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 5, 2012

 

Plains All American Pipeline, L.P.

(Exact name of registrant as specified in its charter)

 

DELAWARE

 

1-14569

 

76-0582150

(State or other jurisdiction of
incorporation)

 

(Commission File Number)

 

(IRS Employer Identification No.)

 

333 Clay Street, Suite 1600, Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

 

Registrant’s telephone number, including area code: 713-646-4100

 

 

(Former name or former address, if changed since last report)

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

 

o            Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

o            Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

o            Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

o            Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

 



 

Item 9.01.             Financial Statements and Exhibits

 

(d)    Exhibit 99.1 — Press Release dated November 5, 2012

 

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

 

Plains All American Pipeline, L.P. (the “Partnership”) today issued a press release reporting its third-quarter 2012 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 providing updated fourth quarter and full year 2012 detailed guidance for financial performance and we are providing preliminary guidance for calendar year 2013 .  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 Fourth Quarter 2012 Guidance and Full Year 2013 Preliminary Guidance

 

To supplement our financial information presented in accordance with GAAP, management uses additional measures known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future.  Management believes that the presentation of such additional financial measures provides useful information to investors regarding our financial condition and results of operations because these measures, when used in conjunction with related GAAP financial measures, (i) provide additional information about our core operations and ability to generate and distribute cash flow, (ii) provide investors with the financial analytical framework upon which management bases financial, operational, compensation and planning decisions and (iii) present measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations.  EBIT and EBITDA (each as defined below in Note 1 to the “Operating and Financial Guidance” table) are non-GAAP financial measures. Net income represents one of the two most directly comparable GAAP measures to EBIT and EBITDA. In Note 10 below, we reconcile net income to EBIT and EBITDA for the 2012 guidance periods presented. Cash flow from operating activities is the other most comparable GAAP measure. We do not, however, reconcile cash flows from operating activities to EBIT and EBITDA, because such reconciliations are impractical for a forecasted period. We encourage you to visit our website at www.paalp.com (in particular the section entitled “Non-GAAP Reconciliations”), which presents a historical reconciliation of EBIT and EBITDA as well as certain other commonly used non-GAAP financial measures. In addition, we have highlighted the impact of (i) losses from derivative activities net of inventory valuation adjustments, (ii) asset impairments, (iii) equity compensation expense, (iv) losses on foreign currency revaluation, (v) significant acquisition-related expenses and (vi) other selected items.  Due to the nature of the selected items, certain of the selected items impacting comparability may impact certain non-GAAP financial measures but not impact other non-GAAP financial measures.

 

We based our guidance for the three-month and twelve-month periods ending December 31, 2012 on assumptions and estimates that we believe are reasonable, given our assessment of historical trends (modified for changes in market conditions), business cycles and other reasonably available information. Projections covering multi-quarter periods contemplate inter-period changes in future performance resulting from new expansion projects, seasonal operational changes (such as NGL sales) and acquisition synergies. Our assumptions and future performance, however, are both subject to a wide range of business risks and uncertainties, so no assurance can be provided that actual performance will fall within the guidance ranges. Please refer to information under the caption “Forward-Looking Statements and Associated Risks” below. These risks and uncertainties, as well as other unforeseeable risks and uncertainties, could cause our actual results to differ materially from those in the following table. The operating and financial guidance provided below is given as of the date hereof, based on information known to us as of November 4, 2012. We undertake no obligation to publicly update or revise any forward-looking statements.

 

2



 

Plains All American Pipeline, L.P.

Operating and Financial Guidance

(in millions, except per unit data)

 

 

 

Actual

 

Guidance (1)

 

 

 

9 Months

 

3 Months Ending

 

12 Months Ending

 

 

 

Ended

 

December 31, 2012

 

December 31, 2012

 

 

 

9/30/2012

 

Low

 

High

 

Low

 

High

 

Segment Profit

 

 

 

 

 

 

 

 

 

 

 

Net revenues (including equity earnings from unconsolidated entities)

 

$

2,528

 

$

870

 

$

905

 

$

3,398

 

$

3,433

 

Field operating costs

 

(860

)

(307

)

(297

)

(1,167

)

(1,157

)

