UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 8-K

 

CURRENT REPORT
Pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934

 

Date of Report (Date of earliest event reported) — November 2, 2016

 

Plains All American Pipeline, L.P.

(Exact name of registrant as specified in its charter)

 

DELAWARE

 

1-14569

 

76-0582150

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incorporation)

 

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333 Clay Street, Suite 1600, Houston, Texas 77002

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Item 9.01.                                        Financial Statements and Exhibits

 

(d)    Exhibit 99.1 — Press Release dated November 2, 2016

 

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

 

Plains All American Pipeline, L.P. (the “Partnership”, “PAA”) today issued a press release reporting its third-quarter 2016 results. We are furnishing the press release, attached as Exhibit 99.1, pursuant to Item 2.02 and Item 7.01 of Form 8-K.  Pursuant to Item 7.01, we are also providing detailed guidance of financial performance for the fourth quarter and full year of 2016 and preliminary guidance for 2017.  In accordance with General Instruction B.2. of Form 8-K, the information presented herein under Item 2.02 and Item 7.01 shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), nor shall it be deemed incorporated by reference in any filing under the Exchange Act or Securities Act of 1933, as amended, except as expressly set forth by specific reference in such a filing.

 

Disclosure of the 2016 Fourth-Quarter and Full Year 2017 Preliminary Guidance

 

We based our guidance for the three-month and twelve-month periods ending December 31, 2016 on assumptions and estimates that we believe are reasonable, given our assessment of historical trends (modified for changes in market conditions, including an assumption that competitive crude oil and NGL market conditions continue), business cycles and other reasonably available information. Projections covering multi-quarter periods contemplate inter-period changes in future performance resulting from new expansion projects, seasonal operational changes (such as NGL sales) and acquisition synergies. Our 2016 guidance and our preliminary 2017 guidance do not include the impact of any pending or future acquisitions.  Such guidance is also based on the assumption that the simplification transaction announced on July 11, 2016 by PAA and PAGP closes on November 15th, 2016.  Our assumptions and future performance, however, are both subject to a wide range of business risks and uncertainties, so we can provide no assurance that assumed events or outcomes will actually take place as assumed or that actual performance will fall within the guidance ranges.  Please refer to information under the caption “Forward-Looking Statements” included in this document. These risks and uncertainties, as well as other unforeseeable risks and uncertainties, could cause our actual results to differ materially from those in the following table. The operating and financial guidance provided in the following pages is given as of the date hereof, based on information known to us as of November 1, 2016. We undertake no obligation to publicly update or revise any forward-looking statements.

 

To supplement our financial information presented in accordance with GAAP, management uses additional measures known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future. 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 to supplement related GAAP financial measures, (i) provide additional information about our core operating performance and ability to fund distributions to our unitholders through cash generated by our operations and (ii) provide investors with the same financial analytical framework upon which management bases financial, operational, compensation and planning/budgeting decisions. We also present these and additional non-GAAP financial measures, including adjusted net income attributable to PAA, basic and diluted adjusted net income per common unit and adjusted segment profit, as they are measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. The calculation of these non-GAAP measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) the mark-to-market of derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), the mark-to-market related to our Preferred Distribution Rate Reset Option, gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (iii) long-term inventory costing adjustments, (iv) items that are not indicative of our core operating results and business outlook and/or (v) other items that we believe should be excluded in understanding our core operating performance. These measures may further be adjusted to include amounts related to deficiencies associated with minimum volume commitments (“MVC’s”) whereby we have billed the counterparties for their deficiency obligation and such amounts are recognized as deferred revenue in “Accounts payable and accrued liabilities” in our Condensed Consolidated Financial Statements. Such amounts are presented net of applicable amounts subsequently recognized into revenue. Furthermore, the calculation of these measures contemplates tax effects as a separate reconciling item, where applicable.  We have defined all such items as “Selected Items Impacting Comparability.” Due to the nature of the selected items, certain selected items impacting comparability may impact certain non-GAAP financial measures, referred to as adjusted results, but not impact other non-GAAP financial measures. We consider an understanding of these selected items impacting comparability to be material to the evaluation of our operating results and prospects.

 

2



 

Our definition and calculation of certain non-GAAP financial measures may not be comparable to similarly-titled measures of other companies. Net income represents the most directly comparable GAAP measure to EBITDA. In Note 9, we reconcile net income to EBITDA, adjusted EBITDA and Implied DCF for the periods presented. In addition, we encourage you to visit our website at www.plainsallamerican.com (in particular the section under “Financial Information” entitled “Non-GAAP Reconciliations” within the “Investor Relations” tab), which presents a reconciliation of EBITDA as well as certain other commonly used non-GAAP and supplemental financial measures.

 

3



 

Plains All American Pipeline, L.P.

Operating and Financial Guidance

(in millions, except per unit data)

 

 

 

Actual

 

Guidance (a)

 

 

 

9 Months

 

3 Months Ending

 

12 Months Ending

 

 

 

Ended

 

Dec 31, 2016

 

Dec 31, 2016

 

 

 

Sep 30, 2016

 

Low

 

High

 

Low

 

High

 

Segment Profit

 

 

 

 

 

 

 

 

 

 

 

Net revenues (including equity earnings in unconsolidated entities)

 

$

2,364

 

$

943

 

$

983

 

$

3,307

 

$

3,347

 

Field operating costs

 

(893

)

(311

)

(303

)

(1,204

)

(1,196

)

General and administrative expenses

 

(210

)

(75

)

(73

)

(285

)

(283

)

 

 

1,261

 

557

 

607

 

1,818

 

1,868

 

Depreciation and amortization expense

 

(351

)

(120

)

(116

)

(471

)

(467

)

Interest expense, net

 

(339

)

(121

)

(117

)

(460

)

(456

)

Income tax expense

 

(15

)

(47

)

(43

)

(62

)

(58

)

Other income / (expense), net

 

46

 

 

 

46

 

46

 

Net Income

 

602

 

269

 

331

 

871

 

933

 

Net income attributable to noncontrolling interests

 

(3

)

(1

)

(1

)

(4

)

(4

)

Net Income Attributable to PAA

 

$

599

 

$

268

 

$

330

 

$

867

 

$

929

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income allocated to common unitholders (b)

 

$

110

 

$

234

 

$

296

 

$

345

 

$

405

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic net income per common unit (b)

 

 

 

 

 

 

 

 

 

 

 

Weighted average common units outstanding (c)

 

399

 

660

 

660

 

464

 

464

 

Net income per common unit

 

$

0.27

 

$

0.36

 

$

0.45

 

$

0.74

 

$

0.87

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted net income per common unit(b)

 

 

 

 

 

 

 

 

 

 

 

Weighted average common units outstanding (c)

 

400

 

662

 

662

 

466

 

466

 

Net income per common unit

 

$

0.27

 

$

0.35

 

$

0.45

 

$

0.74

 

$

0.87

 

 

 

 

 

 

 

 

 

 

 

 

 

EBITDA

 

$

1,307

 

$

557

 

$

607

 

$

1,864

 

$

1,914

 

 

 

 

 

 

 

 

 

 

 

 

 

Selected Items Impacting Comparability

 

 

 

 

 

 

 

 

 

 

 

Losses from derivative activities net of inventory valuation adjustments

 

$

(147

)

$

 

$

 

$

(147

)

$

(147

)

Long-term inventory costing adjustments

 

6

 

 

 

6

 

6

 

Deficiencies under minimum volume commitments, net

 

(59

)

(2

)

(2

)

(61

)

(61

)

Equity-indexed compensation expense

 

(23

)

(10

)

(10

)

(33

)

(33

)

Net gain/(loss) on foreign currency revaluation

 

(1

)

 

 

(1

)

(1

)

Selected items impacting comparability of EBITDA

 

$

(224

)

$

(12

)

$

(12

)

$

(236

)

$

(236

)

Tax effect on selected items impacting comparability

 

40

 

 

 

40

 

40

 

Selected items impacting comparability of net income attributable to PAA

 

$

(184

)

$

(12

)

$

(12

)

$

(196

)

$

(196

)

 

 

 

 

 

 

 

 

 

 

 

 

Excluding Selected Items Impacting Comparability

 

 

 

 

 

 

 

 

 

 

 

Adjusted segment profit

 

 

 

 

 

 

 

 

 

 

 

Transportation

 

$

825

 

$

258

 

$

273

 

$

1,083

 

$

1,098

 

Facilities

 

497

 

158

 

168

 

655

 

665

 

Supply and Logistics

 

208

 

153

 

178

 

361

 

386

 

Other income / (expense), net

 

1

 

 

 

1

 

1

 

Adjusted EBITDA

 

$

1,531

 

$

569

 

$

619

 

$

2,100

 

$

2,150

 

Adjusted net income attributable to PAA

 

$

783

 

$

280

 

$

342

 

$

1,063

 

$

1,125

 

Basic adjusted net income per common unit (b)

 

$

0.73

 

$

0.38

 

$

0.47

 

$

1.16

 

$

1.29

 

Diluted adjusted net income per common unit (b)(c)

 

$

0.72

 

$

0.37

 

$

0.47

 

$

1.15

 

$

1.28

 

 


(a)

The assumed average foreign exchange rate is $1.30 Canadian dollar (CAD) to $1.00 U.S. dollar (USD) for the three-month period ending December 31, 2016. The rate as of November 1, 2016 was $1.34 CAD to $1.00 USD. We do not anticipate that fluctuations in the foreign exchange rate will have significant impact on aggregate reported financial results, but such fluctuations will result in variations between segments.

