UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

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FORM 10-Q

 

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☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended June 30, 2015

 

OR

 

☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

Commission File Number: 1-14569

 

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PLAINS ALL AMERICAN PIPELINE, L.P.

(Exact name of registrant as specified in its charter)

 

 

 

 

(713) 646-4100

(Registrant’s telephone number, including area code)

 

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Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  ☒ Yes  ☐ No

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  ☒ Yes  ☐ No

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  ☐ Yes  ☒ No

 

As of July 31, 2015, there were 397,680,214 Common Units outstanding.

 

 

 

 

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

 

 

 

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PART I. FINANCIAL INFORMATION

 

Item 1.UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in

(in millions, except unit data)

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

(in millions)

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

(in millions)

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(in millions)

 

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

 

Note 1—Organization and Basis of Consolidation and Presentation

 

Organization

 

Plains All American Pipeline, L.P. (“PAA”) is a Delaware limited partnership formed in 1998. Our operations are conducted directly and indirectly through our primary operating subsidiaries. As used in this Form 10-Q and unless the context indicates otherwise, the terms “Partnership,” “we,” “us,” “our,” “ours” and similar terms refer to PAA and its subsidiaries.

 

We own and operate midstream energy infrastructure and provide logistics services for crude oil, natural gas liquids (“NGL”), natural gas and refined products. We own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. Our business activities are conducted through three operating segments: Transportation, Facilities and Supply and Logistics. See Note 11 for further discussion of our operating segments.

 

Our 2% general partner interest is held by PAA GP LLC, a Delaware limited liability company, whose sole member is Plains AAP, L.P. (“AAP”), a Delaware limited partnership. In addition to its ownership of PAA GP LLC, AAP also owns all of our incentive distribution rights (“IDRs”). Plains All American GP LLC (“GP LLC”), a Delaware limited liability company, is AAP’s general partner. Plains GP Holdings, L.P. (“PAGP”) is the sole member of GP LLC, and at June 30, 2015, owned an approximate 37% limited partner interest in AAP.

 

GP LLC manages our operations and activities and employs our domestic officers and personnel. Our Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC (“PMC”). References to our “general partner,” as the context requires, include any or all of PAA GP LLC, AAP and GP LLC.

 

Definitions

 

Additional defined terms are used in this Form 10-Q and shall have the meanings indicated below:

 

 

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Basis of Consolidation and Presentation

 

The accompanying unaudited condensed consolidated interim financial statements and related notes thereto should be read in conjunction with our 2014 Annual Report on Form 10-K. The accompanying condensed consolidated financial statements include the accounts of PAA and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. The financial statements have been prepared in accordance with the instructions for interim reporting as set forth by the SEC. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. These reclassifications do not affect net income attributable to PAA. The condensed consolidated balance sheet data as of December 31, 2014 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three and six months ended June 30, 2015 should not be taken as indicative of results to be expected for the entire year.

 

Subsequent events have been evaluated through the financial statements issuance date and have been included in the following footnotes where applicable.

 

Note 2—Recent Accounting Pronouncements

 

In April 2015, the FASB issued guidance to simplify the presentation of debt issuance costs in entities’ financial statements. Under this revised guidance, an entity will present such costs as a direct reduction from the related debt liability (rather than as an asset under current guidance). Additionally, amortization of the debt issuance costs will be reported as interest expense. This guidance will become effective for interim and annual periods beginning after December 15, 2015 and will be adopted retrospectively to all prior periods. Early adoption is permitted for financial statements that have not been previously issued. We expect to adopt this guidance on January 1, 2016, and we are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows.

 

In February 2015, the FASB issued guidance that revises the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. All legal entities are subject to reevaluation under the revised consolidation model. Among other things, this guidance (i) modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities, (ii) eliminates the presumption that a general partner should consolidate a limited partnership and (iii) affects the consolidation analysis of reporting entities that are involved with variable interest entities, particularly those that have fee arrangements and related party relationships. This guidance will become effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted, including adoption in an interim period. We expect to adopt this guidance on January 1, 2016, and we are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows.

 

In January 2015, as part of its initiative to reduce complexity in accounting standards, the FASB issued guidance to eliminate the concept of extraordinary items from GAAP. This guidance will become effective for interim and annual periods beginning after December 15, 2015. We expect to adopt this guidance on January 1, 2016. We do not believe our adoption will have a material impact on our financial position, results of operations or cash flows.

 

In May 2014, the FASB issued guidance regarding the recognition of revenue from contracts with customers with the underlying principle that an entity will recognize revenue to reflect amounts expected to be received in exchange for the provision of goods and services to customers upon the transfer of those goods or services. The guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. This guidance can be adopted either with a full retrospective approach or a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. In July 2015, the FASB voted to approve a one-year deferral of the effective date of this standard, with final guidance expected to be issued by the end of the third quarter of 2015. This deferral would make the guidance effective for interim and annual periods beginning after December 15, 2017. Therefore, we  currently expect to adopt this guidance on January 1, 2018, and we are evaluating which transition

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approach to apply and the effect that adopting this guidance will have on our financial position, results of operations and cash flows. 