General and administrative expenses

 

(264

)

(80

)

(75

)

(344

)

(339

)

 

 

1,404

 

483

 

533

 

1,887

 

1,937

 

Depreciation and amortization expense

 

(356

)

(88

)

(84

)

(444

)

(440

)

Interest expense, net

 

(214

)

(78

)

(74

)

(292

)

(288

)

Income tax benefit (expense)

 

(43

)

(25

)

(21

)

(68

)

(64

)

Other income (expense), net

 

6

 

1

 

1

 

7

 

7

 

Net Income

 

797

 

293

 

355

 

1,090

 

1,152

 

Less: Net income attributable to noncontrolling interests

 

(23

)

(11

)

(11

)

(34

)

(34

)

Net Income attributable to Plains

 

$

774

 

$

282

 

$

344

 

$

1,056

 

$

1,118

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income to Limited Partners (2)

 

$

554

 

$

200

 

$

261

 

$

754

 

$

815

 

Basic Net Income Per Limited Partner Unit (2), (3)

 

 

 

 

 

 

 

 

 

 

 

Weighted Average Units Outstanding (3)

 

322

 

335

 

335

 

325

 

325

 

Net Income Per Unit

 

$

1.71

 

$

0.59

 

$

0.77

 

$

2.31

 

$

2.49

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted Net Income Per Limited Partner Unit (2), (3)

 

 

 

 

 

 

 

 

 

 

 

Weighted Average Units Outstanding (3)

 

325

 

337

 

337

 

328

 

328

 

Net Income Per Unit

 

$

1.70

 

$

0.59

 

$

0.77

 

$

2.29

 

$

2.47

 

 

 

 

 

 

 

 

 

 

 

 

 

EBIT

 

$

1,054

 

$

396

 

$

450

 

$

1,450

 

$

1,504

 

EBITDA

 

$

1,410

 

$

484

 

$

534

 

$

1,894

 

$

1,944

 

 

 

 

 

 

 

 

 

 

 

 

 

Selected Items Impacting Comparability

 

 

 

 

 

 

 

 

 

 

 

Losses from derivative activities net of inventory valuation adjustments

 

$

(18

)

$

 

$

 

$

(18

)

$

(18

)

Asset Impairments (4)

 

(125

)

 

 

(125

)

(125

)

Equity compensation expense

 

(50

)

(11

)

(11

)

(61

)

(61

)

Losses on foreign currency revaluation

 

(6

)

 

 

(6

)

(6

)

Significant acquisition-related expenses

 

(13

)

 

 

(13

)

(13

)

Other (4)

 

1

 

 

 

1

 

1

 

Selected Items Impacting Comparability of Net Income attributable to Plains

 

$

(211

)

$

(11

)

$

(11

)

$

(222

)

$

(222

)

 

 

 

 

 

 

 

 

 

 

 

 

Excluding Selected Items Impacting Comparability

 

 

 

 

 

 

 

 

 

 

 

Adjusted Segment Profit

 

 

 

 

 

 

 

 

 

 

 

Transportation

 

$

543

 

$

187

 

$

199

 

$

730

 

$

742

 

Facilities

 

362

 

129

 

137

 

491

 

499

 

Supply and Logistics

 

587

 

178

 

208

 

765

 

795

 

Other income, net

 

5

 

1

 

1

 

6

 

6

 

Adjusted EBITDA

 

$

1,497

 

$

495

 

$

545

 

$

1,992

 

$

2,042

 

Adjusted Net Income attributable to Plains

 

$

985

 

$

293

 

$

355

 

$

1,278

 

$

1,340

 

Basic Adjusted Net Income per Limited Partner Unit (2), (3)

 

$

2.35

 

$

0.63

 

$

0.81

 

$

2.97

 

$

3.15

 

Diluted Adjusted Net Income per Limited Partner Unit (2), (3)

 

$

2.33

 

$

0.62

 

$

0.80

 

$

2.95

 

$

3.13

 

 


(1)

The projected average foreign exchange rate is $1.00 Canadian to $1.00 U.S. for the three-month period ending December 31, 2012. The rate as of November 2, 2012 was $1.00 Canadian to $1.00 U.S. A $0.05 change in the FX rate will impact annual adjusted EBITDA by approximately $8 million.