 

 

(b)

For purposes of determining net income per common unit, Net Income Attributable to PAA is allocated among our Series A Preferred Unitholders, Common Unitholders and General Partner interest as prescribed by applicable authoritative accounting guidance for calculating earnings per unit including application of the two-class method in accordance with applicable authoritative accounting guidance. Under the two-class method, we allocate Net Income Attributable to PAA based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner, common unitholders and participating securities in accordance with the contractual terms of the partnership agreement and as further prescribed under the two-class method. See Note 5 for additional information regarding our assumed capital structure for three month period ending December 31, 2016.

 

 

(c)

Basic and diluted weighted average common units outstanding for the three- and twelve-month periods ending December 31, 2016 are calculated giving effect to the Simplification Transactions and assume the associated units are outstanding for the fourth quarter of 2016.  See Note 5 for additional information regarding our assumed capital structure for three month period ending December 31, 2016. Diluted net income per common unit is computed based on the weighted average number of common units outstanding plus the effect of dilutive potential units outstanding during the period using the two-class method, unless the effects of such units are anti-dilutive.

 

4



 

Notes and Significant Assumptions:

 

1.              Definitions.

 

EBITDA

 

Earnings before interest, taxes and depreciation and amortization

Segment Profit

 

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

DCF

 

Distributable cash flow

Bbls/d

 

Barrels per day

Mcf
Bcf

 

Thousand cubic feet
Billion cubic feet

LTIP

 

Long-term incentive plan

NGL

 

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

FX

 

Foreign currency exchange

G&A

 

General and administrative

General partner (GP)

 

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

 

2.              Operating Segments. We manage our operations through three operating segments:  Transportation, Facilities, and Supply and Logistics. The following is a brief explanation of the operating activities for each segment as well as key metrics.

 

a.              Transportation. Our Transportation segment operations generally consist of fee-based activities associated with transporting crude oil and NGL on pipelines, gathering systems, trucks and barges. The Transportation segment generates revenue through a combination of tariffs, third-party pipeline capacity agreements and other transportation fees. Our transportation segment also includes equity earnings from our investments in the entities that own BridgeTex, Cheyenne, Eagle Ford, Frontier, Saddlehorn, STACK, White Cliffs, and Butte pipeline systems as well as Settoon Towing, in which we own interests ranging from 22% to 50%.  We account for these investments under the equity method of accounting.

 

Pipeline volume estimates are based on historical trends, anticipated future operating performance and assumed completion of capital projects. Actual volumes will be influenced by maintenance schedules at refineries, drilling and completion activity levels, production trends, weather and other natural occurrences including hurricanes, changes in the quantity of inventory held in tanks, variations due to market structure and other external factors beyond our control. We forecast adjusted segment profit using the volume assumptions in the following table, priced at forecasted tariff rates, less estimated field operating costs and G&A expenses. Field operating costs do not include depreciation. Actual adjusted segment profit could vary materially depending on the level and mix of volumes transported or expenses incurred during the period, as well as any differences between forecasted and actual recognition of minimum volume commitments. The following table summarizes our total transportation volumes and is broken down by crude oil geographic area as well as total NGL and trucking volumes.

 

5



 

 

 

Actual

 

Guidance

 

 

 

9 Months

 

3 Months

 

12 Months

 

 

 

Ended

 

Ending

 

Ending

 

 

 

Sep 30, 2016

 

Dec 31, 2016

 

Dec 31, 2016

 

Average daily volumes (MBbls/d)

 

 

 

 

 

 

 

Volumes from tariff activities

 

 

 

 

 

 

 

Crude oil pipelines (by region):

 

 

 

 

 

 

 

Permian Basin (1)

 

2,129

 

2,250

 

2,159

 

South Texas / Eagle Ford (1)

 

283

 

285

 

284

 

Western

 

193

 

180

 

190

 

Rocky Mountain (1)

 

448

 

470

 

454

 

Gulf Coast

 

538

 

365

 

495

 

Central (1)

 

393

 

410

 

397

 

Canada

 

384

 

390

 

386

 

Crude oil pipelines

 

4,368

 

4,350

 

4,365

 

NGL pipelines

 

182

 

180

 

181

 

Total volumes from tariff activities

 

4,550

 

4,530

 

4,546

 

Trucking

 

113

 

110

 

112

 

Transportation segment total volumes

 

4,663

 

4,640

 

4,658

 

 

 

 

 

 

 

 

 

Adjusted segment profit per barrel ($/Bbl)

 

$

0.65

 

$

0.62

(2)

$

0.64

(2)

 

 

 

 

 

 

 

 

Adjusted segment profit (excluding MVC selected item) per barrel ($/Bbl)

 

$

0.60

 

$

0.62

(2)

$

0.61

(2)

 


(1)             Region includes volumes (attributable to our interest) from pipelines owned by unconsolidated entities.

(2)             Represents the midpoint of guidance.

 

b.              Facilities. Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services for crude oil, refined products, NGL and natural gas, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. The Facilities segment generates revenue through a combination of month-to-month and multi-year agreements and processing arrangements.

 

Revenues generated in this segment primarily include (i) fees that are generated from storage capacity agreements, (ii) terminal throughput fees that are generated when we receive crude oil, refined products or NGL from one connecting source and deliver the applicable product to another connecting carrier, (iii) loading and unloading fees at our rail terminals, (iv) fees from NGL fractionation and isomerization services, (v) fees from natural gas and condensate processing services and (vi) fees associated with natural gas park and loan activities, interruptible storage services and wheeling and balancing services.  Adjusted segment profit is forecasted using the volume assumptions in the following table, priced at forecasted rates, less estimated field operating costs and G&A expenses. Field operating costs do not include depreciation.

 

 

 

Actual

 

Guidance

 

 

 

9 Months

 

3 Months

 

12 Months

 

 

 

Ended

 

Ending

 

Ending

 

 

 

Sep 30, 2016

 

Dec 31, 2016

 

Dec 31, 2016

 

Operating Data

 

 

 

 

 

 

 

Crude oil, refined products and NGL terminalling and storage capacity (MMBbls/Mo.)

 

106

 

111

 

107

 

Rail load / unload volumes (MBbls/d)

 

97

 

45

 

84

 

Natural gas storage capacity (Bcf/Mo.)

 

97

 

97

 

97

 

NGL fractionation volumes (MBbls/d)

 

113

 

125

 

116

 

Facilities segment total volumes

 

 

 

 

 

 

 

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

 

129

 

132

 

129

 

 

 

 

 

 

 

 

 

Adjusted segment profit per barrel ($/Bbl)

 

$

0.43

 

$

0.41

(2)

$

0.43

(2)

 

 

 

 

 

 

 

 

Adjusted segment profit (excluding MVC selected item) per barrel ($/Bbl)

 

$

0.42

 

$

0.41

(2)

$

0.42

(2)

 


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

(2)             Represents the midpoint of guidance.

 

6



 

c.         Supply and Logistics. Our Supply and Logistics segment operations generally consist of the following merchant-related activities:

 

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

 

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

 

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

 

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

 

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

 

·            the purchase and sale of natural gas.

 

We characterize a substantial portion of our baseline profit generated by our Supply and Logistics segment as fee equivalent. This portion of the segment profit is generated by the purchase and resale of crude oil on an index-related basis, which results in us generating a gross margin for such activities.  This gross margin is reduced by the transportation, facilities and other logistical costs associated with delivering the crude oil to market and carrying costs for hedged inventory as well as any operating and G&A expenses.  The level of profit associated with a portion of the other activities we conduct in the Supply and Logistics segment is influenced by overall market structure and the degree of market volatility as well as variable operating expenses. Forecasted operating results for the three-month period ending December 31, 2016 reflect current market structure as well as seasonal, weather-related and other anticipated variations in crude oil, NGL and natural gas sales. Variations in weather, market structure or volatility could cause actual results to differ materially from forecasted results.

 

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

 

 

 

Actual

 

Guidance

 

 

 

9 Months

 

3 Months

 

12 Months

 

 

 

Ended

 

Ending

 

Ending

 

 

 

Sep 30, 2016

 

Dec 31, 2016

 

Dec 31, 2016

 

Average daily volumes (MBbls/d)

 

 

 

 

 

 

 

Crude oil lease gathering purchases

 

894

 

895

 

894

 

NGL sales

 

230

 

365

 

264

 

Waterborne cargos

 

7

 

10

 

8

 

Supply and Logistics total segment volumes

 

1,131

 

1,270

 

1,166

 

 

 

 

 

 

 

 

 

Adjusted segment profit per barrel ($/Bbl)

 

$

0.67

 

$

1.42

(1)

$

0.88

(1)

 


(1)             Represents the midpoint of guidance.