 

In April 2014, the FASB issued guidance that modifies the criteria under which assets to be disposed of are evaluated to determine if such assets qualify as a discontinued operation and requires new disclosures for both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. This guidance is effective prospectively for annual and interim reporting periods beginning after December 15, 2014. We adopted this guidance on January 1, 2015. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

 

Note 3—Net Income Per Limited Partner Unit

 

Basic and diluted net income per limited partner unit is determined pursuant to the two-class method for MLPs as prescribed in FASB guidance. The two-class method is an earnings allocation formula that is used to determine earnings to our general partner, common unitholders and participating securities according to distributions pertaining to the current period’s net income and participation rights in undistributed earnings. Under this method, all earnings are allocated to our general partner, common unitholders and participating securities based on their respective rights to receive distributions, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective.

 

We calculate basic and diluted net income per limited partner unit by dividing net income attributable to PAA (after deducting the amount allocated to the general partner’s interest, IDRs and participating securities) by the basic and diluted weighted-average number of limited partner units outstanding during the period. Participating securities include LTIP awards that have vested DERs, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units.

 

Diluted net income per limited partner unit is computed based on the weighted average number of limited partner units plus the effect of dilutive potential limited partner units outstanding during the period using the two-class method. Our 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 limited partner unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. See Note 16 to our Consolidated Financial Statements included in Part IV of our 2014 Annual Report on Form 10-K for a complete discussion of our LTIP awards including specific discussion regarding DERs.

 

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The following table sets forth the computation of basic and diluted net income/(loss) per limited partner unit for the periods indicated (in millions, except per unit data):

 

 

 

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Pursuant to the terms of our partnership agreement, the general partner’s incentive distribution is limited to a percentage of available cash, which, as defined in the partnership agreement, is net of reserves deemed appropriate. As such, IDRs are not allocated undistributed earnings or distributions in excess of earnings in the calculation of net income per limited partner unit. If, however, undistributed earnings were allocated to our IDRs beyond amounts distributed to them under the terms of our partnership agreement, basic and diluted net income/(loss) per limited partner unit as reflected in the table above would not have been impacted, as we did not have undistributed earnings for any of the periods presented.

 

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Note 4—Accounts Receivable

 

Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL and natural gas. These purchasers include, but are not limited to, refiners, producers, marketing and trading companies and financial institutions that are active in the physical and financial commodity markets. The majority of our accounts receivable relate to our crude oil supply and logistics activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes.

 

To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash payments, standby letters of credit or parental guarantees. As of June 30, 2015 and December 31, 2014, we had received $115 million and $180 million, respectively, of advance cash payments from third parties to mitigate credit risk. We also received $77 million and $198 million, as of June 30, 2015 and December 31, 2014, respectively, of standby letters of credit to support obligations due from third parties, a portion of which applies to future business. The decrease in standby letters of credit and advance cash payments from third parties as of June 30, 2015 compared to December 31, 2014 is largely due to a decrease in exposure to various customers requiring letters of credit. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. Furthermore, we also enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet) for a majority of such arrangements.

 

We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At June 30, 2015 and December 31, 2014, substantially all of our trade accounts receivable (net of allowance for doubtful accounts) were less than 30 days past their scheduled invoice date. Our allowance for doubtful accounts receivable totaled $4 million as of both June 30, 2015 and December 31, 2014.  Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

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Note 5—Inventory, Linefill and Base Gas and Long-term Inventory

 

Inventory, linefill and base gas and long-term inventory consisted of the following as of the dates indicated (barrels and natural gas volumes in thousands and carrying value in millions):

 

 

 

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At the end of each reporting period, we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. Any resulting adjustments are a component of “Purchases and related costs” on our accompanying Condensed Consolidated Statements of Operations. We recorded a charge of $24 million during the six months ended June 30, 2015, which primarily related to the writedown of our NGL inventory due to declines in prices during the first quarter of 2015. The loss was substantially offset by a portion of the derivative mark-to-market gain that was recognized in the fourth quarter of 2014. See Note 8 for discussion of our derivative and risk management activities. During the six months ended June 30, 2014, we recorded a charge of $37 million related to the writedown of our natural gas inventory that was purchased in conjunction with managing natural gas storage deliverability requirements during the extended period of severe cold weather in the first quarter of 2014.

 

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Note 6—Debt

 

Debt consisted of the following as of the dates indicated (in millions):

 

 

 

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Credit Facilities

 

Senior unsecured 364-day revolving credit facility. In January 2015, we entered into a 364-day senior unsecured credit agreement with a borrowing capacity of $1.0 billion. Borrowings will accrue interest based, at our election, on either the Eurocurrency Rate or the Base Rate, as defined in the agreement, in each case plus a margin based on our credit rating at the applicable time.

 

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Borrowings and Repayments

 

Total borrowings under our credit agreements and commercial paper program for the six months ended June 30, 2015 and 2014 were approximately $17.9 billion and $34.6 billion, respectively. Total repayments under our credit agreements and commercial paper program were approximately $17.7 billion and $34.9 billion for the six months ended June 30, 2015 and 2014, respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities.

 

Letters of Credit

 

In connection with our supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil, NGL and natural gas. Additionally, we issue letters of credit to support insurance programs, derivative transactions and construction activities. At June 30, 2015 and December 31, 2014, we had outstanding letters of credit of $63 million and $87 million, respectively.

 

Senior Notes Repayments

 

In June 2015, we repaid our $150 million, 5.25% senior notes. We utilized cash on hand and available capacity under our commercial paper program to repay these notes.