(2)

We calculate net income available to limited partners based on the distributions pertaining to the current period’s net income.

 

3



 

 

After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner, limited partners and participating securities in accordance with the contractual terms of the partnership agreement and as further prescribed under the two-class method.

(3)

Unit and per-unit amounts are presented as adjusted for the two-for-one unit split effected on October 1, 2012.

(4)

Asset impairments and other do not impact adjusted EBITDA. As a component of depreciation and amortization expense, asset impairments are not included in EBITDA and thus do not impact adjusted EBITDA.

 

Notes and Significant Assumptions:

 

1. Definitions.

 

EBIT

Earnings before interest and taxes

EBITDA

Earnings before interest, taxes and depreciation and amortization expense

Segment Profit

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

FASB

Financial Accounting Standards Board

Bbls/d

Barrels per day

Bcf

Billion cubic feet

LTIP

Long-Term Incentive Plan

NGL

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

FX

Foreign currency exchange

General partner (GP)

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

 

2.              Operating Segments. We manage our operations through three operating segments: (i) Transportation, (ii) Facilities and (iii) 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, NGL and refined products on pipelines, gathering systems, trucks and barges. We generate revenue through a combination of tariffs, third-party leases of pipeline capacity and transportation fees. Our transportation segment also includes our equity earnings from our investments in the Butte, Frontier and White Cliffs pipeline systems and Settoon Towing, in which we own non-controlling interests.

 

Pipeline volume estimates are based on historical trends, anticipated future operating performance and assumed completion of internal growth projects. Actual volumes will be influenced by maintenance schedules at refineries, production trends, weather and other natural occurrences including hurricanes, changes in the quantity of inventory held in tanks, and other external factors beyond our control. We forecast adjusted segment profit using the volume assumptions in the table below, priced at forecasted tariff rates, less estimated field operating costs and G&A expenses. Field operating costs do not include depreciation. Actual segment profit could vary materially depending on the level and mix of volumes transported or expenses incurred during the period.

 

The following table summarizes our total transportation volumes and highlights major systems that are significant either in total volumes transported or in contribution to total transportation segment profit.

 

4



 

 

 

Actual

 

Guidance

 

 

 

Nine Months

 

Three Months

 

Twelve Months

 

 

 

Ended

 

Ending

 

Ending

 

 

 

Sep 30, 2012

 

Dec 31, 2012

 

Dec 31, 2012

 

Average Daily Volumes (MBbls/d)

 

 

 

 

 

 

 

Crude Oil Pipelines

 

 

 

 

 

 

 

All American

 

31

 

35

 

32

 

Basin

 

495

 

510

 

499

 

Capline

 

144

 

160

 

148

 

Line 63 / 2000

 

126

 

125

 

126

 

Salt Lake City Area Systems (1)

 

141

 

140

 

141

 

Permian Basin Area Systems (1)

 

450

 

470

 

455

 

Mid-Continent Area Systems (1)

 

247

 

265

 

252

 

Manito

 

59

 

50

 

57

 

Rainbow

 

147

 

145

 

146

 

Rangeland

 

60

 

55

 

59

 

Other

 

1,140

 

1,255

 

1,169

 

NGL Pipelines

 

163

 

205

 

174

 

Refined Products Pipelines

 

114

 

95

 

109

 

 

 

3,317

 

3,510

 

3,367

 

Trucking

 

103

 

105

 

104

 

 

 

3,420

 

3,615

 

3,471

 

Segment Profit per Barrel ($/Bbl)

 

 

 

 

 

 

 

Excluding Selected Items Impacting Comparability

 

$

0.58

 

$

0.58

(2)

$

0.58

(2)

 


(1)                       The aggregate of multiple systems in their respective areas.

(2)                         Mid-point of guidance.

 

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

 

Adjusted segment profit is forecasted using the volume assumptions in the table below, priced at forecasted rates, less estimated field operating costs and G&A expenses. Field operating costs do not include depreciation.

