# Plains GP Holdings LP: Form 10-Q for the period ended Jun 30, 2015

- Company: [Plains GP Holdings LP](/companies/pagp.md) (CIK 1581990)
- Form: 10-Q
- Filed: 2015-08-07
- Accepted by EDGAR: Aug 7, 2015, 14:54 ET
- Period: 2015-06-30
- Accession: 0001558370-15-001527
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1581990/000155837015001527/pagp-20150630x10q.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1581990/000155837015001527/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2015-06-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2015-04-01 to 2015-06-30 | $6.66bn | us-gaap:Revenues |
| Revenue | 6 months, 2015-01-01 to 2015-06-30 | $12.61bn | us-gaap:Revenues |
| Cost of revenue | 3 months, 2015-04-01 to 2015-06-30 | $5.85bn | us-gaap:CostOfGoodsAndServicesSold |
| Cost of revenue | 6 months, 2015-01-01 to 2015-06-30 | $10.89bn | us-gaap:CostOfGoodsAndServicesSold |
| Gross profit | 3 months, 2015-04-01 to 2015-06-30 | $371.0m | us-gaap:GrossProfit |
| Gross profit | 6 months, 2015-01-01 to 2015-06-30 | $884.0m | us-gaap:GrossProfit |
| Operating income | 3 months, 2015-04-01 to 2015-06-30 | $208.0m | us-gaap:OperatingIncomeLoss |
| Operating income | 6 months, 2015-01-01 to 2015-06-30 | $575.0m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2015-04-01 to 2015-06-30 | $107.0m | us-gaap:InterestExpense |
| Interest expense | 6 months, 2015-01-01 to 2015-06-30 | $211.0m | us-gaap:InterestExpense |
| Income tax | 3 months, 2015-04-01 to 2015-06-30 | $51.0m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 6 months, 2015-01-01 to 2015-06-30 | $85.0m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2015-04-01 to 2015-06-30 | $30.0m | us-gaap:NetIncomeLoss |
| Net income | 6 months, 2015-01-01 to 2015-06-30 | $61.0m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2015-04-01 to 2015-06-30 | $0.14 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 6 months, 2015-01-01 to 2015-06-30 | $0.27 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2015-04-01 to 2015-06-30 | $0.14 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 6 months, 2015-01-01 to 2015-06-30 | $0.28 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2015-04-01 to 2015-06-30 | 224,000,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 6 months, 2015-01-01 to 2015-06-30 | 606,000,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 6 months, 2015-01-01 to 2015-06-30 | $654.0m | us-gaap:NetCashProvidedByUsedInOperatingActivitiesContinuingOperations |
| Capital expenditure | 6 months, 2015-01-01 to 2015-06-30 | $1.03bn | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Cash and equivalents | at 2015-06-30 | $30.0m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2015-06-30 | $3.95bn | us-gaap:AssetsCurrent |
| Total assets | at 2015-06-30 | $24.75bn | us-gaap:Assets |
| Current liabilities | at 2015-06-30 | $4.47bn | us-gaap:LiabilitiesCurrent |
| Current portion of debt | at 2015-06-30 | $915.0m | us-gaap:DebtCurrent |
| Short-term borrowings | at 2015-06-30 | $512.0m | us-gaap:CommercialPaper |

## Management's discussion and analysis

As filed, 66,050 characters.

### 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 2014 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 Capital Projects
- Results of Operations
- Outlook
- Liquidity and Capital Resources
- Off-Balance Sheet Arrangements
- Recent Accounting Pronouncements
- Critical Accounting Policies and Estimates
- Forward-Looking Statements

### Executive Summary

### Company Overview

We are a Delaware limited partnership formed on July 17, 2013 to own an interest in the general partner and IDRs of PAA, a publicly traded Delaware limited partnership. Although we were formed as a limited partnership, we have elected to be taxed as a corporation for United States federal income tax purposes. As of June 30, 2015, we owned an approximate 37% limited partner interest in AAP, a Delaware limited partnership that directly owns all of PAA’s IDRs and indirectly owns the 2% general partner interest in PAA. AAP is the sole member of PAA GP, a Delaware limited liability company that directly holds the 2% general partner interest in PAA.

Since we are the managing member of and control GP LLC, which in turn effectively controls PAA, we reflect our ownership in PAA, as well as its subsidiaries, on a consolidated basis in accordance with GAAP. Accordingly, our financial results are combined with those of GP LLC and PAA as well as with their subsidiaries. As such, our results of operations as discussed below do not differ materially from the results of operations of PAA.

PAA owns and operates midstream energy infrastructure and provides logistics services for crude oil, 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.

### Overview of Operating Results, Capital Investments and Other Significant Activities

For the six months ended June 30, 2015 and 2014, we recognized net income of $365 million and $647 million, respectively. This decrease was primarily driven by less favorable results from our Supply and Logistics segment. In addition, our operating results for the 2015 period were impacted by costs and lost revenue associated with the Line 901 incident. See further discussion of our segment operating results in the following sections. Net income for the first six months of 2015 was also impacted by higher depreciation and amortization expense and interest expense associated with our growing asset base and related financing activities.

We invested approximately $1.2 billion in midstream infrastructure projects during the six months ended June 30, 2015, with a targeted expansion capital plan for the full year of 2015 of $2.2 billion. To fund a portion of such capital activities, PAA issued approximately 22.1 million common units for net proceeds of approximately $1.1 billion. In addition, we paid $805 million of cash distributions to our Class A shareholders and noncontrolling interests during the six months ended June 30, 2015, and we declared a quarterly distribution of $0.227 per Class A share to be paid on August 14, 2015.

### Acquisitions and Capital Projects

The following table summarizes our expenditures for acquisition capital, expansion capital and maintenance capital for the periods indicated (in millions):

|  | Six Months Ended June 30, 2015 | 2014 |
| --- | ---: | ---: |
| Acquisition capital | $64 | $2 |
| Expansion capital (1) | 1,188 | 1,012 |
| Maintenance capital (1) | 102 | 95 |
|  | $1,354 | $1,109 |

(1) Capital expenditures made to expand the existing operating and/or earnings capacity of our assets are classified as expansion capital. 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 are classified as maintenance capital.

### 2015 Capital Projects

Our capital program is highlighted by a large number of small-to-medium sized projects spread across multiple geographic regions/resource plays. We believe the diversity of our program mitigates the impact of delays, cost overruns or adverse market developments with respect to a particular project or geographic region/resource play. The majority of our 2015 expansion capital program will be invested in our fee-based Transportation and Facilities segments. We expect that our investments will have minimal contributions to our 2015 results, but will provide growth for 2016 and beyond.