 

Note 7—Partners’ Capital and Distributions

 

Distributions

 

The following table details the distributions paid during or pertaining to the first six months of 2015, net of reductions to the general partner’s incentive distributions (in millions, except per unit data):

 

 

 

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PAA Equity Offerings

 

Continuous Offering Program. During the six months ended June 30, 2015, we issued an aggregate of approximately 1.1 million common units under our continuous offering program, generating proceeds of $59 million, including our general partner’s proportionate capital contribution of $1 million, net of $1 million of commissions to our sales agents.

 

Underwritten Offering. In March 2015, we completed an underwritten public offering of 21.0 million common units, generating proceeds of approximately $1.1 billion, including our general partner’s proportionate capital contribution of $21 million, net of costs associated with the offering.

 

Noncontrolling Interests in Subsidiaries

 

As of June 30, 2015, noncontrolling interests in our subsidiaries consisted of a 25% interest in SLC Pipeline LLC.

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Note 8—Derivatives and Risk Management Activities

 

We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on hydrocarbon commodity (referred to herein as “commodity”) price changes. We use various derivative instruments to (i) manage our exposure to commodity price risk, as well as to optimize our profits, (ii) manage our exposure to interest rate risk and (iii) manage our exposure to currency exchange rate risk. Our commodity risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our derivative positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. Our interest rate and currency exchange rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies. When we apply hedge accounting, our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in a transaction are highly effective in offsetting changes in cash flows or the fair value of hedged items.

 

Commodity Price Risk Hedging

 

Our core business activities involve certain commodity price-related risks that we manage in various ways, including through the use of derivative instruments. Our policy is to (i) only purchase inventory for which we have a market, (ii) structure our sales contracts so that price fluctuations do not materially affect our operating income and (iii) not acquire and hold physical inventory or derivatives for the purpose of speculating on commodity price changes.  The material commodity-related risks inherent in our business activities can be divided into the following general categories:

 

Commodity Purchases and Sales — In the normal course of our operations, we purchase and sell commodities.  We use derivatives to manage the associated risks and to optimize profits. As of June 30, 2015, net derivative positions related to these activities included:

 

 

 

 

 

 

Storage Capacity Utilization — We own a significant amount of crude oil, NGL and refined products storage capacity other than that used in our transportation operations. This storage may be leased to third parties or utilized in our own supply and logistics activities, including for the storage of inventory in a contango market. For capacity allocated to our supply and logistics operations, we have utilization risk in a backwardated market structure. As of June 30, 2015, we used derivatives to manage the risk of not utilizing approximately 0.8 million barrels of storage capacity through January 2016. These positions involve no outright price exposure, but instead enable us to profitably use the capacity to store hedged crude oil.

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Natural Gas Processing/NGL Fractionation — We purchase natural gas for processing and operational needs. Additionally, we purchase NGL mix for fractionation and sell the resulting individual specification products (including ethane, propane, butane and condensate). In conjunction with these activities, we hedge the price risk associated with the purchase of the natural gas and the subsequent sale of the individual specification products. As of June 30, 2015, we had a long natural gas position of 15.2 Bcf through December 2016, a short propane position of 2.9 million barrels through December 2016, a short butane position of 0.9 million barrels through December 2016 and a short WTI position of 0.3 million barrels through December 2016. In addition, we had a long power position of 0.5 million megawatt hours, which hedges a portion of our power supply requirements at our natural gas processing and fractionation plants through December 2018.

 

To the extent they qualify and we decide to make the election, all of our commodity derivatives for which we elect hedge accounting are designated as cash flow hedges. Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the normal purchases and normal sales scope exception are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings. We have determined that substantially all of our physical purchase and sale agreements qualify for the normal purchases and normal sales scope exception.

 

Interest Rate Risk Hedging

 

We use interest rate derivatives to hedge interest rate risk associated with anticipated and outstanding interest payments occurring as a result of debt issuances. The derivative instruments we use to manage this risk consist primarily of interest rate swaps and treasury locks. As of June 30, 2015, AOCI includes deferred losses of $109 million that relate to open and terminated interest rate derivatives that were designated as cash flow hedges. The terminated interest rate derivatives were cash-settled in connection with the issuance or refinancing of debt agreements. The deferred loss related to these instruments is being amortized to interest expense over the terms of the hedged debt instruments.

 

We have entered into forward starting interest rate swaps to hedge the underlying benchmark interest rate related to forecasted interest payments through 2049. The following table summarizes the terms of our forward starting interest rate swaps as of June 30, 2015 (notional amounts in millions):

 

 

 

During June 2015, we terminated ten forward starting swaps. These swaps had an aggregate notional amount of $250 million and an average fixed rate of 3.60%. We made a cash payment of approximately $31 million in connection with the termination of these swaps.

 

Currency Exchange Rate Risk Hedging

 

Because a significant portion of our Canadian business is conducted in CAD and, at times, a portion of our debt is denominated in CAD, we use foreign currency derivatives to minimize the risk of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts and forwards.

 

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As of June 30, 2015, our outstanding foreign currency derivatives include derivatives we use to (i) hedge currency exchange risk associated with USD-denominated commodity purchases and sales in Canada and (ii) hedge currency exchange risk created by the use of USD-denominated commodity derivatives to hedge commodity price risk associated with CAD-denominated commodity purchases and sales.