 

7



 

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

 

4.              Capital Expenditures and Acquisitions.  Although acquisitions constitute a key element of our growth strategy, the forecasted results and associated estimates do not include any forecasts for acquisitions that we may commit to after the date hereof. We forecast capital expenditures during calendar year 2016 to be approximately $1.425 billion for expansion projects with an additional $175 million to $185 million for maintenance capital projects. During the first nine months of 2016, we invested $1.065 billion and $128 million for expansion and maintenance projects, respectively. The following are some of the more notable projects and forecasted expenditures for the year ending December 31, 2016:

 

 

 

Calendar 2016

 

 

 

(in millions)

 

Expansion Capital

 

 

 

· Red River Pipeline (Cushing to Longview)

 

$310

 

· Fort Saskatchewan Facility Projects

 

205

 

· Permian Basin Area Pipeline Projects

 

185

 

· Saddlehorn Pipeline

 

125

 

· Diamond Pipeline

 

105

 

· Cushing Terminal Expansions

 

70

 

· St. James Terminal Expansions

 

50

 

· Caddo Pipeline

 

35

 

· Eagle Ford JV Project

 

25

 

· Cactus Pipeline

 

20

 

· Other Projects

 

295

 

 

 

$1,425

 

Potential Adjustments for Timing / Scope Refinement (1)

 

- $50 + $50

 

Total Projected Expansion Capital Expenditures

 

$1,375 - $1,475

 

 

 

 

 

Maintenance Capital Expenditures

 

$175 - $185

 

 


(1)             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 receipt of permits, or regulatory approvals and weather.

 

5.              Capital Structure. This guidance is based on our capital structure as of September 30, 2016, adjusted for estimated potential equity issuances and senior note offerings. This guidance further assumes that the simplification transaction announced by PAA and PAGP on July 11, 2016 closes on November 15th, 2016, and in connection with such closing PAA issues or agrees to issue 245.5 million common units to AAP in exchange for the cancellation of the incentive distribution rights in PAA that are owned by AAP, and the conversion of the 2% general partner interest in PAA indirectly held by AAP into a non-economic general partner interest in PAA and the assumption by PAA of AAP’s outstanding third party bank debt (the “AAP Debt Assumption”).

 

6.              Interest Expense. Debt balances, which assume the AAP Debt Assumption takes place in connection with the closing of the simplification transaction on November 15th, 2016 as described in Note 5, are projected based on estimated cash flows, estimated distribution rates, estimated capital expenditures for maintenance and expansion projects, anticipated equity proceeds from the continuous offering program, expected timing of collections and payments and forecasted levels of inventory and other working capital sources and uses. Interest rate assumptions for variable-rate debt are based on the LIBOR curve as of late October 2016.

 

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

 

7.             Income Taxes. We expect our Canadian income tax expense to be approximately $45 million and $60 million for the three-month and twelve-month periods ending December 31, 2016, respectively, of which approximately $23 million and $68 million, respectively, is classified as a current income tax expense.  For the twelve-month period ending December 31, 2016 we expect to have a deferred tax benefit of $8 million.  All or part of the annual income tax expense of $60 million may result in a tax credit to our equity holders.

 

8



 

8.              Equity-Indexed Compensation Plans. Certain grants outstanding under our various equity-indexed compensation plans contain vesting criteria that are based on a combination of performance benchmarks and service periods. The grants will vest in various percentages, typically on the later to occur of specified vesting dates and the dates on which minimum distribution levels are reached.

 

Guidance assumes a market price of $31 per unit as well as an accrual associated with awards that will vest on a certain date.  A $2 change in the unit price would change the fourth-quarter equity-indexed compensation expense by approximately $2 million. Therefore, actual net income could differ from our projections.

 

9.              Reconciliation of Net Income to EBITDA, Adjusted EBITDA, and Implied DCF. The following table reconciles net income to EBITDA, Adjusted EBITDA, and Implied DCF for the indicated periods.

 

 

 

Actual

 

Guidance

 

 

 

9 Months

 

3 Months Ending

 

12 Months Ending

 

 

 

Ended

 

Dec 31, 2016

 

Dec 31, 2016

 

 

 

Sep 30, 2016

 

Low

 

High

 

Low

 

High

 

 

 

(in millions)

 

Reconciliation to EBITDA, Adjusted EBITDA and Implied DCF

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

602

 

$

269

 

$

331

 

$

871

 

$

933

 

Interest expense, net

 

339

 

121

 

117

 

460

 

456

 

Income tax expense

 

15

 

47

 

43

 

62

 

58

 

Depreciation and amortization

 

351

 

120

 

116

 

471

 

467

 

EBITDA

 

$

1,307

 

$

557

 

$

607

 

$

1,864

 

$

1,914

 

 

 

 

 

 

 

 

 

 

 

 

 

Selected items impacting comparability of EBITDA

 

224

 

12

 

12

 

236

 

236

 

Adjusted EBITDA

 

$

1,531

 

$

569

 

$

619

 

$

2,100

 

$

2,150

 

Interest expense, net (1)

 

(327

)

(116

)

(112

)

(443

)

(439

)

Maintenance capital

 

(128

)

(57

)

(47

)

(185

)

(175

)

Current income tax expense

 

(45

)

(25

)

(21

)

(70

)

(66

)

Other, net

 

15

 

1

 

3

 

16

 

18

 

Implied DCF

 

$

1,046

 

$

372

 

$

442

 

$

1,418

 

$

1,488

 

 


(1)             Excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps.

 

Preliminary 2017 Guidance

 

There have been recent indications that the current industry cycle for crude oil markets has stabilized and upstream activity levels are increasing in certain regions. However, certain of these positive developments will impact the midstream sector on a delayed basis.  Additionally, as production growth returns in certain basins impacted by shippers with minimum volume commitments (MVCs) in excess of volumes they control, a meaningful portion of the incremental production will go to fill current MVC shortfalls on either PAA’s or competitors’ pipelines and therefore will not have a linear impact on transportation revenues. Accordingly, as a result of these factors and uncertainty generally, we anticipate the next nine months or more will continue to be challenging for the midstream sector and competition for the marginal crude oil and NGL barrel will remain high, resulting in continued margin compression.

 

Adjusted EBITDA also reflects reductions associated with recent and anticipated assets sales and assets contributed to joint ventures, which are reported on the equity method of accounting.  The impact on DCF of these reductions is partially offset by associated reductions in maintenance capital and adding back distributions in excess of our share of joint venture income. On that basis, our preliminary 2017 guidance forecast is as follows:

 

·                  Adjusted EBITDA: +/- $2.3 billion

·                  Maintenance Capital: +/- $180 million

·                  Cash Interest Expense: +/- $470 million

·                  Income Taxes & Other, net: +/- $50 million

·                  Implied Distributable Cash Flow: +/- $1.6 billion

·                  Expansion Capital: $500 million - $700 million

 

9



 

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:

 

·                  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 assets, 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;

 

·                  the effects of competition;

 

·                  failure to implement or capitalize, or delays in implementing or capitalizing, on expansion 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;

 

·                  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;

 

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

 

·                  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;

 

·                  inability to recognize current revenue attributable to deficiency payments received from customers who fail to ship or move more than minimum contracted volumes until the related credits expire or are used;

 

·                  non-utilization of our assets and facilities;

 

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

 

·                  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 our historical operations;

 

·                  the effectiveness of our risk management activities;

 

10



 

·                  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 our units at the time of vesting under our long-term incentive plans;

 

·                  risks related to the development and operation of our assets, including our ability to satisfy our contractual obligations to our customers;

 

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

 

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

 

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

 

We undertake no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in our filings with the Securities and Exchange Commission, which information is incorporated by reference herein.

 

11



 

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 

 

PLAINS ALL AMERICAN PIPELINE, L.P.

 

 

 

 

By:

PAA GP LLC, its general partner

 

 

 

 

By:

PLAINS AAP, L. P., its sole member

 

 

 

 

By:

PLAINS ALL AMERICAN GP LLC, its general partner

 

 

 

Date: November 2, 2016

By:

/s/ Sharon Spurlin

 

 

Name:

Sharon Spurlin

 

 

Title:

Vice President and Treasurer

 

12



Exhibit 99.1

 

 

FOR IMMEDIATE RELEASE

 

Plains All American Pipeline, L.P. and Plains GP Holdings Report Third-Quarter 2016 Results

 

(Houston — November 2, 2016) Plains All American Pipeline, L.P. (NYSE: PAA) and Plains GP Holdings (NYSE: PAGP) today reported third-quarter 2016 results.

 

Plains All American Pipeline, L.P.

