in PNG on December 31, 2013. We believe that we have sufficient liquid assets, cash flow from operating activities and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. We are, however, subject to business and operational risks that could adversely affect our cash flow. A prolonged material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity. Contingencies



For a discussion of contingencies that may impact us, see Note 11 to our condensed consolidated financial statements.

Commitments Contractual Obligations. In the ordinary course of doing business, we purchase crude oil and NGL from third parties under contracts, the majority of which range in term from thirty-day evergreen to five years with a limited number of contracts extending up to approximately ten years. We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. In addition, we enter into similar contractual obligations in conjunction with our natural gas operations. The table below includes purchase obligations related to these activities. Where applicable, the amounts presented represent the net obligations associated with our counterparties (including giving effect to netting buy/sell contracts and those subject to a net settlement arrangement). We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to entities that we deem creditworthy or who have provided credit support we consider adequate. The following table includes our best estimate of the amount and timing of these payments as well as others due under the specified contractual obligations as of June 30, 2014 (in millions): Remainder of 2019 and 2014 2015 2016 2017 2018 Thereafter Total Long-term debt, including related interest payments (1) $ 193 $ 927$ 533$ 728$ 900$ 8,888$ 12,169 Leases (2) 76 143 135 112 88 416 970 Other obligations (3) 122 125 89 62 45 221 664 Subtotal 391 1,195 757 902 1,033 9,525 13,803 Crude oil, natural gas, NGL and other purchases (4) 7,310 7,111 6,303 4,898 2,766 8,151 36,539 Total $ 7,701$ 8,306$ 7,060$ 5,800$ 3,799$ 17,676$ 50,342

-------------------------------------------------------------------------------- (1) Includes debt service payments, interest payments due



on

senior notes and the commitment fee on assumed available capacity under the PAA revolving credit facilities. Although there may be short-term borrowings under the PAA revolving credit facilities and commercial paper program, we historically repay and borrow at varying amounts. As such, we have included only the maximum commitment fee (as if no short-term borrowings were outstanding on the facilities or commercial paper program) in the amounts above. 43 -------------------------------------------------------------------------------- (2) Leases are primarily for (i) surface rentals, (ii)



office

rent, (iii) pipeline assets and (iv) trucks, trailers and railcars.

(3) Includes (i) other long-term liabilities, (ii)



storage,

processing and transportation agreements and (iii) commitments related to our capital expansion projects, including projected contributions for our share of the capital spending of our equity-method investments. Excludes a non-current liability of approximately $4 million related to derivative activity included in Crude oil, natural gas, NGL and other purchases. (4) Amounts are primarily based on estimated volumes and market prices based on average activity during June 2014. The actual physical volume purchased and actual settlement prices will vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control. Letters of Credit. In connection with supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil, NGL and natural gas. Additionally, we issue letters of credit to support insurance programs and construction activities. At June 30, 2014 and December 31, 2013, we had outstanding letters of credit of approximately $38 million and $41 million, respectively.



Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements as defined by Item 303 of Regulation S-K.

Recent Accounting Pronouncements

See Note 2 to our condensed consolidated financial statements.

Critical Accounting Policies and Estimates

For additional discussion regarding our critical accounting policies and estimates, see "Critical Accounting Policies and Estimates" under Item 7 of our 2013 Annual Report on Form 10-K.

FORWARD-LOOKING STATEMENTS 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 internal growth projects;

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;

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 or other factors;



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

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

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

44 --------------------------------------------------------------------------------



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

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

the 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; shortages or cost increases of supplies, materials or labor; the effectiveness of our risk management activities;



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

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

non-utilization of our assets and facilities; the effects of competition; 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. Other factors described herein, as well as factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please read "Risk Factors" discussed in Item 1A of our 2013 Annual Report on Form 10-K. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information. 45



--------------------------------------------------------------------------------


For more stories on investments and markets, please see HispanicBusiness' Finance Channel



Source: Edgar Glimpses


Story Tools






HispanicBusiness.com Facebook Linkedin Twitter RSS Feed Email Alerts & Newsletters