 

The following table summarizes our open forward exchange contracts as of June 30, 2015 (in millions):

 

 

 

Summary of Financial Impact

 

We record all open derivatives on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives that qualify as cash flow hedges, changes in fair value of the effective portion of the hedges are deferred in AOCI and recognized in earnings in the periods during which the underlying physical transactions are recognized in earnings. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective in offsetting changes in cash flows of the hedged items are recognized in earnings each period. Cash settlements associated with our derivative activities are classified within the same category as the related hedged item in our Condensed Consolidated Statements of Cash Flows.

 

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A summary of the impact of our derivative activities recognized in earnings for the periods indicated is as follows (in millions):

 

 

 

 

 

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The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheets on a gross basis as of June 30, 2015 (in millions):

 

 

 

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The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheets on a gross basis as of December 31, 2014 (in millions):

 

 

 

Our derivative transactions are governed through ISDA (International Swaps and Derivatives Association) master agreements and clearing brokerage agreements. These agreements include stipulations regarding the right of set off in the event that we or our counterparty default on our performance obligations. If a default were to occur, both parties have the right to net amounts payable and receivable into a single net settlement between parties.

 

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through clearing brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. As of June 30, 2015, we had a net broker payable of $46 million (consisting of initial margin of $49 million reduced by $95 million of variation margin that had been returned to us). As of December 31, 2014, we had a net broker payable of $133 million (consisting of initial margin of $126 million reduced by $259 million of variation margin that had been returned to us).

 

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The following table presents information about derivatives and financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements as of the dates indicated (in millions):

 

 

 

As of June 30, 2015, there was a net loss of $120 million deferred in AOCI including tax effects. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with (i) the earnings recognition of the underlying hedged commodity transaction or (ii) interest expense accruals associated with underlying debt instruments. Of the total net loss deferred in AOCI at June 30, 2015, we expect to reclassify a net gain of $4 million to earnings in the next twelve months. The remaining deferred loss of $124 million is expected to be reclassified to earnings through 2049. A portion of these amounts are based on market prices as of June 30, 2015; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

 

The net deferred gain/(loss), including tax effects, recognized in AOCI for derivatives for the periods indicated was as follows (in millions):

 

 

 

At June 30, 2015 and December 31, 2014, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. Although we may be required to post margin on our cleared derivatives as described above, we do not require our non-cleared derivative counterparties to post collateral with us.

 

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Recurring Fair Value Measurements

 

Derivative Financial Assets and Liabilities

 

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the dates indicated (in millions):

 

 

 

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Level 1

 

Level 1 of the fair value hierarchy includes exchange-traded commodity derivatives such as futures and options. The fair value of exchange-traded commodity derivatives is based on unadjusted quoted prices in active markets.

 

Level 2

 

Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives and over-the-counter commodity, interest rate and foreign currency derivatives that are traded in active markets. In addition, it includes certain physical commodity contracts. The fair value of these derivatives is based on broker price quotations which are corroborated with market observable inputs.

 

Level 3

 

Level 3 of the fair value hierarchy includes certain physical commodity contracts. The fair value of our Level 3 physical commodity contracts is based on a valuation model utilizing broker-quoted forward commodity prices, and timing estimates, which involve management judgment. The significant unobservable inputs used in the fair value measurement of our Level 3 derivatives are forward prices obtained from brokers. A significant increase or decrease in these forward prices could result in a material change in fair value to our Level 3 derivatives. We report unrealized gains and losses associated with Level 3 commodity derivatives in our Condensed Consolidated Statements of Operations as Supply and Logistics segment revenues.

 

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Rollforward of Level 3 Net Asset/(Liability)

 

 

 

The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives classified as Level 3 for the periods indicated (in millions):

 

 

 

 

Note 9—Equity-Indexed Compensation Plans

 

We refer to the PAA LTIPs and AAP Management Units collectively as our “equity-indexed compensation plans.” For additional discussion of our equity-indexed compensation plans and awards, see Note 16 to our Consolidated Financial Statements included in Part IV of our 2014 Annual Report on Form 10-K.

 

PAA LTIP Awards

 

Activity for LTIP awards under our equity-indexed compensation plans denominated in PAA units is summarized in the following table (units in millions):

 

 

 

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AAP Management Units

 

Activity for AAP Management Units is summarized in the following table (in millions):

 

 

 

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Other Consolidated Equity-Indexed Compensation Plan Information

 

The table below summarizes the expense recognized and the value of vested LTIP awards (settled both in common units and cash) under our equity-indexed compensation plans and includes both liability-classified and equity-classified awards for the periods indicated (in millions):

 

 

Note 10—Commitments and Contingencies

 

Loss Contingencies — General

 

To the extent we are able to assess the likelihood of a negative outcome for a contingency, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue an undiscounted liability equal to the estimated amount.  If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then we accrue an undiscounted liability equal to the minimum amount in the range.  In addition, we estimate legal fees that we expect to incur associated with loss contingencies and accrue those costs when they are material and probable of being incurred.

 

We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss.

 

Legal Proceedings — General

 

In the ordinary course of business, we are involved in various legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully protect us from losses arising from current or future legal proceedings.