 

Summary Financial Information (1) (unaudited)

(in millions, except per unit data)

 

 

 

Three Months Ended

 

 

 

 

Nine Months Ended

 

 

 

 

 

September 30,

 

%

 

 

September 30,

 

%

 

 

 

2016

 

2015

 

Change

 

 

2016

 

2015

 

Change

 

Net income attributable to PAA

 

$

297

 

$

249

 

19

%

 

$

599

 

$

657

 

(9

)%

Diluted net income per common unit

 

$

0.40

 

$

0.24

 

67

%

 

$

0.27

 

$

0.53

 

(49

)%

Diluted weighted average common units outstanding

 

402

 

399

 

1

%

 

400

 

395

 

1

%

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

 

 

Nine Months Ended

 

 

 

 

 

September 30,

 

%

 

 

September 30,

 

%

 

 

 

2016

 

2015

 

Change

 

 

2016

 

2015

 

Change

 

Adjusted net income attributable to PAA

 

$

293

 

$

262

 

12

%

 

$

783

 

$

887

 

(12

)%

Diluted adjusted net income per common unit

 

$

0.39

 

$

0.28

 

39

%

 

$

0.72

 

$

1.11

 

(35

)%

EBITDA

 

$

445

 

$

483

 

(8

)%

 

$

1,307

 

$

1,364

 

(4

)%

Adjusted EBITDA

 

$

450

 

$

497

 

(9

)%

 

$

1,531

 

$

1,605

 

(5

)%

Distribution per common unit declared for the period

 

$

0.550

 

$

0.700

 

(21.4

)%

 

 

 

 

 

 

 

 


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

 

“PAA reported third-quarter adjusted EBITDA of $450 million, which included solid performance in our fee-based Facilities segment and in-line performance from our fee-based Transportation segment, offset by Supply and Logistics segment performance that was below the low-end of our third quarter guidance.  Our third quarter Supply and Logistics segment was impacted by a combination of delayed EBITDA recognition associated with our NGL inventory costing and the timing of crude oil sales, as well as lower than forecasted EBITDA as a result of continued margin compression and less favorable market conditions for both our crude oil and NGL activities,” said Greg Armstrong, Chairman and CEO of Plains All American.

 

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“Looking forward, we are encouraged by recent signals that indicate the current industry cycle has reached a bottom and are supportive of PAA’s positive intermediate-to-long term view. However, we continue to anticipate a challenging midstream environment over the near term and we have incorporated those expectations into our forward guidance.”

 

Armstrong noted that in response to the industry downturn that began approximately two years ago, PAA had taken a number of actions to mitigate the adverse impacts and position PAA to manage through challenging market conditions.  Such actions include:

 

§                  Reducing capital commitments through scope changes and project deferrals;

 

§                  Selling non-core assets and entering into strategic joint ventures which collectively raised approximately $550 million, reduced PAA’s capital commitments by approximately $600 million and secured complementary partners/shippers;

 

§                  Securing $1.6 billion of non-conventional financing;

 

§                  Intensifying efforts to capture incremental gathering and transportation barrels;  and

 

§                  Lowering its incremental cost of equity capital by executing an agreement to eliminate PAA’s incentive distribution rights and, in connection therewith, resetting PAA’s annualized distribution from $2.80 to $2.20 per common unit, which resulted in a $320 million annual reduction in cash distributions.

 

Armstrong continued “As a result of these actions, we believe PAA is positioned to manage through the balance of the down-cycle, benefit significantly during a recovery as U.S. & Canadian oil production increases and capitalize on attractive opportunities.”

 

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

 



 

Page 3

 

The following table summarizes selected PAA financial information by segment for the third quarter and first nine months of 2016:

 

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

(in millions)

 

 

 

Three Months Ended

 

Three Months Ended

 

 

 

September 30, 2016

 

 

September 30, 2015

 

 

 

Transportation

 

Facilities

 

Supply and
Logistics

 

 

Transportation

 

Facilities

 

Supply and
Logistics

 

Reported segment profit/(loss)

 

$

261

 

$

173

 

$

(6

)

 

$

254

 

$

146

 

$

87

 

Selected items impacting comparability of segment profit (2)

 

34

 

(2

)

(11

)

 

(1

)

2

 

8

 

Adjusted segment profit/(loss)

 

$

295

 

$

171

 

$

(17

)

 

$

253

 

$

148

 

$

95

 

Percentage change in reported segment profit/(loss) versus 2015 period

 

3

%

18

%

(107

)%

 

 

 

 

 

 

 

Percentage change in adjusted segment profit/(loss) versus 2015 period

 

17

%

16

%

(118

)%

 

 

 

 

 

 

 

 

 

 

Nine Months Ended

 

Nine Months Ended

 

 

 

September 30, 2016

 

 

September 30, 2015

 

 

 

Transportation

 

Facilities

 

Supply and
Logistics

 

 

Transportation

 

Facilities

 

Supply and
Logistics

 

Reported segment profit

 

$

760

 

$

488

 

$

13

 

 

$

681

 

$

432

 

$

258

 

Selected items impacting comparability of segment profit (2)

 

65

 

9

 

195

 

 

74

 

7

 

152

 

Adjusted segment profit

 

$

825

 

$

497

 

$

208

 

 

$

755

 

$

439

 

$

410

 

Percentage change in reported segment profit versus 2015 period

 

12

%

13

%

(95

)%

 

 

 

 

 

 

 

Percentage change in adjusted segment profit versus 2015 period

 

9

%

13

%

(49

)%

 

 

 

 

 

 

 

 


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

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

 

Plains GP Holdings

 

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

 

 

 

Q3 2016

 

Q2 2016

 

Q3 2015

 

Distribution per Class A share declared for the period

 

$

0.2065

 

$

0.231

 

$

0.231

 

Q3 2016 distribution percentage change from prior periods

 

 

 

(10.6

)%

(10.6

)%

 

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

 



 

Page 4

 

Conference Call

 

PAA and PAGP will hold a conference call on November 3, 2016 (see details below).  Prior to this conference call, PAA will furnish a current report on Form 8-K, which will include material in this news release as well as PAA’s financial and operational guidance for the fourth quarter and full year of 2016.  A copy of the Form 8-K will be available at www.plainsallamerican.com, where PAA and PAGP routinely post important information.

 

The PAA and PAGP conference call will be held at 11:00 a.m. ET on Thursday, November 3, 2016 to discuss the following items:

 

1.              PAA’s third-quarter 2016 performance;

2.              Financial and operating guidance for the fourth quarter and full year of 2016;

3.              Capitalization and liquidity;

4.              2017 Preliminary Guidance; and

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

 

Conference Call Webcast Instructions

 

To access the internet webcast of the conference call, please go to www.plainsallamerican.com, under the “Investor Relations” section of the website (Navigate to: Investor Relations / either “PAA” or “PAGP” / News & Events / Quarterly Earnings).  Following the live webcast, an audio replay in MP3 format will be available on the website within two hours after the end of the call and will be accessible for a period of 365 days.

 

Non-GAAP Financial Measures and Selected Items Impacting Comparability

 

To supplement our financial information presented in accordance with GAAP, management uses additional measures known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future. 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 to supplement related GAAP financial measures, (i) provide additional information about our core operating performance and ability to fund distributions to our unitholders through cash generated by our operations and (ii) provide investors with the same financial analytical framework upon which management bases financial, operational, compensation and planning/budgeting decisions. We also present these and additional non-GAAP financial measures, including adjusted net income attributable to PAA, basic and diluted adjusted net income per common unit and adjusted segment profit, as they are measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These non-GAAP measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) the mark-to-market of derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), the mark-to-market related to our Preferred Distribution Rate Reset Option, gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (iii) long-term

 

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

 



 

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inventory costing adjustments, (iv) items that are not indicative of our core operating results and business outlook and/or (v) other items that we believe should be excluded in understanding our core operating performance. These measures may further be adjusted to include amounts related to deficiencies associated with minimum volume commitments whereby we have billed the counterparties for their deficiency obligation and such amounts are recognized as deferred revenue in “Accounts payable and accrued liabilities” in our Condensed Consolidated Financial Statements. Such amounts are presented net of applicable amounts subsequently recognized into revenue. Furthermore, the calculation of these measures contemplates tax effects as a separate reconciling item, where applicable.  We have defined all such items as “Selected Items Impacting Comparability.” Due to the nature of the selected items, certain selected items impacting comparability may impact certain non-GAAP financial measures, referred to as adjusted results, but not impact other non-GAAP financial measures. We consider an understanding of these selected items impacting comparability to be material to the evaluation of our operating results and prospects.

 

Our definition and calculation of certain non-GAAP financial measures may not be comparable to similarly-titled measures of other companies. Adjusted EBITDA, Implied DCF and other non-GAAP financial measures are reconciled to the most comparable measures as reported in accordance with GAAP for the periods presented in the tables attached to this release, and should be viewed in addition to, and not in lieu of, our Condensed Consolidated Financial Statements and notes thereto. In addition, we encourage you to visit our website at www.plainsallamerican.com (in particular the section under “Financial Information” entitled “Non-GAAP Reconciliations” within the “Investor Relations” tab), which presents a reconciliation of EBITDA as well as certain other commonly used non-GAAP and supplemental financial measures.