 

 

 

Actual

 

Guidance

 

 

 

Nine Months

 

Three Months

 

Twelve Months

 

 

 

Ended

 

Ending

 

Ending

 

 

 

Sep 30, 2012

 

Dec 31, 2012

 

Dec 31, 2012

 

Operating Data

 

 

 

 

 

 

 

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

 

88

 

94

 

90

 

Natural Gas Storage (Bcf/Mo.)

 

82

 

93

 

84

 

NGL Fractionation (MBbls/d)

 

73

 

105

 

81

 

Facilities Activities Total

 

 

 

 

 

 

 

Avg. Capacity (MMBbls/Mo.) (1) 

 

104

 

113

 

106

 

 

 

 

 

 

 

 

 

Segment Profit per Barrel ($/Bbl)

 

 

 

 

 

 

 

Excluding Selected Items Impacting Comparability

 

$

0.39

 

$

0.39

(2)

$

0.39

(2)

 


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

(2)                    Mid-point of guidance.

 

5



 

c.             Supply and Logistics. Our supply and logistics segment operations generally consist of the following activities:

 

·                  the purchase of 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;

 

·                  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 to maximize profits; and

 

·                  the transportation of crude oil and NGL on trucks, barges, railcars, pipelines and ocean-going vessels to our terminals and third-party terminals.

 

We characterize a substantial portion of the 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 as well as any operating and general and administrative 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 volatility in the crude oil market, as well as variable operating expenses. Forecasted operating results for the three-month period ending December 31, 2012 reflect the current market structure and seasonal, weather-related variations in NGL 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 contango inventory, based on current and anticipated market conditions. Actual volumes are influenced by temporary market-driven storage and withdrawal of 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, quality, and contract structure. Accordingly, the projected segment profit per barrel can vary significantly even if aggregate volumes are in line with the forecasted levels.

 

 

 

Actual

 

Guidance

 

 

 

Nine Months

 

Three Months

 

Twelve Months

 

 

 

Ended

 

Ending

 

Ending

 

 

 

Sep 30, 2012

 

Dec 31, 2012

 

Dec 31, 2012

 

Average Daily Volumes (MBbl/d)

 

 

 

 

 

 

 

Crude Oil Lease Gathering Purchases

 

808

 

835

 

815

 

NGL Sales

 

155

 

260

 

181

 

Waterborne cargos

 

3

 

 

2

 

 

 

966

 

1,095

 

998

 

 

 

 

 

 

 

 

 

Segment Profit per Barrel ($/Bbl)

 

 

 

 

 

 

 

Excluding Selected Items Impacting Comparability

 

$

2.22

 

$

1.92

(1)

$

2.14

(1)

 


(1)                 Mid-point of guidance.

 

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

 

6



 

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 2012 to be approximately $1.15 billion for expansion projects with an additional $160 to $170 million for maintenance capital projects. During the first nine months of 2012, we invested $831 million and $123 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, 2012:

 

 

 

Calendar 2012

 

 

(in millions)

Expansion Capital

 

 

· Eagle Ford Project

 

$125

· Spraberry Area Pipeline Projects

 

90

· Gardendale Gathering System (1)

 

85

· Rainbow II Pipeline

 

75

· PAA Natural Gas Storage (multiple projects)

 

61

· Bakken North

 

50

· Rail Projects (2)

 

50

· Mississippian Lime Project

 

45

· St. James Terminal Expansion (3)

 

45

· Yorktown Terminal Project

 

35

· Cushing Terminal Expansion (3)

 

30

· BP NGL Acquisition Related Projects

 

25

· Patoka Terminal Expansion (3)

 

25

· Shafter Expansion

 

18

· Other Projects (4)

 

391

 

 

$1,150

Potential Adjustments for Timing / Scope Refinement (5)

 

- $50 + $100

Total Projected Expansion Capital Expenditures

 

$1,100 - $1,250

 

 

 

Maintenance Capital Expenditures

 

$160 - $170

 


(1)                      Includes pipeline, tankage and condensate stabilization.

(2)                      Excludes rail project associated with the Yorktown terminal project.

(3)                      Includes carryover capital from 2011 expansions as well as new expansions.