The following table summarizes our notable projects in progress during 2015 and the forecasted expenditures for the year ending December 31, 2015 (in millions):

| Projects | 2015 |
| --- | ---: |
| Permian Basin Area Projects | $410 |
| Fort Saskatchewan Facility Projects / NGL Line | 310 |
| Rail Terminal Projects (1) | 275 |
| Cactus Pipeline (2) | 150 |
| Saddlehorn Pipeline | 140 |
| Red River Pipeline (Cushing to Longview) | 130 |
| Eagle Ford JV Project | 80 |
| Cowboy Pipeline (Cheyenne to Carr) | 50 |
| St. James Terminal Expansions | 50 |
| Eagle Ford Area Projects | 45 |
| Diamond Pipeline | 40 |
| Cushing Terminal Expansions | 40 |
| Line 63 Reactivation | 25 |
| Other Projects | 455 |
|  | $2,200 |
| Potential Adjustments for Timing / Scope Refinement (3) | -$100 + $100 |
| Total Projected Expansion Capital Expenditures | $2,100 - $2,300 |
| Maintenance Capital Expenditures | $205 - $225 |

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

(2) Includes linefill costs associated with the project.

(3) 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.

### Results of Operations

We manage our operations through three operating segments: Transportation, Facilities and 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 19 to our Consolidated Financial Statements included in Part IV of our 2014 Annual Report on Form 10-K for further discussion of how we evaluate segment profit.

The following table sets forth an overview of our consolidated financial results calculated in accordance with GAAP for the periods indicated (in millions, except per share data):

|  | Three Months Ended June 30, 2015 | 2014 | Favorable/ (Unfavorable) Variance $% |  | Six Months Ended June 30, 2015 | 2014 | Favorable/ (Unfavorable) Variance $% |  |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Transportation segment profit | $186 | $221 | $(35) | (16)% | $428 | $427 | $1 | —% |
| Facilities segment profit | 144 | 134 | 10 | 7% | 285 | 288 | (3) | (1)% |
| Supply and Logistics segment profit | 41 | 133 | (92) | (69)% | 171 | 382 | (211) | (55)% |
| Total segment profit | 371 | 488 | (117) | (24)% | 884 | 1,097 | (213) | (19)% |
| Unallocated general and administrative expenses | (1) | (1) | — | —% | (2) | (2) | — | —% |
| Depreciation and amortization | (110) | (100) | (10) | (10)% | (218) | (197) | (21) | (11)% |
| Interest expense, net | (107) | (85) | (22) | (26)% | (211) | (166) | (45) | (27)% |
| Other income/(expense), net | 1 | 4 | (3) | (75)% | (3) | 2 | (5) | (250)% |
| Income tax expense | (51) | (31) | (20) | (65)% | (85) | (87) | 2 | 2% |
| Net income | 103 | 275 | (172) | (63)% | 365 | 647 | (282) | (44)% |
| Net income attributable to noncontrolling interests | (73) | (260) | 187 | 72% | (304) | (618) | 314 | 51% |
| Net income attributable to PAGP | $30 | $15 | $15 | 100% | $61 | $29 | $32 | 110% |
| Basic net income per Class A share | $0.14 | $0.11 | $0.03 | 27% | $0.28 | $0.21 | $0.07 | 33% |
| Diluted net income per Class A share | $0.14 | $0.11 | $0.03 | 27% | $0.27 | $0.21 | $0.06 | 29% |
| Basic weighted average Class A shares outstanding | 224 | 136 | 88 | 65% | 218 | 135 | 83 | 61% |
| Diluted weighted average Class A shares outstanding | 224 | 136 | 88 | 65% | 606 | 135 | 471 | 349% |

### Analysis of Operating Segments

### 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 pipeline capacity agreements and other transportation fees.

The following tables set forth our operating results from our Transportation segment for the periods indicated:

*(in millions, except per barrel data)*

| Operating Results (1) Revenues | Three Months Ended June 30, 2015 | 2014 | Favorable/ (Unfavorable) Variance $% |  | Six Months Ended June 30, 2015 | 2014 | Favorable/ (Unfavorable) Variance $% |  |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Tariff activities | $361 | $356 | $5 | 1% | $720 | $691 | $29 | 4% |
| Trucking | 41 | 56 | (15) | (27)% | 83 | 107 | (24) | (22)% |
| Total transportation revenues | 402 | 412 | (10) | (2)% | 803 | 798 | 5 | 1% |
| Costs and Expenses |  |  |  |  |  |  |  |  |
| Trucking costs | (29) | (41) | 12 | 29% | (59) | (78) | 19 | 24% |
| Field operating costs (2) | (209) | (137) | (72) | (53)% | (346) | (265) | (81) | (31)% |
| Equity-indexed compensation expense - operations | (3) | (5) | 2 | 40% | (6) | (10) | 4 | 40% |
| Segment general and administrative expenses (2) (3) | (22) | (21) | (1) | (5)% | (43) | (43) | — | —% |
| Equity-indexed compensation expense - general and administrative | (5) | (10) | 5 | 50% | (10) | (19) | 9 | 47% |
| Equity earnings in unconsolidated entities | 52 | 23 | 29 | 126% | 89 | 44 | 45 | 102% |
| Segment profit | $186 | $221 | $(35) | (16)% | $428 | $427 | $1 | —% |
| Maintenance capital | $33 | $42 | $9 | 21% | $66 | $76 | $10 | 13% |
| Segment profit per barrel | $0.45 | $0.62 | $(0.17) | (27)% | $0.54 | $0.61 | $(0.07) | (11)% |