 

Forward Looking Statements

 

Except for the historical information contained herein, the matters discussed in this release consist of forward-looking statements that involve certain risks and uncertainties that could cause actual results or outcomes to differ materially from results or outcomes anticipated in the forward-looking statements. These risks and uncertainties include, among other things, 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 assets, 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; the effects of competition; failure to implement or capitalize, or delays in implementing or capitalizing, on expansion 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; 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; maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties; 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; inability to recognize current revenue attributable to deficiency payments received from customers who fail to ship or move more than minimum contracted volumes until the related credits expire or are used; non-utilization of our assets

 

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

 



 

Page 6

 

and facilities; increased costs, or lack of availability, of insurance; 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 our historical operations; the effectiveness of our risk management activities; shortages or cost increases of supplies, materials or labor; the impact of current and future laws, rulings, governmental regulations, accounting standards and statements, and related interpretations; 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 assets, including our ability to satisfy our contractual obligations to our customers; factors affecting demand for natural gas and natural gas storage services and rates; general economic, market or business conditions and the amplification of other risks caused by volatile financial markets, capital constraints and pervasive liquidity concerns; and other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil and refined products, as well as in the storage of natural gas and the processing, transportation, fractionation, storage and marketing of natural gas liquids as discussed in the Partnerships’ filings with the Securities and Exchange Commission.

 

Plains All American Pipeline, L.P. is a publicly traded master limited partnership that owns and operates midstream energy infrastructure and provides logistics services for crude oil, natural gas liquids (“NGL”), natural gas and refined products. PAA owns an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. On average, PAA handles over 4.6 million barrels per day of crude oil and NGL in its Transportation segment. PAA is headquartered in Houston, Texas.

 

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

 

– more –

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

 



 

Page 7

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (1)

(in millions, except per unit data)

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2016

 

2015

 

2016

 

2015

 

 

 

 

 

 

 

 

 

 

 

REVENUES

 

$

5,170

 

$

5,551

 

$

14,231

 

$

18,156

 

 

 

 

 

 

 

 

 

 

 

COSTS AND EXPENSES

 

 

 

 

 

 

 

 

 

Purchases and related costs

 

4,429

 

4,701

 

12,000

 

15,591

 

Field operating costs

 

289

 

348

 

893

 

1,111

 

General and administrative expenses

 

70

 

60

 

210

 

217

 

Depreciation and amortization (2)

 

33

 

107

 

351

 

319

 

Total costs and expenses

 

4,821

 

5,216

 

13,454

 

17,238

 

 

 

 

 

 

 

 

 

 

 

OPERATING INCOME

 

349

 

335

 

777

 

918

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME/(EXPENSE)

 

 

 

 

 

 

 

 

 

Equity earnings in unconsolidated entities

 

46

 

45

 

133

 

134

 

Interest expense, net

 

(113

)

(109

)

(339

)

(320

)

Other income/(expense), net

 

17

 

(4

)

46

 

(7

)

 

 

 

 

 

 

 

 

 

 

INCOME BEFORE TAX

 

299

 

267

 

617

 

725

 

Current income tax expense

 

(4

)

(11

)

(45

)

(72

)

Deferred income tax benefit/(expense)

 

3

 

(6

)

30

 

6

 

 

 

 

 

 

 

 

 

 

 

NET INCOME

 

298

 

250

 

602

 

659

 

Net income attributable to noncontrolling interests

 

(1

)

(1

)

(3

)

(2

)

NET INCOME ATTRIBUTABLE TO PAA

 

$

297

 

$

249

 

$

599

 

$

657

 

 

 

 

 

 

 

 

 

 

 

NET INCOME PER COMMON UNIT:

 

 

 

 

 

 

 

 

 

Net income allocated to common unitholders — Basic

 

$

162

 

$

98

 

$

110

 

$

211

 

Basic weighted average common units outstanding

 

401

 

398

 

399

 

393

 

Basic net income per common unit

 

$

0.40

 

$

0.25

 

$

0.27

 

$

0.54

 

 

 

 

 

 

 

 

 

 

 

Net income allocated to common unitholders — Diluted

 

$

162

 

$

98

 

$

110

 

$

211

 

Diluted weighted average common units outstanding

 

402

 

399

 

400

 

395

 

Diluted net income per common unit

 

$

0.40

 

$

0.24

 

$

0.27

 

$

0.53

 

 


(1)             The 2015 periods have been retroactively adjusted to reflect the reclassification of the amortization of debt issuance costs from “Depreciation and amortization” to “Interest expense, net” as a result of our adoption of revised debt issuance costs guidance issued by the FASB.

(2)             Includes gains and losses on asset dispositions and asset impairments.

 

ADJUSTED RESULTS

(in millions, except per unit data)

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2016

 

2015

 

2016

 

2015

 

 

 

 

 

 

 

 

 

 

 

Adjusted net income attributable to PAA

 

$

293

 

$

262

 

$

783

 

$

887

 

 

 

 

 

 

 

 

 

 

 

Diluted adjusted net income per common unit

 

$

0.39

 

$

0.28

 

$

0.72

 

$

1.11

 

 

 

 

 

 

 

 

 

 

 

Adjusted EBITDA

 

$

450

 

$

497

 

$

1,531

 

$

1,605

 

 

– more –

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

 



 

Page 8

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 

CONDENSED CONSOLIDATED BALANCE SHEET DATA

(in millions)

 

 

 

September 30,

 

December 31,

 

 

 

2016

 

2015

 

ASSETS

 

 

 

 

 

Current assets

 

$

3,773

 

$

2,969

 

Property and equipment, net

 

13,811

 

13,474

 

Goodwill

 

2,353

 

2,405

 

Investments in unconsolidated entities

 

2,216

 

2,027

 

Linefill and base gas

 

899

 

898

 

Long-term inventory

 

146

 

129

 

Other long-term assets, net

 

309

 

386

 

Total assets

 

$

23,507

 

$

22,288

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

 

 

 

 

 

Current liabilities

 

$

4,077

 

$

3,407

 

Senior notes, net of unamortized discounts and debt issuance costs

 

9,130

 

9,698

 

Other long-term debt

 

504

 

677

 

Other long-term liabilities and deferred credits

 

722

 

567

 

Total liabilities

 

14,433

 

14,349

 

 

 

 

 

 

 

Partners’ capital excluding noncontrolling interests

 

9,016

 

7,881

 

Noncontrolling interests

 

58

 

58

 

Total partners’ capital

 

9,074

 

7,939

 

Total liabilities and partners’ capital

 

$

23,507

 

$

22,288

 

 

DEBT CAPITALIZATION RATIOS

(in millions)

 

 

 

September 30,

 

December 31,

 

 

 

2016

 

2015

 

Short-term debt

 

$

1,384

 

$

999

 

Long-term debt

 

9,634

 

10,375

 

Total debt

 

$

11,018

 

$

11,374

 

 

 

 

 

 

 

Long-term debt

 

$

9,634

 

$

10,375

 

Partners’ capital

 

9,074

 

7,939

 

Total book capitalization

 

$

18,708

 

$

18,314

 

Total book capitalization, including short-term debt

 

$

20,092

 

$

19,313

 

 

 

 

 

 

 

Long-term debt-to-total book capitalization

 

51

%

57

%

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

 

55

%

59

%

 

– more –

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Page 9

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 

OPERATING DATA (1)

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2016

 

2015

 

2016

 

2015

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

Volumes from tariff activities

 

 

 

 

 

 

 

 

 

Crude oil pipelines (by region):

 

 

 

 

 

 

 

 

 

Permian Basin (2)

 

2,162

 

1,885

 

2,129

 

1,810

 

South Texas / Eagle Ford (2)

 

263

 

321

 

283

 

298

 

Western

 

194

 

196

 

193

 

223

 

Rocky Mountain (2)

 

475

 

447

 

448

 

442

 

Gulf Coast

 

423

 

576

 

538

 

531

 

Central (2)

 

403

 

424

 

393

 

430

 

Canada

 

379

 

384

 

384

 

397

 

Crude oil pipelines

 

4,299

 

4,233

 

4,368

 

4,131

 

NGL pipelines

 

185

 

200

 

182

 

195

 

Total volumes from tariff activities

 

4,484

 

4,433

 

4,550

 

4,326

 

Trucking

 

118

 

112

 

113

 

114

 

Transportation segment total volumes

 

4,602

 

4,545

 

4,663

 

4,440

 

 

 

 

 

 

 

 

 

 

 

Facilities segment (average monthly volumes):

 

 

 

 

 

 

 

 

 

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

 

109

 

100

 

106

 

99

 

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

 

73

 

231

 

97

 

223

 

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)

 

119

 

98

 

113

 

101

 

Facilities segment total volumes (average monthly volumes in millions of barrels) (3)

 

131

 

126

 

129

 

126

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

Crude oil lease gathering purchases

 

883

 

927

 

894

 

958

 

NGL sales

 

207

 

183

 

230

 

209

 

Waterborne cargos

 

8

 

4

 

7

 

1

 

Supply and Logistics segment total volumes

 

1,098

 

1,114

 

1,131

 

1,168

 

 


(1)             Average volumes are calculated as total volumes for the period (attributable to our interest) divided by the number of days or months in the period.

(2)             Region includes volumes (attributable to our interest) from pipelines owned by unconsolidated entities.

(3)             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 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.