 

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Taking into account what we believe to be all relevant known facts and circumstances, and based on what we believe to be reasonable assumptions regarding the application of those facts and circumstances to existing laws and regulations, we do not believe that the outcome of the legal proceedings in which we are currently involved (including those described below) will, individually or in the aggregate, have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

 

Environmental — General

 

Although over the course of the last several years we have made significant investments in our maintenance and integrity programs, and have hired additional personnel in those areas, we have experienced (and likely will experience future) releases of hydrocarbon products into the environment from our pipeline, rail and storage operations. These releases can result from accidents or from unpredictable man-made or natural forces and may reach surface water bodies, groundwater aquifers or other sensitive environments. Damages and liabilities associated with any such releases from our existing or future assets could be significant and could have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

 

At June 30, 2015, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident, as discussed further below) totaled $297 million, of which $197 million was classified as short-term and $100 million was classified as long-term. At December 31, 2014, our estimated undiscounted reserve for environmental liabilities totaled $82 million, of which $13 million was classified as short-term and $69 million was classified as long-term. The short- and long-term environmental liabilities referenced above are reflected in “Accounts payable and accrued liabilities” and “Other long-term liabilities and deferred credits,” respectively, on our Condensed Consolidated Balance Sheets. At June 30, 2015 and December 31, 2014, we had recorded receivables totaling $200 million and $8 million, respectively, for amounts probable of recovery under insurance and from third parties under indemnification agreements, which are predominantly reflected in “Trade accounts receivable and other receivables, net” on our Condensed Consolidated Balance Sheets.

 

In some cases, the actual cash expenditures associated with these liabilities may not occur for three years or longer. Our estimates used in determining these reserves are based on information currently available to us and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing legal claims giving rise to additional liabilities. Therefore, although we believe that the reserve is adequate, costs incurred may be in excess of the reserve and may potentially have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

 

Specific Legal, Environmental or Regulatory Matters

 

Line 901 Incident. During May 2015, we experienced a crude oil release from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California.  A portion of the released crude oil reached the Pacific Ocean at Refugio State Beach through a drainage culvert. Following the release, we shut down the pipeline and initiated our emergency response plan. A Unified Command, which includes the United States Coast Guard, the EPA, the California Office of Spill Prevention and Response and the Santa Barbara Office of Emergency Management was established for the response effort. Clean-up and remediation operations and contamination monitoring continue, and the cause of the release is currently under investigation. 

 

Although the precise volume of crude oil released in connection with this incident has not been determined, following the release, we developed and have periodically updated a “worst case” estimate of the amount of oil spilled, which represents what we believe to be the maximum volume of oil that could have been spilled based on relevant facts, data and information available at the time of such calculation.  Our worst-case estimate has been developed primarily using information regarding (i) an estimate of the amount of oil that flowed into Line 901 during the period between the estimated time of release and the point when the pumps were shut down and (ii) an estimate of the volume of oil that drained out of the line due to the natural force of gravity based on the characteristics of the pipeline (i.e., length, elevation profile, diameter and location of the release point).  Using this “drain-down” methodology, our worst case

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estimate of the volume of oil released totaled approximately 2,400 barrels. We believe that the “drain-down” methodology represents the most straight forward and accurate calculation of the potential worst case discharge.

 

In the second half of June we completed the process of emptying and purging Line 901, which resulted in the removal of approximately 26,500 barrels of crude oil from the line.  This activity provided additional data to assess the reasonableness of our worst case estimate of 2,400 barrels based on the “drain-down” methodology.  Based on a preliminary analysis, an alternative calculation using the purge data could be as much as 1,000 barrels higher than the worst-case estimate calculated using the drain-down methodology.  However, the alternative calculation does not take into account certain factors that could account for a meaningful portion of the difference between the two calculations and this reconciliation process is ongoing.  As part of our effort to reconcile these differences, we have retained an outside, third party consulting firm to review the materials and submit a report, but such study has not been completed.  Accordingly, to date we have not finalized our calculation of the “worst case” estimate of the amount of oil released from Line 901, and such volume estimate may change as additional facts, data and information are analyzed during the course of the investigation of this incident. Any variance between the current and final estimate of the worst case discharge is not expected to impact our estimate of response, clean-up or remediation costs, but could impact our estimate of fines and penalties.

 

As a result of the Line 901 incident, several governmental agencies and regulators have initiated investigations into the Line 901 incident, various claims have been made against us and a number of lawsuits have been filed against us. Set forth below is a brief summary of such actions and matters:

 

On May 21, 2015, we received a corrective action order from the United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”), the governmental agency that has jurisdiction over the operation of Line 901 as well as over a second stretch of pipeline extending from Gaviota Pump Station in Santa Barbara County to Emidio Pump Station in Kern County, California (Line 903), requiring us to shut down, purge, review, remediate and test Line 901. On June 3, 2015, the corrective action order was amended to require us to take additional corrective actions with respect to both Lines 901 and 903 (as amended, the “CAO”). Among other requirements, the CAO also obligates us to conduct a root cause failure analysis with respect to Line 901 and present remedial work plans and restart plans to PHMSA prior to returning Line 901 to service; the CAO also imposes a pressure restriction on Line 903 and requires us to take other specified actions with respect to both Lines 901 and 903. We fully intend to comply with the CAO and to cooperate with any other governmental investigations relating to or arising out of the release. Excavation and removal of the affected section of the pipeline was completed on May 28, 2015. No timeline has been established for the restart of Line 901.  By virtue of its statutory authority, PHMSA has the power and authority to impose fines and penalties on us and cause civil or criminal charges to be brought against us. While to date PHMSA has not imposed any such fines or penalties or pursued any such civil or criminal charges, there can be no assurance that such fines or penalties will not be imposed upon us, or that such civil or criminal charges will not be brought against us, in the future.