38

| Average Daily Volumes (in thousands of barrels per day) (4) Tariff activities Crude Oil Pipelines | Three Months Ended June 30, 2015 | 2014 | Favorable/ (Unfavorable) Variance Volumes% |  | Six Months Ended June 30, 2015 | 2014 | Favorable/ (Unfavorable) Variance Volumes% |  |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| All American | 18 | 38 | (20) | (53)% | 27 | 36 | (9) | (25)% |
| Bakken Area Systems (5) | 147 | 145 | 2 | 1% | 149 | 138 | 11 | 8% |
| Basin / Mesa / Sunrise | 858 | 714 | 144 | 20% | 839 | 729 | 110 | 15% |
| BridgeTex | 130 | — | 130 | N/A | 107 | — | 107 | N/A |
| Cactus | 62 | — | 62 | N/A | 31 | — | 31 | N/A |
| Capline | 169 | 121 | 48 | 40% | 161 | 123 | 38 | 31% |
| Eagle Ford Area Systems (5) | 308 | 209 | 99 | 47% | 286 | 199 | 87 | 44% |
| Line 63 / Line 2000 | 108 | 106 | 2 | 2% | 122 | 116 | 6 | 5% |
| Manito | 48 | 44 | 4 | 9% | 51 | 44 | 7 | 16% |
| Mid-Continent Area Systems | 355 | 371 | (16) | (4)% | 363 | 349 | 14 | 4% |
| Permian Basin Area Systems | 836 | 759 | 77 | 10% | 795 | 759 | 36 | 5% |
| Rainbow | 116 | 108 | 8 | 7% | 117 | 114 | 3 | 3% |
| Rangeland | 56 | 65 | (9) | (14)% | 59 | 67 | (8) | (12)% |
| Salt Lake City Area Systems (5) | 122 | 130 | (8) | (6)% | 126 | 131 | (5) | (4)% |
| South Saskatchewan | 61 | 58 | 3 | 5% | 63 | 61 | 2 | 3% |
| White Cliffs | 41 | 24 | 17 | 71% | 44 | 24 | 20 | 83% |
| Other | 791 | 734 | 57 | 8% | 740 | 692 | 48 | 7% |
| NGL Pipelines |  |  |  |  |  |  |  |  |
| Co-Ed | 57 | 55 | 2 | 4% | 59 | 56 | 3 | 5% |
| Other | 137 | 123 | 14 | 11% | 133 | 119 | 14 | 12% |
| Tariff activities total | 4,420 | 3,804 | 616 | 16% | 4,272 | 3,757 | 515 | 14% |
| Trucking | 109 | 127 | (18) | (14)% | 115 | 129 | (14) | (11)% |
| Transportation segment total | 4,529 | 3,931 | 598 | 15% | 4,387 | 3,886 | 501 | 13% |

(1) Revenues and costs and expenses include 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) Volumes associated with assets employed through acquisitions and capital expansion 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.

(5) Area systems include volumes (attributable to our interest) from our investments in unconsolidated entities.

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 agreements generally reflects a negotiated amount. 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 following is a discussion of items impacting Transportation segment profit and segment profit per barrel for the periods indicated.

*Net Operating Revenues and Volumes.* As noted in the table above, our total Transportation segment revenues, net of trucking costs, increased for the six months ended June 30, 2015 compared to the six months ended June 30, 2014 and were relatively consistent for the comparative three-month periods, while average daily volumes increased for each of the comparative periods presented. Our Transportation segment results were impacted by the following:

- North American Crude Oil Production and Related Expansion Projects — Production growth from the development of certain North American crude oil resource plays increased volumes and revenues on our existing pipeline systems over the comparative periods presented. We estimate that the impact of increased throughput and related infrastructure projects, most notably on our Eagle Ford Area Systems and certain pipelines in our Permian Basin Area Systems, and our recently constructed Cactus, Sunrise and Pascagoula pipelines, increased our revenues by $25 million and $45 million, respectively, for the three and six months ended June 30, 2015 compared to the three and six months ended June 30, 2014.
- Tariff Rates — Revenues on our pipelines are impacted by various tariff rate changes that may occur during the period, which include (i) rate increases or decreases on our intrastate and Canadian pipelines and fees on related system assets, (ii) the indexing of rates on our FERC regulated pipelines or (iii) other negotiated rate changes. We estimate that the net impact of such rate changes on our pipelines increased revenues by $10 million and $30 million for the three and six months ended June 30, 2015, respectively, compared to the three and six months ended June 30, 2014 primarily due to tariff rate increases on certain of our Canadian crude oil pipelines and incremental fees on related system assets, and, to a much lesser extent, the FERC indexing effective July 1, 2014 and rate increases on our intrastate pipelines.
- Loss Allowance Revenue — As is common in the pipeline transportation 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 decreased by $18 million and $27 million, respectively, for the three and six months ended June 30, 2015 compared to the three and six months ended June 30, 2014 primarily due to a lower average realized price per barrel, partially offset by higher volumes.
- Foreign Exchange Impact — We estimate that revenues from our Canadian pipeline systems and trucking operations were unfavorably impacted by $12 million and $23 million for the three and six months ended June 30, 2015, respectively, compared to the three and six months ended June 30, 2014 due to the depreciation of CAD relative to USD.

Additional noteworthy volume and revenue variances for the comparative periods presented included (i) lower volumes and revenues on our All American Pipeline System due to pipeline downtime associated with the Line 901 incident (see Note 10 to our Condensed Consolidated Financial Statements for additional information), (ii) decreased trucking activity due to lower producer volumes and (iii) increased volumes and revenues on the Capline Pipeline System due to higher refinery demand and timing of a refinery turnaround, which occurred in the second quarter of 2014.

*Field Operating Costs.* Field operating costs (excluding equity-indexed compensation expense) increased during the three and six months ended June 30, 2015 compared to the three and six months ended June 30, 2014 primarily due to the following:

- Estimated costs of $65 million associated with the Line 901 incident, net of amounts we believe are probable of recovery from insurance. See Note 10 to our Condensed Consolidated Financial Statements for additional information regarding this incident.
- Higher salary and related expenses and property tax expense primarily associated with the growth and capital expansion in the segment.

The increase in operating costs for the comparative periods was partially offset by favorable foreign exchange impacts of $4 million and $9 million for the three and six months ended June 30, 2015, respectively.

*Equity-Indexed Compensation Expense.* On a consolidated basis across all segments, equity-indexed compensation expense decreased for the three and six months ended June 30, 2015 compared to the same periods in 2014 primarily due to the impact of the decrease in unit price during each of the 2015 periods compared to the impact of the increase in unit price during the 2014 periods.

Allocations of equity-indexed compensation expense vary over time (i) between field operating costs and general and administrative expenses and (ii) between segments and could result in variances in those expense categories or segments that differ from the consolidated variance explanations above. See Note 16 to our Consolidated Financial Statements included in Part IV of our 2014 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, 2015 compared to the three and six months ended June 30, 2014 was primarily driven by (i) earnings from our 50% interest in BridgeTex, which we acquired in November 2014, (ii) increased throughput on the White Cliffs pipeline due to an expansion of the pipeline that was placed into service in July 2014 and (iii) increased throughput on the Eagle Ford pipeline as a result of increased crude oil production, as discussed in “Net Operating Revenues and Volumes” above.