 

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Page 10

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 

COMPUTATION OF BASIC AND DILUTED NET INCOME PER COMMON UNIT

(in millions, except per unit data)

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2016

 

2015

 

2016

 

2015

 

Basic Net Income per Common Unit

 

 

 

 

 

 

 

 

 

Net income attributable to PAA

 

$

297

 

$

249

 

$

599

 

$

657

 

Distributions to Series A preferred units (1)

 

(33

)

 

(88

)

 

Distributions to general partner (1)

 

(102

)

(154

)

(412

)

(454

)

Distributions to participating securities (1)

 

(1

)

(1

)

(3

)

(4

)

Undistributed loss allocated to general partner (1)

 

1

 

4

 

14

 

12

 

Net income allocated to common unitholders in accordance with application of the two-class method for MLPs

 

$

162

 

$

98

 

$

110

 

$

211

 

 

 

 

 

 

 

 

 

 

 

Basic weighted average common units outstanding

 

401

 

398

 

399

 

393

 

 

 

 

 

 

 

 

 

 

 

Basic net income per common unit

 

$

0.40

 

$

0.25

 

$

0.27

 

$

0.54

 

 

 

 

 

 

 

 

 

 

 

Diluted Net Income per Common Unit

 

 

 

 

 

 

 

 

 

Net income attributable to PAA

 

$

297

 

$

249

 

$

599

 

$

657

 

Distributions to Series A preferred units (1)

 

(33

)

 

(88

)

 

Distributions to general partner (1)

 

(102

)

(154

)

(412

)

(454

)

Distributions to participating securities (1)

 

(1

)

(1

)

(3

)

(4

)

Undistributed loss allocated to general partner (1)

 

1

 

4

 

14

 

12

 

Net income allocated to common unitholders in accordance with application of the two-class method for MLPs

 

$

162

 

$

98

 

$

110

 

$

211

 

 

 

 

 

 

 

 

 

 

 

Basic weighted average common units outstanding

 

401

 

398

 

399

 

393

 

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

 

1

 

1

 

1

 

2

 

Diluted weighted average common units outstanding

 

402

 

399

 

400

 

395

 

 

 

 

 

 

 

 

 

 

 

Diluted net income per common unit (3)

 

$

0.40

 

$

0.24

 

$

0.27

 

$

0.53

 

 


(1)             Net income allocated to common unitholders is calculated based on the distributions pertaining to the current period’s net income.  After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner, common unitholders and participating securities in accordance with the contractual terms of our partnership agreement and as further prescribed under the two-class method.

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

(3)             The possible conversion of our Series A preferred units was excluded from the calculation of diluted net income per common unit for the three and nine months ended September 30, 2016 as the effect was antidilutive.

 

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Page 11

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 

SELECTED ITEMS IMPACTING COMPARABILITY

(in millions, except per unit data)

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2016

 

2015

 

2016

 

2015

 

Selected Items Impacting Comparability (1):

 

 

 

 

 

 

 

 

 

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

 

$

69

 

$

39

 

$

(147

)

$

(112

)

Long-term inventory costing adjustments (3)

 

(38

)

(47

)

6

 

(62

)

Deficiencies under minimum volume commitments, net (4)

 

(25

)

 

(59

)

 

Equity-indexed compensation expense (5)

 

(8

)

 

(23

)

(22

)

Net gain/(loss) on foreign currency revaluation (6)

 

(3

)

(6

)

(1

)

20

 

Line 901 incident (7)

 

 

 

 

(65

)

Selected items impacting comparability of EBITDA

 

$

(5

)

$

(14

)

$

(224

)

$

(241

)

Deferred income tax expense (8)

 

 

 

 

(22

)

Tax effect on selected items impacting comparability

 

9

 

1

 

40

 

33

 

Selected items impacting comparability of net income attributable to PAA

 

$

4

 

$

(13

)

$

(184

)

$

(230

)

 

 

 

 

 

 

 

 

 

 

Impact to basic net income per common unit

 

$

0.01

 

$

(0.03

)

$

(0.46

)

$

(0.57

)

Impact to diluted net income per common unit

 

$

0.01

 

$

(0.04

)

$

(0.45

)

$

(0.58

)

 


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

(2)             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 results. In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill. We also exclude the impact of corresponding inventory valuation adjustments, as applicable, as well as the mark-to-market adjustment related to our Preferred Distribution Rate Reset Option.

(3)             We carry approximately 5 million barrels of crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is 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. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We treat the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and writedowns of such inventory that result from price declines as a selected item impacting comparability.

(4)             We have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on our capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. We believe the inclusion of the contractually committed revenues associated with that period is meaningful to investors as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results.

(5)             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 net income 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 net income 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.

(6)             During the periods presented, there were fluctuations in the value of CAD to USD, resulting in gains and losses that were not related to our core operating results for the period and were thus classified as a selected item impacting comparability.

(7)              Includes costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance.

(8)             Includes the initial cumulative effect of a change in Canadian tax legislation impacting the period.

 

– more –

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

 



 

Page 12

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 

SELECTED FINANCIAL DATA BY SEGMENT

(in millions)

 

 

 

Three Months Ended

 

Three Months Ended

 

 

 

September 30, 2016

 

September 30, 2015

 

 

 

 

 

 

 

Supply and

 

 

 

 

 

Supply and

 

 

 

Transportation

 

Facilities

 

Logistics

 

Transportation

 

Facilities

 

Logistics

 

Revenues (1)

 

$

401

 

$

282

 

$

4,879

 

 

$

401

 

$

263

 

$

5,254

 

Purchases and related costs (1)

 

(24

)

(6

)

(4,788

)

 

(26

)

(7

)

(5,032

)

Field operating costs (1) (2)

 

(133

)

(85

)

(70

)

 

(147

)

(96

)

(110

)

Equity-indexed compensation expense - operations

 

(3

)

(1

)

 

 

1

 

1

 

 

Segment general and administrative expenses (2) (3)

 

(22

)

(15

)

(23

)

 

(23

)

(17

)

(26

)

Equity-indexed compensation expense - general and administrative

 

(4

)

(2

)

(4

)

 

3

 

2

 

1

 

Equity earnings in unconsolidated entities

 

46

 

 

 

 

45

 

 

 

Reported segment profit/(loss)

 

$

261

 

$

173

 

$

(6

)

 

$

254

 

$

146

 

$

87

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Selected items impacting comparability of segment profit:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

$

 

$

1

 

$

(53

)

 

$

 

$

2

 

$

(41

)

Long-term inventory costing adjustments

 

 

 

38

 

 

 

 

47

 

Deficiencies under minimum volume commitments, net

 

30

 

(5

)

 

 

 

 

 

Equity-indexed compensation expense/(benefit)

 

4

 

2

 

2

 

 

(1

)

 

1

 

Net loss on foreign currency revaluation

 

 

 

2

 

 

 

 

1

 

Line 901 incident

 

 

 

 

 

 

 

 

Selected items impacting comparability of segment profit (4)

 

$

34

 

$

(2

)

$

(11

)

 

$

(1

)

$

2

 

$

8

 

Adjusted segment profit/(loss)

 

$

295

 

$

171

 

$

(17

)

 

$

253

 

$

148

 

$

95

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Maintenance capital

 

$

29

 

$

15

 

$

3

 

 

$

34

 

$

16

 

$

2

 

 

 

 

Nine Months Ended

 

Nine Months Ended

 

 

 

September 30, 2016

 

September 30, 2015

 

 

 

 

 

 

 

Supply and

 

 

 

 

 

Supply and

 

 

 

Transportation

 

Facilities

 

Logistics

 

Transportation

 

Facilities

 

Logistics

 

Revenues (1)

 

$

1,188

 

$

817

 

$

13,353

 

 

$

1,203

 

$

789

 

$

17,238

 

Purchases and related costs (1)

 

(69

)

(17

)

(13,031

)

 

(85

)

(17

)

(16,553

)

Field operating costs (1) (2)

 

(406

)

(258

)

(226

)

 

(493

)

(284

)

(338

)

Equity-indexed compensation expense - operations

 

(9

)

(3

)

(1

)

 

(5

)

(1

)

 

Segment general and administrative expenses (2) (3)

 

(67

)

(44

)

(72

)

 

(67

)

(50

)

(79

)

Equity-indexed compensation expense - general and administrative

 

(10

)

(7

)

(10

)

 

(6

)

(5

)

(10

)

Equity earnings in unconsolidated entities

 

133

 

 

 

 

134

 

 

 

Reported segment profit

 

$

760

 

$

488

 

$

13

 

 

$

681

 

$

432

 

$

258

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Selected items impacting comparability of segment profit:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Losses from derivative activities net of inventory valuation adjustments

 

$

 

$

 

$

189

 

 

$

 

$

2

 

$

110

 

Long-term inventory costing adjustments

 

 

 

(6

)

 

 

 

62

 

Deficiencies under minimum volume commitments, net

 

54

 

5

 

 

 

 

 

 

Equity-indexed compensation expense

 

11

 

5

 

7

 

 

9

 

5

 

8

 

Net (gain)/loss on foreign currency revaluation

 

 

(1

)

5

 

 

 

 

(28

)

Line 901 incident

 

 

 

 

 

65

 

 

 

Selected items impacting comparability of segment profit (4)

 

$

65

 

$

9

 

$

195

 

 

$

74

 

$

7

 

$

152

 

Adjusted segment profit

 

$

825

 

$

497

 

$

208

 

 

$

755

 

$

439

 

$

410

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Maintenance capital

 

$

86

 

$

32

 

$

10

 

 

$

101

 

$

48

 

$

5

 

 


(1)             Includes intersegment amounts.