 

In late May, on behalf of the EPA, the United States Attorney for the Department of Justice, Central District of California, Environmental Crimes Section (“DOJ”) began an investigation into whether there were any violations of federal criminal statutes in connection with the Line 901 incident, including potential violations of the federal Clean Water Act. We are cooperating with the DOJ’s investigation by responding to their requests for documents and access to our employees. The DOJ has expressed an interest in talking to several of our employees and consistent with the terms of our governing organizational documents, we are funding their defense costs, including the costs of separate counsel engaged to represent such individuals.  In addition to the DOJ, the California Attorney General’s Office and the District Attorney’s Office for the County of Santa Barbara have also announced that they are investigating the Line 901 incident to determine whether any applicable state or local laws have been violated.  While to date no civil or criminal charges have been brought against PAA or any of its affiliates, officers or employees by the DOJ, California Attorney General or Santa Barbara County District Attorney, and no fines or penalties have been imposed by such governmental agents, there can be no assurance that such fines or penalties will not be imposed upon us, or that such civil or criminal charges will not be brought against us, in the future.

 

Shortly following the Line 901 incident, we established a claims line and encouraged any parties that were damaged by the release to contact us to discuss their damage claims. We have received a number of claims through the

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claims line and we are processing those claims as we receive them. In addition, we have also had six class action lawsuits filed against us, all of which have been filed in the United States District Court for the Central District of California. In general, these lawsuits have been brought by various plaintiffs seeking to establish different classes of claimants that have allegedly been damaged by the release, including potential classes such as persons that derive a significant portion of their income through commercial fishing and harvesting activities in the waters adjacent to Santa Barbara County or from businesses that are dependent on marine resources from Santa Barbara County, retail businesses located in historic downtown Santa Barbara, certain owners of oceanfront and/or beachfront property on the Pacific Coast of California, and other classes of businesses that were allegedly impacted by the release.

 

In addition to the foregoing, as the “responsible party” for the Line 901 incident we are liable for various costs and for certain natural resource damages under the Oil Pollution Act, and we also have exposure to the payment of additional fines, penalties and costs under other applicable federal, state and local laws, statutes and regulations.  To the extent any such costs are reasonably estimable, we have included an estimate of such costs in the loss accrual described below.

 

Taking the foregoing into account, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately $257 million, which estimate includes actual and projected emergency response and clean-up costs, natural resource damage assessments and certain third party claims settlements as well as estimates for fines, penalties and certain legal fees. This estimate does not include any lost revenue associated with the shutdown of Line 901 or 903. In addition, this estimate considers our prior experience in environmental investigation and remediation matters and available data from, and in consultation with, our environmental and other specialists, as well as currently available facts and presently enacted laws and regulations. We have made assumptions for (i) the expected number of days that clean up, remediation and monitoring services will be required, the number of personnel and equipment required at the site and the rates charged by the associated service and equipment providers, (ii) the duration of the natural resource damage assessment and the ultimate amount of damages determined, (iii) the resolution of certain third party claims and lawsuits, but excluding claims and lawsuits with respect to which losses are not probable and reasonably estimable, and excluding future claims and lawsuits,  (iv) the determination and calculation of fines and penalties and (v) the nature,  extent and cost of  legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Line 901 incident. We believe we have accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that we have made. Our assumptions and estimates may turn out to be inaccurate and our total costs could turn out to be higher; accordingly, we can provide no assurance that we will not have to accrue additional costs in the future with respect to the Line 901 incident.

 

We have accrued such estimate of aggregate total costs to “Field operating costs” on our Condensed Consolidated Statement of Operations. As of June 30, 2015, we had a remaining undiscounted gross liability of $221 million related to this event, the majority of which is presented as a current liability in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheets. We maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such environmental liabilities. Subject to such exclusions and deductibles, we believe that our coverage is adequate to cover the current estimated total emergency response and clean-up costs, claims settlement costs and remediation costs and we believe that this coverage is also adequate to cover any potential increase in the estimates for these costs that exceed the amounts currently identified. We therefore have recognized a receivable of $192 million as of June 30, 2015 for the portion of the release costs that we believe is probable of recovery from insurance, net of deductibles. A majority of this receivable has been recognized as a current asset in “Trade accounts receivable and other receivables, net” on our Condensed Consolidated Balance Sheets with the offset reducing “Field operating costs” on our Condensed Consolidated Statement of Operations. We currently expect that the clean-up and remediation efforts, excluding long-term site monitoring activities, will be substantially completed during 2015; however, we expect to make payments for additional costs associated with restoration and monitoring of the area, as well as natural resource damage assessment, legal, professional and regulatory costs, in addition to fines and penalties, during future periods.