*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 decrease in maintenance capital for the three and six months ended June 30, 2015 compared to the three and six months ended June 30, 2014 was primarily due to a reclassification of certain maintenance capital costs from our Facilities segment during the 2014 period.

### 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. 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 following tables set forth our operating results from our Facilities segment for the periods indicated:

*(in millions, except per barrel data)*

| Operating Results (1) | Three Months Ended June 30, 2015 | 2014 | Favorable/ (Unfavorable) Variance $% |  | Six Months Ended June 30, 2015 | 2014 | Favorable/ (Unfavorable) Variance $% |  |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Revenues | $269 | $277 | $(8) | (3)% | $525 | $576 | $(51) | (9)% |
| Storage related costs (natural gas related) | (7) | (12) | 5 | 42% | (11) | (38) | 27 | 71% |
| Field operating costs (2) | (97) | (106) | 9 | 8% | (187) | (204) | 17 | 8% |
| Equity-indexed compensation expense - operations | (1) | (2) | 1 | 50% | (2) | (2) | — | —% |
| Segment general and administrative expenses (2) (3) | (17) | (16) | (1) | (6)% | (33) | (29) | (4) | (14)% |
| Equity-indexed compensation expense - general and administrative | (3) | (7) | 4 | 57% | (7) | (15) | 8 | 53% |
| Segment profit | $144 | $134 | $10 | 7% | $285 | $288 | $(3) | (1)% |
| Maintenance capital | $17 | $5 | $(12) | (240)% | $32 | $15 | $(17) | (113)% |
| Segment profit per barrel | $0.38 | $0.37 | $0.01 | 3% | $0.38 | $0.40 | $(0.02) | (5)% |

| Volumes (4) | Three Months Ended June 30, 2015 | 2014 | Favorable/ (Unfavorable) Variance Volumes% |  | Six Months Ended June 30, 2015 | 2014 | Favorable/ (Unfavorable) Variance Volumes% |  |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Crude oil, refined products and NGL terminalling and storage (average monthly capacity in millions of barrels) | 99 | 94 | 5 | 5% | 99 | 95 | 4 | 4% |
| Rail load / unload volumes (average volumes in thousands of barrels per day) | 233 | 224 | 9 | 4% | 220 | 227 | (7) | (3)% |
| Natural gas storage (average monthly working capacity in billions of cubic feet) | 97 | 97 | — | —% | 97 | 97 | — | —% |
| NGL fractionation (average volumes in thousands of barrels per day) | 103 | 86 | 17 | 20% | 103 | 89 | 14 | 16% |
| Facilities segment total (average monthly volumes in millions of barrels) (5) | 126 | 120 | 6 | 5% | 125 | 121 | 4 | 3% |

(1) Revenues and costs and expenses include 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) Volumes associated with assets employed through acquisitions and capital expansion projects represent total volumes for the number of months we employed the assets divided by the number of months in the period.

(5) 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 working capacity divided by 6 to account for the 42

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.

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

*Net Operating Revenues and Volumes.* As noted in the table above, our Facilities segment revenues, less storage related costs, decreased for the three and six months ended June 30, 2015 compared to the same periods in 2014, while total volumes for each of the comparative periods presented increased slightly. Our Facilities segment results for the comparative periods were impacted by:

- Rail Terminals — For the three and six months ended June 30, 2015, revenues from our rail activities decreased by $1 million and $10 million, respectively, due to lower rail fees related to the movement of certain volumes of Bakken crude oil, primarily to our St. James rail terminal, partially offset by revenues from our Bakersfield rail terminal that came online in the fourth quarter of 2014.
- NGL Storage, NGL Fractionation and Canadian Gas Processing Activities — Revenues from our NGL storage, NGL fractionation and Canadian gas processing activities increased by $2 million for the three month comparative periods presented and decreased by $4 million for the six month comparative periods. Both the three and six month periods in 2015 were favorably impacted by higher facility fees at certain of our storage and gas processing facilities, largely offset by unfavorable foreign currency effects of $8 million and $17 million for the three and six month comparative periods, respectively, due to the depreciation of CAD relative to USD. The six month comparative period was further unfavorably impacted by lower physical processing gains during 2015 related to component mix at our fractionation facilities and significantly lower NGL prices. NGL fractionation volumes increased for the 2015 periods due to higher NGL supply volumes from western Canada; however, there was not a corresponding increase in revenue as the impacted facilities charge a fixed monthly fee.
- Gulf Coast Gas Processing Activities — Revenues from our Gulf Coast gas processing activities decreased by $3 million and $7 million for the three and six months ended June 30, 2015, respectively, compared to the three and six months ended June 30, 2014, primarily due to lower volumes and decreased margins driven by lower commodity prices.

Additional noteworthy variances for the comparative periods presented included (i) lower revenues from our natural gas storage operations due to less favorable market conditions during the 2015 periods and (ii) higher volumes and revenues from our crude oil storage activities primarily resulting from capacity expansions at our St. James and Cushing terminals, partially offset by decreased demand for storage at certain of our California facilities.

*Field Operating Costs.* Field operating costs (excluding equity-indexed compensation expense) decreased for the three and six months ended June 30, 2015 compared to the three and six months ended June 30, 2014 primarily due to a decrease in maintenance and repair costs and lower gas and power costs largely associated with our NGL fractionation and Canadian natural gas processing activities. These decreases were partially offset by higher property taxes and salary and related expenses primarily associated with rail facilities. Favorable foreign exchange effects of $5 million and $9 million for the comparable three and six month periods, respectively, further drove the decrease in field operating costs.

*General and Administrative Expenses.* The increase in general and administrative expenses (excluding equity-indexed compensation expense) during the six months ended June 30, 2015 over the comparable 2014 period was primarily due to a change in the allocation of shared costs and increased legal fees.

*Maintenance Capital.* The increase in maintenance capital for the three and six months ended June 30, 2015 compared to the three and six months ended June 30, 2014 was primarily due to various tank and facility projects and timing of equipment replacements. The three month comparative period was also impacted by a change in classification in the three months ended June 30, 2014 of certain maintenance capital costs to our Transportation segment.

### 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. 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 and NGL sales volumes), (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. We do not anticipate that future changes in revenues resulting from variances in commodity prices will be a primary driver of segment profit.