(4)                      Primarily multiple, smaller projects comprised of pipeline connections, upgrades and truck stations, new tank construction and refurbishing, pipeline linefill purchases and carry-over of projects from prior years.

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

 

5.              Capital Structure. This guidance is based on our capital structure as of September 30, 2012 and adjusted for estimated equity issuances under our continuous offering program.

 

6.              Interest Expense. Debt balances are projected based on estimated cash flows, estimated distribution rates, estimated capital expenditures for maintenance and expansion projects, expected timing of collections and payments and forecasted levels of inventory and other working capital sources and uses. Interest rate assumptions for variable-rate debt are based on the current forward LIBOR curve.

 

Included in interest expense are commitment fees, amortization of long-term debt discounts or premiums, deferred amounts associated with terminated interest-rate hedges and interest on short-term debt for non-contango inventory (primarily hedged NGL inventory and New York Mercantile Exchange and Intercontinental Exchange margin deposits). Interest expense is net of amounts capitalized for major expansion capital projects and does not include interest on borrowings for inventory stored in a contango market. We treat interest on hedged inventory borrowings as carrying costs of crude oil and NGL and include it in purchases and related costs.

 

7.             Income Taxes. We expect Canadian income tax expense/(benefit) to be approximately $23 million and $66 million for the three-month and twelve-month periods ending December 31, 2012, respectively, of which approximately $22 million and $54 million, respectively, is classified as current.  For the twelve-month period ending December 31, 2012 we expect to have a deferred tax expense of $12 million.  All or part of the income tax expense of $66 million may result in a tax credit to our equity holders.

 

7



 

8.              Reconciliation of Adjusted EBITDA to Implied DCF. The following table reconciles the mid-point of adjusted EBITDA to implied distributable cash flow for the three-month and twelve-month periods ending December 31, 2012.

 

 

 

Mid-Point Guidance

 

 

 

Three Months

 

Twelve Months

 

 

 

Ending

 

Ending

 

 

 

December 31, 2012

 

December 31, 2012

 

 

 

(in millions)

 

Adjusted EBITDA

 

$

520

 

$

2,017

 

Interest expense, net

 

(76

)

(290

)

Current income tax benefit (expense)

 

(22

)

(54

)

Distributions to noncontrolling interests

 

(12

)

(48

)

Maintenance capital expenditures

 

(42

)

(165

)

Other, net

 

1

 

3

 

Implied DCF

 

$

369

 

$

1,463

 

 

9.              Equity Compensation Plans. The majority of grants outstanding under our various equity compensation plans contain vesting criteria that are based on a combination of performance benchmarks and service periods. The grants will vest in various percentages, typically on the later to occur of specified vesting dates and the dates on which minimum distribution levels are reached. Among the various grants outstanding as of November 5, 2012, estimated vesting dates range from November 2012 to May 2019 and annualized distribution levels range from $1.925 to $2.40. For some awards, a percentage of any units remaining unvested as of a certain date will vest on such date and all others will be forfeited.

 

On October 4, 2012, we declared an annualized distribution of $2.17 payable on November 14, 2012 to our unitholders of record as of November 2, 2012. For the purposes of guidance, we have made the assessment that a $2.35 distribution level is probable of occurring, and accordingly, guidance includes an accrual over the applicable service period at an assumed market price of $46.00 per unit as well as an accrual associated with awards that will vest on a certain date. The actual amount of equity compensation expense in any given period will be directly influenced by (i) our unit price at the end of each reporting period, (ii) our unit price on the vesting date, (iii) the probability assessment regarding distributions, and (iv) new equity compensation award grants. For example, a $2.00 change in the unit price during the fourth-quarter would change the fourth-quarter equity compensation expense by approximately $4 million. Therefore, actual net income could differ from our projections.

 

10.       Reconciliation of Net Income to EBIT and EBITDA. The following table reconciles net income to EBIT and EBITDA for the nine-month period ending September 30, 2012 and three-month and twelve-month periods ending December 31, 2012.