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

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

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

 

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Page 13

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 

FINANCIAL DATA RECONCILIATIONS

(in millions)

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2016

 

2015

 

2016

 

2015

 

Net Income to Earnings Before Interest, Taxes, Depreciation and Amortization (“EBITDA”), Excluding Selected Items Impacting Comparability (“Adjusted EBITDA”) and Implied Distributable Cash Flow (“DCF”) Reconciliations

 

 

 

 

 

 

 

 

 

Net Income

 

$

298

 

$

250

 

$

602

 

$

659

 

Interest expense, net

 

113

 

109

 

339

 

320

 

Income tax expense

 

1

 

17

 

15

 

66

 

Depreciation and amortization

 

33

 

107

 

351

 

319

 

EBITDA

 

$

445

 

$

483

 

$

1,307

 

$

1,364

 

Selected items impacting comparability of EBITDA (1)

 

5

 

14

 

224

 

241

 

Adjusted EBITDA

 

$

450

 

$

497

 

$

1,531

 

$

1,605

 

Interest expense, net (2)

 

(109

)

(105

)

(327

)

(309

)

Maintenance capital

 

(47

)

(52

)

(128

)

(154

)

Current income tax expense

 

(4

)

(11

)

(45

)

(72

)

Equity earnings in unconsolidated entities, net of distributions

 

4

 

12

 

18

 

25

 

Distributions to noncontrolling interests (3)

 

(1

)

(1

)

(3

)

(3

)

Implied DCF (4)

 

$

293

 

$

340

 

$

1,046

 

$

1,092

 

 


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

(2)             Excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps.

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

(4)             Including costs recognized during the period related to the Line 901 incident that occurred during May 2015, Implied DCF would have been $1,027 million for the nine months ended September 30, 2015.

 

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Page 14

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 

COMPUTATION OF ADJUSTED BASIC AND DILUTED NET INCOME PER COMMON UNIT

(in millions, except per unit data)

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2016

 

2015

 

2016

 

2015

 

Basic Adjusted Net Income per Common Unit

 

 

 

 

 

 

 

 

 

Net income attributable to PAA

 

$

297

 

$

249

 

$

599

 

$

657

 

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

 

(4

)

13

 

184

 

230

 

Adjusted net income attributable to PAA

 

293

 

262

 

783

 

887

 

Distributions to Series A preferred units (2)

 

(33

)

 

(88

)

 

Distributions to general partner (2)

 

(102

)

(154

)

(412

)

(454

)

Distributions to participating securities (2)

 

(1

)

(1

)

(3

)

(4

)

Undistributed loss allocated to general partner (2)

 

1

 

3

 

10

 

8

 

Adjusted net income allocated to common unitholders in accordance with application of the two-class method for MLPs

 

$

158

 

$

110

 

$

290

 

$

437

 

 

 

 

 

 

 

 

 

 

 

Basic weighted average common units outstanding

 

401

 

398

 

399

 

393

 

 

 

 

 

 

 

 

 

 

 

Basic adjusted net income per common unit

 

$

0.39

 

$

0.28

 

$

0.73

 

$

1.11

 

 

 

 

 

 

 

 

 

 

 

Diluted Adjusted Net Income per Common Unit

 

 

 

 

 

 

 

 

 

Net income attributable to PAA

 

$

297

 

$

249

 

$

599

 

$

657

 

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

 

(4

)

13

 

184

 

230

 

Adjusted net income attributable to PAA

 

293

 

262

 

783

 

887

 

Distributions to Series A preferred units (2)

 

(33

)

 

(88

)

 

Distributions to general partner (2)

 

(102

)

(154

)

(412

)

(454

)

Distributions to participating securities (2)

 

(1

)

(1

)

(3

)

(4

)

Undistributed loss allocated to general partner (2)

 

1

 

3

 

10

 

8

 

Adjusted net income allocated to common unitholders in accordance with application of the two-class method for MLPs

 

$

158

 

$

110

 

$

290

 

$

437

 

 

 

 

 

 

 

 

 

 

 

Basic weighted average common units outstanding

 

401

 

398

 

399

 

393

 

Effect of dilutive securities: Weighted average LTIP units (3)

 

1

 

1

 

1

 

2

 

Diluted weighted average common units outstanding

 

402

 

399

 

400

 

395

 

 

 

 

 

 

 

 

 

 

 

Diluted adjusted net income per common unit (4)

 

$

0.39

 

$

0.28

 

$

0.72

 

$

1.11

 

 


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

(2)             Adjusted net income allocated to common unitholders is calculated based on the distributions pertaining to the current period’s net income. After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner, common unitholders and participating securities in accordance with the contractual terms of our partnership agreement and as further prescribed under the two-class method.

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

(4)             The possible conversion of our Series A preferred units was excluded from the calculation of diluted adjusted net income per common unit for the three and nine months ended September 30, 2016 as the effect was antidilutive.

 

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Page 15

 

PLAINS GP HOLDINGS AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (1)

(in millions, except per share data)

 

 

 

 

Three Months Ended

 

 

Three Months Ended

 

 

 

September 30, 2016

 

 

September 30, 2015

 

 

 

PAA

 

Consolidating
Adjustments 
(2)

 

PAGP

 

 

PAA

 

Consolidating
Adjustments 
(2)

 

PAGP

 

REVENUES

 

$

5,170

 

$

 

$

5,170

 

 

$

5,551

 

$

 

$

5,551

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

COSTS AND EXPENSES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchases and related costs

 

4,429

 

 

4,429

 

 

4,701

 

 

4,701

 

Field operating costs

 

289

 

 

289

 

 

348

 

 

348

 

General and administrative expenses

 

70

 

1

 

71

 

 

60

 

 

60

 

Depreciation and amortization

 

33

 

 

33

 

 

107

 

1

 

108

 

Total costs and expenses

 

4,821

 

1

 

4,822

 

 

5,216

 

1

 

5,217

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

OPERATING INCOME

 

349

 

(1

)

348

 

 

335

 

(1

)

334

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME/(EXPENSE)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity earnings in unconsolidated entities

 

46

 

 

46

 

 

45

 

 

45

 

Interest expense, net

 

(113

)

(3

)

(116

)

 

(109

)

(3

)

(112

)

Other income/(expense), net

 

17

 

 

17

 

 

(4

)

 

(4

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

INCOME BEFORE TAX

 

299

 

(4

)

295

 

 

267

 

(4

)

263

 

Current income tax expense

 

(4

)

 

(4

)

 

(11

)

 

(11

)

Deferred income tax benefit/(expense)

 

3

 

(15

)

(12

)

 

(6

)

(18

)

(24

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NET INCOME

 

298

 

(19

)

279

 

 

250

 

(22

)

228

 

Net income attributable to noncontrolling interests

 

(1

)

(254

)

(255

)

 

(1

)

(195

)

(196

)

NET INCOME ATTRIBUTABLE TO PAGP

 

$

297

 

$

(273

)

$

24

 

 

$

249

 

$

(217

)

$

32

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BASIC NET INCOME PER CLASS A SHARE

 

 

 

 

 

$

0.09

 

 

 

 

 

 

$

0.14

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DILUTED NET INCOME PER CLASS A SHARE

 

 

 

 

 

$

0.09

 

 

 

 

 

 

$

0.14

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BASIC WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING

 

 

 

 

 

268

 

 

 

 

 

 

225

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING

 

 

 

 

 

268

 

 

 

 

 

 

225

 

 


(1)             The 2015 period has been retroactively adjusted to reflect the reclassification of the amortization of debt issuance costs from “Depreciation and amortization” to “Interest expense, net” as a result of our adoption of revised debt issuance costs guidance issued by the FASB.