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

*(in millions, except per barrel data)*

| Operating Results (1) | Three Months Ended June 30, 2015 | 2014 | Favorable/ (Unfavorable) Variance $% |  | Six Months Ended June 30, 2015 | 2014 | Favorable/ (Unfavorable) Variance $% |  |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Revenues | $6,351 | $10,860 | $(4,509) | (42)% | $11,984 | $22,228 | $(10,244) | (46)% |
| Purchases and related costs (2) | (6,168) | (10,578) | 4,410 | 42% | (11,521) | (21,553) | 10,032 | 47% |
| Field operating costs (3) | (110) | (112) | 2 | 2% | (227) | (218) | (9) | (4)% |
| Equity-indexed compensation expense - operations | — | (1) | 1 | 100% | (1) | (2) | 1 | 50% |
| Segment general and administrative expenses (3) (4) | (27) | (27) | — | —% | (54) | (53) | (1) | (2)% |
| Equity-indexed compensation expense - general and administrative | (5) | (9) | 4 | 44% | (10) | (20) | 10 | 50% |
| Segment profit | $41 | $133 | $(92) | (69)% | $171 | $382 | $(211) | (55)% |
| Maintenance capital | $2 | $1 | $(1) | (100)% | $4 | $4 | $— | —% |
| Segment profit per barrel | $0.40 | $1.37 | $(0.97) | (71)% | $0.79 | $1.89 | $(1.10) | (58)% |

*(in thousands of barrels per day)*

| Average Daily Volumes | Three Months Ended June 30, 2015 | 2014 | Favorable/ (Unfavorable) Variance Volume% |  | Six Months Ended June 30, 2015 | 2014 | Favorable/ (Unfavorable) Variance Volume% |  |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Crude oil lease gathering purchases | 967 | 931 | 36 | 4% | 974 | 912 | 62 | 7% |
| NGL sales | 158 | 139 | 19 | 14% | 222 | 205 | 17 | 8% |
| Supply and Logistics segment total | 1,125 | 1,070 | 55 | 5% | 1,196 | 1,117 | 79 | 7% |

(1) Revenues and costs include intersegment amounts.

(2) Purchases and related costs include interest expense (related to hedged inventory purchases) of $2 million and $3 million for the three and six months ended June 30, 2015, respectively, and $5 million and $7 million for the three and six months ended June 30,2014, respectively.

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

(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.

The following table presents the range of the NYMEX WTI benchmark price of crude oil during the periods indicated (in dollars per barrel):

|  | NYMEX WTI Crude Oil Price Low | High |
| --- | ---: | ---: |
| Three months ended June 30, 2015 | $49 | $61 |
| Three months ended June 30, 2014 | $99 | $108 |
| Six months ended June 30, 2015 | $43 | $61 |
| Six months ended June 30, 2014 | $91 | $108 |

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 decreased for the three and six months ended June 30, 2015 due to lower crude oil and NGL prices relative to the comparative 2014 periods.

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 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.

*Net Operating Revenues and Volumes.* Our Supply and Logistics segment revenues, net of purchases and related costs, decreased for the three and six months ended June 30, 2015 compared to the three and six months ended June 30, 2014. The following summarizes the more significant items in the comparative periods:

- Crude Oil Operations — Net revenues from our crude oil supply and logistics activities decreased for the three and six months ended June 30, 2015 as compared to the same periods in 2014 primarily due to the compression of certain differentials during the 2015 periods, which resulted in fewer opportunities to capture above-baseline margins as compared to 2014. Such unfavorable results were partially offset by revenues from opportunities created by the contango market structure during the 2015 periods.
- NGL Operations — Net revenues from our NGL operations were relatively consistent for the three months ended June 30, 2015 compared to the three months ended June 30, 2014. Net revenues increased for the comparative six-month periods, primarily due to higher sales volumes during the end of our 2014-2015 winter heating season, partially offset by increased facility fees.
- Natural Gas Storage Commercial Optimization — During the first quarter of 2014, our natural gas storage commercial optimization activities were unfavorably impacted by costs incurred to manage deliverability requirements in conjunction with the extended period of severe cold weather. We did not incur similar costs 45

during 2015 and, therefore, we experienced more favorable results from our natural gas storage activities for the six months ended June 30, 2015 as compared to the six-month 2014 period.

- Impact from Certain Derivative Activities, Net of Inventory Valuation Adjustments — The mark-to-market of certain of our derivative activities impacted our net revenues as shown in the table below for the periods indicated (in millions):

|  | Three Months Ended June 30, 2015 | 2014 | Variance $% |  | Six Months Ended June 30, 2015 | 2014 | Variance $% |  |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Gains/(losses) from certain derivative activities net of inventory valuation adjustments (1) | $(66) | $(15) | $(51) | (340)% | $(159) | $51 | $(210) | (412)% |

(1) Includes mark-to-market and other gains and losses resulting from certain derivative instruments that are related to underlying activities in another period (or the reversal of mark-to-market gains and losses from a prior period), gains and losses on certain derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable. See Note 8 to our Condensed Consolidated Financial Statements for a comprehensive discussion regarding our derivatives and risk management activities.

- Long-Term Inventory Costing Adjustment — Our operating results are impacted by changes in the weighted average cost of our crude oil and NGL inventory pools that result from price movements during the periods. Such costing adjustments resulted in a favorable impact of $23 million for the three months ended June 30, 2015 due to price increases during the period; however, the six month 2015 period was unfavorably impacted by $15 million due to price decreases. These costing adjustments related to long-term inventory necessary to meet our minimum inventory requirements in third-party assets and other working inventory that was needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future.
- Foreign Exchange — During 2015, there were fluctuations in the value of CAD to USD, resulting in net foreign exchange gains on U.S. denominated net assets within our Canadian operations of $30 million for the six months ended June 30, 2015.

*Field Operating Costs.* The increase in field operating costs (excluding equity-indexed compensation expense) for the six months ended June 30, 2015 compared to the six months ended June 30, 2014 was primarily due to increases in driver salaries and related expenses and trucking costs associated with higher crude oil lease gathering purchases volumes. This increase was partially offset by a reduction in fuel costs due to lower average diesel fuel cost per gallon.

### Other Income and Expenses

### Depreciation and Amortization

Depreciation and amortization expense increased for the three and six months ended June 30, 2015 compared to the three and six months ended June 30, 2014, primarily due to various internal growth projects completed since June 30, 2014.

### Interest Expense

The increase in interest expense for the three and six months ended June 30, 2015 over the three and six months ended June 30, 2014 was primarily due to a higher weighted average debt balance driven by PAA senior notes issuances in April, September and December of 2014 for an aggregate of $2.6 billion.