 

MP29 Release. On July 10, 2015, we experienced a crude oil release of approximately 100 barrels at our Pocahontas Pump Station near the border of Bond and Madison Counties in Illinois, approximately 40 miles from St. Louis Missouri. The Pocahontas Station is part of the Capwood pipeline that runs from our Patoka Station to Wood

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River, Illinois. A portion of the released crude oil was contained within our Pocahontas facility, but some of the released crude oil entered a nearby waterway where it was contained with booms. On July 14, 2015, PHMSA issued a corrective action order requiring us to take various actions in response to the release, including remediation, reporting and other actions. We are in the process of satisfying the requirements of the corrective action order. To date, no fines or penalties have been assessed in this matter; however, it is possible that fines and penalties could be assessed in the future. In connection with this incident, we have also had one class action lawsuit filed against us in the United States District Court for the Southern District of Illinois. In this lawsuit, the plaintiff seeks unspecified money damages and other remedies on behalf of itself and other unspecified similarly situated claimants. We estimate that the aggregate total costs associated with this release will be less than $10 million.

 

Cushing Tank Cathodic Protection.  On May 22, 2015, PHMSA issued a Final Order relating to an April 2013 Notice of Probable Violation and Proposed Compliance Order alleging that we did not maintain adequate cathodic protection for certain tanks at our Cushing Terminal. In its 2013 Notice of Probable Violation, PHMSA maintained that the proprietary cathodic protection system utilized by us for certain of our storage tanks at our Cushing, Oklahoma facility was not contemplated by applicable regulations. In response to the notice, we provided extensive documentation and supporting information regarding the effectiveness of the technology we were utilizing, including past communications with PHMSA regarding the topic. At a hearing in August 2013 we gave a formal presentation on the technology, provided empirical data confirming its effectiveness and also had a third party corrosion expert witness speak to the effectiveness of the technology. Almost two years later, PHMSA issued the Final Order and Compliance Order dated May 22, 2015 ruling against our position, assessing a penalty of $102,900 and specifying certain corrective actions to be completed by us. We chose not to further contest this matter and paid the penalty on June 5, 2015. On July 14, 2015, we submitted to PHMSA a Remediation Plan and schedule to satisfy the conditions of the Compliance Order. 

 

In the Matter of Bakersfield Crude Terminal LLC et al. On April 30, 2015, the EPA issued a Finding and Notice of Violation (“NOV”) to Bakersfield Crude Terminal LLC, our subsidiary, for alleged violations of the Clean Air Act, as amended. The NOV, which cites 10 separate rule violations, questions the validity of construction and operating permits issued to our Bakersfield rail unloading facility in 2012 and 2014 by the San Joaquin Valley Air Pollution Control District (the “SJV District”). We believe we fully complied with all applicable regulatory requirements and that the permits issued to us by the SJV District are valid. To date, no fines or penalties have been assessed in this matter; however, it is possible that fines and penalties could be assessed in the future.

 

National Energy Board Audit. In the third quarter of 2014, the National Energy Board (“NEB”) of Canada notified PMC that various corrective actions from a 2010 audit had not been completed to the satisfaction of the NEB. The NEB initiated a process to assess PMC’s approach to compliance with the NEB’s Onshore Pipeline Regulations, which process resulted in the issuance by the NEB of an order on January 15, 2015 that imposed six conditions on PMC designed to enhance PMC’s ability to operate its pipelines in a manner that protects the public and the environment. The conditions include the filing of certain safety critical tasks, controls and programs with the NEB, external audits of certain PMC programs and systems, and periodic update meetings with NEB staff regarding the status and progress of corrective actions. In early February 2015, the NEB imposed a penalty on PMC of $76,000 CAD related to these issues.  It is possible that additional fines and penalties may be assessed against PMC in the future related to this matter.

 

Kemp River Pipeline Releases.  During May and June 2013, two separate releases were discovered on our Kemp River pipeline in Northern Alberta, Canada that, in the aggregate, resulted in the release of approximately 700 barrels of condensate and light crude oil. Clean-up and remediation activities are being conducted in cooperation with the applicable regulatory agencies. Final investigation by the Alberta Energy Regulator is not complete. To date, no charges, fines or penalties have been assessed against PMC with respect to these releases; however, it is possible that fines or penalties may be assessed against PMC in the future. We estimate that the aggregate clean-up and remediation costs associated with these releases will be $15 million. Through June 30, 2015, we spent $9 million in connection with clean-up and remediation activities.

 

Bay Springs Pipeline Release. During February 2013, we experienced a crude oil release of approximately 120 barrels on a portion of one of our pipelines near Bay Springs, Mississippi. Most of the released crude oil was contained within our pipeline right of way, but some of the released crude oil entered a nearby waterway where it was contained with booms. The EPA has issued an administrative order requiring us to take various actions in response to the release,

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including remediation, reporting and other actions. We have satisfied the requirements of the administrative order; however, we may be subjected to a civil penalty. The aggregate cost to clean up and remediate the site was $6 million.

 

Note 11—Operating Segments

 

We manage our operations through three operating segments: Transportation, Facilities and Supply and Logistics. Our Chief Operating Decision Maker (our Chief Executive Officer) evaluates segment performance based on measures including segment profit and maintenance capital investment. We define segment profit as revenues and equity earnings in unconsolidated entities less (a) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses. Each of the items above excludes depreciation and amortization. Maintenance capital consists of capital expenditures for the replacement of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets.

 

The following table reflects certain financial data for each segment for the periods indicated (in millions):

 

 

 

 

 

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Note 12—Related Party Transactions

 

See Note 15 to our Consolidated Financial Statements included in Part IV of our 2014 Annual Report on Form 10-K for a complete discussion of our related party transactions.