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

 

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Page 16

 

PLAINS GP HOLDINGS AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (1)

(in millions, except per share data)

 

 

 

Nine Months Ended

 

 

Nine Months Ended

 

 

 

September 30, 2016

 

 

September 30, 2015

 

 

 

PAA

 

Consolidating
Adjustments 
(2)

 

PAGP

 

 

PAA

 

Consolidating
Adjustments 
(2)

 

PAGP

 

REVENUES

 

$

14,231

 

$

 

$

14,231

 

 

$

18,156

 

$

 

$

18,156

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

COSTS AND EXPENSES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchases and related costs

 

12,000

 

 

12,000

 

 

15,591

 

 

15,591

 

Field operating costs

 

893

 

 

893

 

 

1,111

 

 

1,111

 

General and administrative expenses

 

210

 

2

 

212

 

 

217

 

2

 

219

 

Depreciation and amortization

 

351

 

1

 

352

 

 

319

 

1

 

320

 

Total costs and expenses

 

13,454

 

3

 

13,457

 

 

17,238

 

3

 

17,241

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

OPERATING INCOME

 

777

 

(3

)

774

 

 

918

 

(3

)

915

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME/(EXPENSE)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity earnings in unconsolidated entities

 

133

 

 

133

 

 

134

 

 

134

 

Interest expense, net

 

(339

)

(10

)

(349

)

 

(320

)

(9

)

(329

)

Other income/(expense), net

 

46

 

 

46

 

 

(7

)

 

(7

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

INCOME BEFORE TAX

 

617

 

(13

)

604

 

 

725

 

(12

)

713

 

Current income tax expense

 

(45

)

 

(45

)

 

(72

)

 

(72

)

Deferred income tax benefit/(expense)

 

30

 

(51

)

(21

)

 

6

 

(54

)

(48

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NET INCOME

 

602

 

(64

)

538

 

 

659

 

(66

)

593

 

Net income attributable to noncontrolling interests

 

(3

)

(433

)

(436

)

 

(2

)

(498

)

(500

)

NET INCOME ATTRIBUTABLE TO PAGP

 

$

599

 

$

(497

)

$

102

 

 

$

657

 

$

(564

)

$

93

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BASIC NET INCOME PER CLASS A SHARE

 

 

 

 

 

$

0.39

 

 

 

 

 

 

$

0.42

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DILUTED NET INCOME PER CLASS A SHARE

 

 

 

 

 

$

0.38

 

 

 

 

 

 

$

0.42

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BASIC WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING

 

 

 

 

 

263

 

 

 

 

 

 

220

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

DILUTED WEIGHTED AVERAGE CLASS A SHARES OUTSTANDING

 

 

 

 

 

629

 

 

 

 

 

 

220

 

 


(1)             The 2015 period has been retroactively adjusted to reflect the reclassification of the amortization of debt issuance costs from “Depreciation and amortization” to “Interest expense, net” as a result of our adoption of revised debt issuance costs guidance issued by the FASB.

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

 

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Page 17

 

PLAINS GP HOLDINGS AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 

CONDENSED CONSOLIDATING BALANCE SHEET DATA

(in millions)

 

 

 

September 30, 2016

 

December 31, 2015

 

 

 

 

 

Consolidating

 

 

 

 

 

 

Consolidating

 

 

 

 

 

PAA

 

Adjustments (1)

 

PAGP

 

 

PAA

 

Adjustments (1)

 

PAGP

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current assets

 

$

3,773

 

$

3

 

$

3,776

 

 

$

2,969

 

$

3

 

$

2,972

 

Property and equipment, net

 

13,811

 

18

 

13,829

 

 

13,474

 

19

 

13,493

 

Goodwill

 

2,353

 

 

2,353

 

 

2,405

 

 

2,405

 

Investments in unconsolidated entities

 

2,216

 

 

2,216

 

 

2,027

 

 

2,027

 

Deferred tax asset

 

 

1,886

 

1,886

 

 

 

1,835

 

1,835

 

Linefill and base gas

 

899

 

 

899

 

 

898

 

 

898

 

Long-term inventory

 

146

 

 

146

 

 

129

 

 

129

 

Other long-term assets, net

 

309

 

(3

)

306

 

 

386

 

(3

)

383

 

Total assets

 

$

23,507

 

$

1,904

 

$

25,411

 

 

$

22,288

 

$

1,854

 

$

24,142

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current liabilities

 

$

4,077

 

$

2

 

$

4,079

 

 

$

3,407

 

$

2

 

$

3,409

 

Senior notes, net of unamortized discounts and debt issuance costs

 

9,130

 

 

9,130

 

 

9,698

 

 

9,698

 

Other long-term debt, net of unamortized debt issuance costs

 

504

 

602

 

1,106

 

 

677

 

557

 

1,234

 

Other long-term liabilities and deferred credits

 

722

 

 

722

 

 

567

 

 

567

 

Total liabilities

 

14,433

 

604

 

15,037

 

 

14,349

 

559

 

14,908

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partners’ capital excluding noncontrolling interests

 

9,016

 

(7,248

)

1,768

 

 

7,881

 

(6,119

)

1,762

 

Noncontrolling interests

 

58

 

8,548

 

8,606

 

 

58

 

7,414

 

7,472

 

Total partners’ capital

 

9,074

 

1,300

 

10,374

 

 

7,939

 

1,295

 

9,234

 

Total liabilities and partners’ capital

 

$

23,507

 

$

1,904

 

$

25,411

 

 

$

22,288

 

$

1,854

 

$

24,142

 

 


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

 

– more –

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

 



 

Page 18

 

PLAINS GP HOLDINGS AND SUBSIDIARIES

DISTRIBUTION SUMMARY (unaudited)

 

Q3 2016 PAGP DISTRIBUTION SUMMARY

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

 

 

 

Q3 2016 (1)

 

PAA Distribution/Common Unit

 

$

0.5500

 

GP Distribution/Common Unit

 

$

0.2450

 

Total Distribution/Common Unit

 

$

0.7950

 

 

 

 

 

PAA Common Units Outstanding at 10/31/16

 

413

 

 

 

 

 

Gross GP Distribution

 

$

104

 

Less: IDR Reduction

 

(3

)

Net Distribution from PAA to AAP (2)

 

$

101

 

Plus: Borrowings to Fund True-up Distribution (3)

 

33

 

Cash Available for Distribution by AAP

 

$

134

 

 

 

 

 

Distributions to AAP Partners

 

 

 

Direct AAP Owners & AAP Management (59% economic interest)

 

$

79

 

PAGP (41% economic interest)

 

55

 

Total distributions to AAP Partners

 

$

134

 

 

 

 

 

Distribution to PAGP Investors

 

$

55

 

PAGP Class A Shares Outstanding at 10/31/16

 

268

 

PAGP Distribution/Class A Share

 

$

0.2065

 

 


(1)             Amounts may not recalculate due to rounding.

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

(3)             AAP has agreed to borrow funds under its credit agreement as necessary to make a special ‘‘true-up’’ distribution to its partners that, when added to the distributions to be paid to AAP in respect of the 2% general partner interest in PAA and the IDRs, equals the total distribution AAP’s partners would have received if the closing of the Simplification Transactions had occurred immediately prior to the record date for the third quarter distribution.

 

– more –

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

 



 

Page 19

 

PLAINS GP HOLDINGS AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

 

COMPUTATION OF BASIC AND DILUTED NET INCOME PER CLASS A SHARE

(in millions, except per share data)

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2016

 

2015

 

2016

 

2015

 

Basic Net Income per Class A Share

 

 

 

 

 

 

 

 

 

Net income attributable to PAGP

 

$

24

 

$

32

 

$

102

 

$

93

 

Basic weighted average Class A shares outstanding

 

268

 

225

 

263

 

220

 

 

 

 

 

 

 

 

 

 

 

Basic net income per Class A share

 

$

0.09

 

$

0.14

 

$

0.39

 

$

0.42

 

 

 

 

 

 

 

 

 

 

 

Diluted Net Income per Class A Share

 

 

 

 

 

 

 

 

 

Net income attributable to PAGP

 

$

24

 

$

32

 

$

102

 

$

93

 

Incremental net income allocated to PAGP resulting from assumed exchange of AAP units and AAP Management Units

 

 

 

138

 

 

Net income allocated to PAGP including incremental net income from assumed exchange of AAP units and AAP Management Units

 

$

24

 

$

32

 

$

240

 

$

93

 

 

 

 

 

 

 

 

 

 

 

Basic weighted average Class A shares outstanding

 

268

 

225

 

263

 

220

 

Dilutive shares resulting from assumed exchange of AAP units and AAP Management Units

 

 

 

366

 

 

Diluted weighted average Class A shares outstanding

 

268

 

225

 

629

 

220

 

 

 

 

 

 

 

 

 

 

 

Diluted net income per Class A share

 

$

0.09

 

$

0.14

 

$

0.38

 

$

0.42

 

 

Contacts:

 

Ryan Smith

Al Swanson

Director, Investor Relations

Executive Vice President, CFO

(866) 809-1291

(800) 564-3036

 

###

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

 



Additional Information and Where to Find It

 

This communication may be deemed to be solicitation material in respect of the special meeting of PAGP’s shareholders to vote on the approval of the previously-announced Simplification Agreement and the transactions contemplated thereby (the “Simplification Proposal”).  PAGP filed a definitive proxy statement with the SEC on October 7, 2016, and has mailed the definitive proxy statement to its shareholders on or about October 7, 2016.  The proxy statement contains important information about PAGP and the Simplification Proposal.   INVESTORS AND SECURITY HOLDERS OF PAGP ARE URGED TO READ THE PROXY STATEMENT, THE ACCOMPANYING PROXY CARD AND ANY OTHER DOCUMENTS THAT HAVE BEEN FILED OR WILL BE FILED WITH THE SEC IN CONNECTION WITH THE SIMPLIFICATION PROPOSAL OR INCORPORATED BY REFERENCE INTO THE PROXY STATEMENT.  Security holders may obtain free copies of the proxy statement and other documents containing important information about PAGP, once such documents are filed with the SEC, through the website maintained by the SEC at http://www.sec.gov.  Copies of the documents filed with the SEC by PAGP will be available free of charge on PAGP’s website at ir.pagp.com or by contacting PAGP’s Investor Relations Department at (866) 809-1291.