### Income Tax Expense

Income tax expense increased for the three months ended June 30, 2015 compared to the three months ended June 30, 2014 primarily due to higher deferred income tax expense associated with the amortization of our deferred tax asset, an Alberta, Canada provincial tax rate increase of 2% enacted during the 2015 period, as well as higher current income tax expense as a result of increased quarter-over-quarter taxable earnings from our Canadian operations. The increase was partially offset by a deferred income tax benefit associated with derivative mark-to-market losses in our Canadian operations during the 2015 period.

Income tax expense decreased for the six months ended June 30, 2015 compared to the six months ended June 30, 2014 primarily due to a deferred income tax benefit associated with derivative mark-to-market losses in our Canadian operations during the 2015 period. This benefit was partially offset by higher deferred income tax expense associated with the amortization of our deferred tax asset, an Alberta, Canada provincial tax rate increase of 2% enacted during the second quarter of 2015, as well as higher current income tax expense resulting from increased year-over-year taxable earnings from our Canadian operations.

### Outlook

Primarily as a result of advances in drilling and completion techniques and their application to a number of large-scale shale and resource plays occurring contemporaneously with attractive crude oil and liquids prices, U.S. crude oil and liquids production over the last several years has increased rapidly in multiple regions in the lower 48 states. This has been particularly true for light crudes and condensates. Similar resource development activities in Canada and ongoing oil sands development activities have also led to increased Canadian crude oil production. Additionally, the crude oil market has periodically experienced high levels of volatility in location and quality differentials as a result of the confluence of regional infrastructure constraints in North America, rapid and unexpected changes in crude oil qualities, international supply issues, and regional downstream operating issues. During 2013 and to a lesser degree 2014, these market conditions had a positive impact on our profitability as our business strategy and asset base positioned us to capitalize on opportunities created by the volatile environment.

However, over the last several years the combination of surging North American liquids production, relatively flat liquids production for the rest of the world and relatively modest growth in global liquids demand has led to a supply imbalance, which has further led to a significant and rapid reduction in petroleum prices and compression of basis differentials in a number of locations. While we believe that our business model and asset base have minimal direct exposure to petroleum prices, our performance is influenced by certain differentials and overall North American production levels, which in turn are impacted by major price movements. The meaningful decrease in crude oil prices during the second half of 2014 and first seven months of 2015 have led many producers, including producers that impact North American production levels, to significantly scale back capital programs for the next year or more. While we believe that the large North American resource base remains intact and will be developed, such production will likely take place at a slower pace and previously anticipated peak production levels will likely be reduced. This transitioning crude oil market may present challenges to our business model and asset base and may impact the rate of cash flow and distribution growth that we would have otherwise experienced over the next several years. In addition, increased competition and compressed differentials may drive lower volumes and lower unit margins in parts of our business, including our Supply and Logistics segment.

While we believe that these recent market developments should ultimately slow down crude oil supply growth and contribute toward bringing the markets back to equilibrium, there can be no assurance that such equilibrium will be achieved or that we will not be negatively impacted by declining crude oil supply, unfavorable volatility or challenging capital markets conditions. Additionally, construction of additional infrastructure by us and our competitors will likely continue to reduce existing infrastructure constraints, which could further reduce unit margins in our various segments, and underutilization of midstream assets resulting from continued production declines could have a similar unfavorable impact on volumes and unit margins. Finally, we cannot be certain that our expansion efforts will generate targeted returns or that any future acquisition activities will be successful. See “Risk Factors - Risks Related to PAA’s Business” discussed in Item 1A of our 2014 Annual Report on Form 10-K.

### Liquidity and Capital Resources

### General

On a consolidated basis, our primary sources of liquidity are (i) cash flow from operating activities, (ii) borrowings under credit facilities or the PAA commercial paper program and (iii) funds received from PAA’s 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 Class A shareholders and noncontrolling interests. We generally expect to fund our short-term cash requirements through cash flow generated from operating activities and/or borrowings under the PAA commercial paper program or the credit facilities. In addition, we generally expect to fund our long-term needs, such as those resulting from expansion activities or acquisitions and refinancing 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 PAA equity or debt securities. As of June 30, 2015, we had a working capital deficit of $529 million and approximately $3.1 billion of liquidity available to meet our ongoing operating, investing and financing needs as noted below (in millions):

|  | As of June 30, 2015 |
| --- | ---: |
| Availability under PAA senior unsecured revolving credit facility (1) | $1,586 |
| Availability under PAA senior secured hedged inventory facility (1) | 1,351 |
| Availability under PAA senior unsecured 364-day revolving credit facility | 1,000 |
| Amounts outstanding under PAA commercial paper program | (885) |
| Subtotal | 3,052 |
| Availability under AAP senior secured revolving credit facility | 15 |
| Cash and cash equivalents | 30 |
| Total | $3,097 |

(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 PAA 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 Item 1A “Risk Factors” of our 2014 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, certain of which provide the backstop for the PAA commercial paper program, is subject to ongoing compliance with covenants. As of June 30, 2015, PAA and AAP 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 derivatives, see “Liquidity and Capital Resources—Cash Flow from Operating Activities” under Item 7 of our 2014 Annual Report on Form 10-K.

Net cash provided by operating activities for the first six months of 2015 and 2014 was $654 million and $954 million, respectively, and primarily resulted from earnings from our operations. Additionally, changes in our inventory levels during these periods are discussed further below, including related impact, if any, to our cash flow from operating activities.

During the six months ended June 30, 2015, we increased the volume of crude oil inventory that we held, primarily as a result of storing such inventory due to contango market conditions. These increases were primarily funded with proceeds received from the seasonal sale of our NGL and natural gas inventory and thus did not significantly impact cash provided by operating activities during the period.

During the first six months of 2014, we decreased the volume of inventory that we held (including margin balances required as part of our hedging activities), primarily due to the sale of NGL and natural gas inventory related to high demand for product used for heating during the extended 2013-2014 winter season. The net proceeds received from liquidation of such inventory were used to repay borrowings under the PAA commercial paper program and favorably impacted cash provided by operating activities.

### Acquisitions and Capital Expenditures

In addition to operating needs discussed above, we also use cash for our acquisition activities and capital projects. We have made and will continue to make capital expenditures for acquisitions, expansion capital and maintenance capital.

*2015 Capital Projects.* See “—Acquisitions and Capital Projects” for detail of our projected capital expenditures for the year ending December 31, 2015. We expect the majority of funding for our remaining 2015 capital program will be provided by borrowings under the PAA commercial paper program as well as through proceeds received from PAA’s March 2015 underwritten equity offering.