 

 

 

Actual

 

Guidance

 

 

 

9 Months

 

3 Months Ending

 

12 Months Ending

 

 

 

Ended

 

Dec 31, 2012

 

Dec 31, 2012

 

 

 

Sep 30, 2012

 

Low

 

High

 

Low

 

High

 

 

 

(in millions)

 

Reconciliation to EBITDA

 

 

 

 

 

 

 

 

 

 

 

Net Income

 

$

797

 

$

293

 

$

355

 

$

1,090

 

$

1,152

 

Interest expense, net

 

214

 

78

 

74

 

292

 

288

 

Income tax expense (benefit)

 

43

 

25

 

21

 

68

 

64

 

EBIT

 

1,054

 

396

 

450

 

1,450

 

1,504

 

Depreciation and amortization

 

356

 

88

 

84

 

444

 

440

 

EBITDA

 

$

1,410

 

$

484

 

$

534

 

$

1,894

 

$

1,944

 

 

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Preliminary 2013 Guidance

 

Our preliminary adjusted EBITDA guidance for 2013 is based on (i)  operating and financial performance of our existing assets that is assumed to be generally in line with recent performance trends, appropriately adjusted for known and expected developments as well as estimated market conditions, (ii) achievement of targeted performance levels for recent acquisitions and (iii) contributions from expansion capital projects in line with our expectations. In addition, our preliminary 2013 guidance does not include any forecast for acquisitions that we may commit to after the date hereof.  The following table summarizes the range of selected key financial data of our preliminary guidance for calendar year 2013.

 

Preliminary Calendar 2013 Guidance (in millions)

 

 

 

Low

 

High

 

Adjusted EBITDA

 

$

1,875

 

$

1,975

 

Interest expense, net

 

(320

)

(310

)

Current income tax benefit (expense)

 

(45

)

(35

)

Distributions to noncontrolling interests

 

(50

)

(46

)

Maintenance capital expenditures

 

(180

)

(160

)

Other, net

 

 

 

Implied DCF

 

1,280

 

1,424

 

 

 

 

 

 

 

Expansion Capital

 

$

900

 

$

1,100

 

 

Our preliminary guidance for interest expense is based on our capital structure as of September 30, 2012 and adjusted for estimated equity issuances under our continuous equity offering program, approved capital projects for 2012, and the assumption that 2013 capital projects will range between $900 million and $1.1 billion. Our preliminary guidance for maintenance capital expenditures is based on our estimated average level of recurring expenditures of approximately $170 million. Our preliminary guidance for adjusted net income and adjusted EBITDA does not include a forecast of selected items impacting comparability, such as equity compensation expense, as it is impractical to forecast such items.

 

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Forward-Looking Statements and Associated Risks

 

All statements included in this report, other than statements of historical fact, are forward-looking statements, including, but not limited to, statements incorporating the words “anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend” and “forecast,” as well as similar expressions and statements regarding our business strategy, plans and objectives for future operations. The absence of these words, however, does not mean that the statements are not forward-looking. These 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 to differ materially from results anticipated in the forward-looking statements. The most important of these factors include, but are not limited to:

 

·                  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;

 

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

 

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

 

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

 

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

 

·                  the effectiveness of our risk management activities;

 

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

 

·                  abrupt or severe declines or interruptions in outer continental shelf production located offshore California and transported on our pipeline systems;

 

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

 

·                 the availability of adequate third-party production volumes for transportation and marketing in the areas in which we operate and other factors that could cause declines in volumes shipped on our pipelines by us and third-party shippers, such as declines in production from existing oil and gas reserves or failure to develop additional oil and gas reserves;

 

·                  fluctuations in refinery capacity in areas supplied by our mainlines and other factors affecting demand for various grades of crude oil, refined products and natural gas and resulting changes in pricing conditions or transportation throughput requirements;

 

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

 

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

 

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

 

·                  the effects of competition;

 

·                  interruptions in service on third-party pipelines;

 

·                  increased costs or lack of availability of insurance;

 

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

 

·                  the currency exchange rate of the Canadian dollar;

 

·                 weather interference with business operations or project construction;

 

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·                  risks related to the development and operation of natural gas storage facilities;

 

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

 

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

 

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

 

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

 

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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 5, 2012

By:

/s/ Charles Kingswell-Smith

 

 

Name:

Charles Kingswell-Smith

 

 

Title:

Vice President and Treasurer

 

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