### Equity and Debt Financing Activities

On a consolidated basis, our financing activities primarily relate to funding acquisitions, expansion capital projects and refinancing of 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 PAA equity offerings, PAA senior notes offerings and borrowings and repayments under credit facilities or the PAA commercial paper program, as well as payment of distributions to our Class A shareholders and noncontrolling interests.

*PAA Registration Statements.* PAA periodically accesses the capital markets for both equity and debt financing. PAA has filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows PAA to issue up to an aggregate of $2.0 billion of debt or equity securities (“Traditional Shelf”). All issuances of PAA equity securities associated with PAA’s continuous offering program, as discussed further below, have been issued pursuant to the Traditional Shelf. At June 30, 2015, PAA had approximately $555 million of unsold securities available under the Traditional Shelf. PAA also has access to a universal shelf registration statement (“WKSI Shelf”), which provides it with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and capital needs. PAA’s March 2015 underwritten equity offering, as discussed further below, was conducted under PAA’s WKSI Shelf.

*PAA Continuous Offering Program*. During the six months ended June 30, 2015, PAA issued an aggregate of approximately 1.1 million common units under its continuous offering program, generating proceeds of $58 million. The net proceeds from sales were used for general partnership purposes.

*Underwritten Offering*. In March 2015, PAA completed an underwritten public offering of 21.0 million common units generating net proceeds of approximately $1.0 billion, net of costs associated with the offering. We used a portion of the net proceeds from this offering to repay outstanding borrowings under PAA’s commercial paper program and we used the remaining net proceeds for general partnership purposes, including expenditures for our 2015 capital program.

*Credit Agreements, Commercial Paper Program and Indentures.* The PAA credit agreements (which impact the ability to access the PAA commercial paper program because they provide the backstop that supports PAA’s short-term credit ratings), the AAP credit agreement and the indentures governing PAA’s senior notes contain cross-default provisions. A default under the credit agreements would permit the lenders to accelerate the maturity of the outstanding debt. As long as PAA and AAP are in compliance with the provisions in the credit agreements, their ability to make distributions of available cash is not restricted. PAA and AAP were in compliance with the covenants contained in the credit agreements and indentures as of June 30, 2015.

During the six months ended June 30, 2015, we had net borrowings under credit agreements and the PAA commercial paper program of $175 million. These net borrowings resulted primarily from funding needs for (i) internal capital projects, (ii) repayment of the PAA $150 million, 5.25% senior notes that matured in June 2015 and (iii) other general partnership purposes.

During the six months ended June 30, 2014, we had net repayments under credit agreements and the PAA commercial paper program of $333 million. The net repayments resulted primarily from cash flow from operating activities, including sales of NGL and natural gas inventory that was liquidated during the periods, as well as cash received from PAA’s debt and equity activities.

In January 2015, PAA entered into a new $1.0 billion, 364-day senior unsecured credit agreement. Borrowings, if any, accrue interest based, at PAA’s election, on either the Eurocurrency Rate or the Base Rate, as defined in the agreement, in each case plus a margin based on PAA’s credit rating at the applicable time.

As mentioned above, in June 2015, PAA’s $150 million, 5.25% senior notes matured and were repaid with cash on hand and proceeds from borrowings under the PAA commercial paper program.

PAA’s $400 million, 3.95% senior notes will mature in September 2015. We intend to use borrowings under the PAA commercial paper program to repay these senior notes when they mature.

### Distributions Paid to Our Class A Shareholders and Noncontrolling Interests

*Distributions to our Class A shareholders.* We distribute 100% of our available cash within 55 days following the end of each quarter to Class A shareholders of record. 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, 2015, we will pay a quarterly distribution of $0.227 per Class A share. This distribution represents a year-over-year distribution increase of approximately 23.8%. See Note 7 to our Condensed Consolidated Financial Statements for details of distributions paid. Also, see Item 5. “Market for Registrant’s Shares, Related Shareholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy” included in our 2014 Annual Report on Form 10-K for additional discussion regarding distributions.

*Distributions to noncontrolling interests.* Distributions to noncontrolling interests represent amounts paid on interests in consolidated entities that are not owned by us. During the six months ended June 30, 2015 and 2014, we paid distributions of $713 million and $626 million, respectively, to noncontrolling interests.

We believe that we have sufficient liquid assets, cash flow from operating activities and borrowing capacity under 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 10 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 nine 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, 2015 (in millions):

|  | Remainder of 2015 | 2016 | 2017 | 2018 | 2019 | 2020 and Thereafter | Total |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Long-term debt, including current maturities and related interest payments (1) | $998 | $614 | $810 | $982 | $1,755 | $10,605 | $15,764 |
| Leases (2) | 88 | 188 | 170 | 149 | 124 | 547 | 1,266 |
| Other obligations (3) | 325 | 369 | 94 | 42 | 30 | 178 | 1,038 |
| Subtotal | 1,411 | 1,171 | 1,074 | 1,173 | 1,909 | 11,330 | 18,068 |
| Crude oil, natural gas, NGL and other purchases (4) | 3,747 | 3,839 | 2,754 | 1,814 | 1,015 | 2,642 | 15,811 |
| Total | $5,158 | $5,010 | $3,828 | $2,987 | $2,924 | $13,972 | $33,879 |

(1) Includes debt service payments, interest payments due on PAA’s senior notes, interest payments on long-term borrowings outstanding under the AAP credit agreement, the commitment fee on assumed available capacity under the PAA revolving credit facilities and long-term borrowings under the PAA commercial paper program. Although there may be short-term borrowings under the PAA revolving credit facilities and the PAA 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 the PAA commercial paper program) in the amounts above.

(2) Leases are primarily for (i) surface rentals, (ii) office rent, (iii) pipeline assets and (iv) trucks, trailers and railcars. Includes both capital and operating leases as defined by FASB guidance.

(3) Includes (i) other long-term liabilities, (ii) storage, processing and transportation agreements and (iii) non-cancelable 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 2015. 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, derivative transactions and construction activities. At June 30, 2015 and December 31, 2014, we had outstanding letters of credit of approximately $63 million and $87 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 a discussion regarding our critical accounting policies and estimates, see “Critical Accounting Policies and Estimates” under Item 7 of our 2014 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:

- our ability to pay distributions to our Class A shareholders;
- our expected receipt of, and amounts of, distributions from Plains AAP, L.P.;
- 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;
- the currency exchange rate of the Canadian dollar;
- continued creditworthiness of, and performance by, our counterparties, including financial institutions and trading companies with which we do business;
- maintenance of PAA’s credit rating and ability to receive open credit from suppliers and trade counterparties;
- weather interference with business operations or project construction, including the impact of extreme weather events or conditions;
- 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 historical operations;
- increased costs, or lack of availability, of insurance;
- non-utilization of our assets and facilities;
- 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;
- fluctuations in the debt and equity markets, including the price of PAA’s units at the time of vesting under its 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 2014 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.

## Market risk

As filed, 6,213 characters.

We are exposed to various market risks, including (i) commodity price risk, (ii) interest rate risk and (iii) currency exchange rate risk. We use various derivative instruments to manage such risks and, in certain circumstances, to realize incremental margin during volatile market conditions. Our risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our exchange-cleared and over-the-counter positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. We have a risk management function that has direct responsibility and authority for our risk policies, related controls around commercial activities and certain aspects of corporate risk management. Our risk management function also approves all new risk management strategies through a formal process. The following discussion addresses each category of risk.

### Commodity Price Risk

We use derivative instruments to hedge commodity price risk associated with the following commodities:

- *Crude oil*

We utilize crude oil derivatives to hedge commodity price risk inherent in our Supply and Logistics and Transportation segments. Our objectives for these derivatives include hedging anticipated purchases and sales, stored inventory, and storage capacity utilization. We manage these exposures with various instruments including exchange-traded and over-the-counter futures, forwards, swaps and options.

- *Natural gas*

We utilize natural gas derivatives to hedge commodity price risk inherent in our Supply and Logistics and Facilities segments. Our objectives for these derivatives include hedging anticipated purchases and sales and managing our anticipated base gas requirements. We manage these exposures with various instruments including exchange-traded futures, swaps and options.

- *NGL and other*

We utilize NGL derivatives, primarily butane and propane derivatives, to hedge commodity price risk inherent in our Supply and Logistics segment. Our objectives for these derivatives include hedging anticipated purchases and sales and stored inventory. We manage these exposures with various instruments including exchange-traded and over-the-counter futures, forwards, swaps and options.

See Note 8 to our Condensed Consolidated Financial Statements for further discussion regarding our hedging strategies and objectives.

Our policy is to (i) purchase only product for which we have a market, (ii) hedge our purchase and sales contracts so that price fluctuations do not materially affect our operating income and (iii) not acquire and hold physical inventory or other derivative instruments for the purpose of speculating on outright commodity price changes, as these activities could expose us to significant losses.

The fair value of our commodity derivatives and the change in fair value as of June 30, 2015 that would be expected from a 10% price increase or decrease is shown in the table below (in millions):

|  | Fair Value | Effect of 10% Price Increase | Effect of 10% Price Decrease |
| --- | ---: | ---: | ---: |
| Crude oil | $2 | $(19) | $20 |
| Natural gas | (15) | $(1) | $1 |
| NGL and other | 98 | $(24) | $24 |
| Total fair value | $85 |  |  |

The fair values presented in the table above reflect the sensitivity of the derivative instruments only and do not include the effect of the underlying hedged commodity. Price-risk sensitivities were calculated by assuming an across-the-board 10% increase or decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10% change in near-term commodity prices, the fair value of our derivative portfolio would typically change less than that shown in the table as changes in near-term prices are not typically mirrored in delivery months further out.

### Interest Rate Risk

Our use of variable rate debt and any forecasted issuances of fixed rate debt expose us to interest rate risk. Therefore, from time to time we use interest rate derivatives to hedge interest rate risk associated with anticipated interest payments and, in certain cases, outstanding debt instruments. All of PAA’s senior notes are fixed rate notes and thus are not subject to interest rate risk. The majority of our variable rate debt at June 30, 2015, $1.4 billion, is subject to interest rate re-sets, which range from one day to one month. The average interest rate on variable rate debt that was outstanding during the six months ended June 30, 2015 was 1.3%, based upon rates in effect during such period. The fair value of our interest rate derivatives is an asset of $9 million as of June 30, 2015. A 10% increase in the forward LIBOR curve as of June 30, 2015 would result in an increase of $63 million to the fair value of our interest rate derivatives. A 10% decrease in the forward LIBOR curve as of June 30, 2015 would result in a decrease of $63 million to the fair value of our interest rate derivatives. See Note 8 to our Condensed Consolidated Financial Statements for a discussion of our interest rate risk hedging activities.

### Currency Exchange Rate Risk

We use foreign currency derivatives to hedge foreign currency exchange rate risk associated with our exposure to fluctuations in the USD-to-CAD exchange rate. Because a significant portion of our Canadian business is conducted in CAD and, at times, a portion of our debt is denominated in CAD, we use certain financial instruments to minimize the risks of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts, forwards and options. The fair value of our foreign currency derivatives is a liability of $2 million as of June 30, 2015. A 10% increase in the exchange rate (USD-to-CAD) would result in a decrease of $21 million to the fair value of our foreign currency derivatives. A 10% decrease in the exchange rate (USD-to-CAD) would result in an increase of $21 million to the fair value of our foreign currency derivatives. See Note 8 to our Condensed Consolidated Financial Statements for a discussion of our currency exchange rate risk hedging.

## Controls and procedures

As filed, 1,826 characters.

### Disclosure Controls and Procedures

We maintain written disclosure controls and procedures, which we refer to as our “DCP.” Our DCP is designed to ensure that information required to be disclosed by us in reports that we file under the Securities Exchange Act of 1934 (the “Exchange Act”) is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure.

Applicable SEC rules require an evaluation of the effectiveness of our DCP. Management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our DCP as of June 30, 2015, the end of the period covered by this report, and, based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our DCP is effective.

### Changes in Internal Control over Financial Reporting

In addition to the information concerning our DCP, we are required to disclose certain changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting during the second quarter of 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

### Certifications

The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a) are filed with this report as Exhibits 31.1 and 31.2. The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. 1350 are furnished with this report as Exhibits 32.1 and 32.2.

## Risk factors

As filed, 384 characters.

For a discussion regarding our risk factors, see Item 1A of our 2014 Annual Report on Form 10-K. Those risks and uncertainties are not the only ones facing us and there may be additional matters of which we are unaware or that we currently consider immaterial. All of those risks and uncertainties could adversely affect our business, financial condition and/or results of operations.

Filed Aug 7, 2015.
Source: SEC EDGAR, the filing index for accession 0001558370-15-001527. Last ingested by Listed: Nov 6, 2026, 12:23 ET. No prices; not investment advice.