 

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Transactions with Oxy

 

As of June 30, 2015, Oxy owned approximately 13% of the limited partner interests in our general partner and had a representative on the board of directors of GP LLC. During the three and six months ended June 30, 2015 and 2014, we recognized sales and transportation revenues and purchased petroleum products from Oxy. These transactions were conducted at posted tariff rates or prices that we believe approximate market. See detail below (in millions):

 

 

 

We currently have a netting arrangement with Oxy. Our gross receivable and payable amounts with Oxy were as follows as of the dates indicated (in millions):

 

 

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Item 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Introduction

 

The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical Consolidated Financial Statements and accompanying notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations as presented in our 2014 Annual Report on Form 10-K. For more detailed information regarding the basis of presentation for the following financial information, see the Condensed Consolidated Financial Statements and related notes that are contained in Part I, Item 1 of this Quarterly Report on Form 10-Q.

 

Our discussion and analysis includes the following:

 

 

 

 

 

 

 

 

 

 

Executive Summary

 

Company Overview

 

We own and operate midstream energy infrastructure and provide logistics services for crude oil, NGL, natural gas and refined products. We own an extensive network of pipeline transportation, terminalling, storage, and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. We were formed in 1998, and our operations are conducted directly and indirectly through our operating subsidiaries and are managed through three operating segments: Transportation, Facilities and Supply and Logistics. See “—Results of Operations—Analysis of Operating Segments” for further discussion.

 

Overview of Operating Results, Capital Investments and Other Significant Activities

 

For the six months ended June 30, 2015 and 2014, we recognized net income attributable to PAA of $407 million and $671 million, respectively. This decrease was primarily driven by less favorable results from our Supply and Logistics segment. In addition, our operating results for the 2015 period were impacted by costs and lost revenue associated with the Line 901 incident. See further discussion of our segment operating results in the following sections. Net income attributable to PAA for the first six months of 2015 was also impacted by higher depreciation and amortization expense and interest expense associated with our growing asset base and related financing activities.

 

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We invested approximately $1.2 billion in midstream infrastructure projects during the six months ended June 30, 2015, with a targeted expansion capital plan for the full year of 2015 of $2.2 billion. To fund a portion of such capital activities, we issued approximately 22.1 million common units for net proceeds of approximately $1.1 billion. In addition, we paid $810 million of cash distributions to our limited partners and general partner during the six months ended June 30, 2015, and we declared a quarterly distribution of $0.6950 per limited partner unit to be paid on August 14, 2015.

 

 

Acquisitions and Capital Projects

 

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

 

 

 

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2015 Capital Projects

 

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

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

 

 

 

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Results of Operations

 

We manage our operations through three operating segments: Transportation, Facilities and Supply and Logistics. Our Chief Operating Decision Maker (our Chief Executive Officer) evaluates such segment performance based on a variety of measures including segment profit, segment volumes, segment profit per barrel and maintenance capital investment. See Note 19 to our Consolidated Financial Statements included in Part IV of our 2014 Annual Report on Form 10-K for further discussion of how we evaluate segment profit.

 

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

 

 

 

Non-GAAP Financial Measures

 

To supplement our financial information presented in accordance with GAAP, management uses additional measures that are known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future. The primary additional measures used by management are adjusted earnings before interest, taxes, depreciation and amortization (“adjusted EBITDA”) and implied distributable cash flow (“DCF”).

 

Management believes that the presentation of such additional financial measures provides useful information to investors regarding our performance and results of operations because these measures, when used in conjunction with related GAAP financial measures, (i) provide additional information about our core operating performance and ability to generate and distribute cash flow, (ii) provide investors with the financial analytical framework upon which management bases financial, operational, compensation and planning decisions and (iii) present measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) the mark-to-market of derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), 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. We have defined all such items hereinafter as “Selected Items Impacting Comparability.” These additional financial measures are reconciled to the most directly comparable measures as reported in accordance with GAAP, and should be viewed in addition to, and not in lieu of, our Condensed Consolidated Financial Statements and footnotes.

 

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

 

 

 

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Analysis of Operating Segments

 

Transportation Segment

 

Our Transportation segment operations generally consist of fee-based activities associated with transporting crude oil and NGL on pipelines, gathering systems, trucks and barges. The Transportation segment generates revenue through a combination of tariffs, third-party pipeline capacity agreements and other transportation fees.

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

 

 

 

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Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The segment profit generated by our tariff and other fee-related activities depends on the volumes transported on the pipeline and the level of the tariff and other fees charged as well as the fixed and variable field costs of operating the pipeline. Revenue from our pipeline capacity agreements generally reflects a negotiated amount. Revenues and expenses from our Canadian based subsidiaries, which use the Canadian dollar as their functional currency, are translated at the prevailing average exchange rates for each month.

 

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

 

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

 

 

 

 

 

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

 

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

 

 

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

 

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

 

Allocations of equity-indexed compensation expense vary over time (i) between field operating costs and general and administrative expenses and (ii) between segments and could result in variances in those expense categories or segments that differ from the consolidated variance explanations above. See Note 16 to our Consolidated Financial Statements included in Part IV of our 2014 Annual Report on Form 10-K for additional information regarding our equity-indexed compensation plans.

 

Equity Earnings in Unconsolidated Entities.  The favorable variance in equity earnings in unconsolidated entities for the three and six months ended June 30, 2015 compared to the three and six months ended June 30, 2014 was primarily driven by (i) earnings from our 50% interest in BridgeTex, which we acquired in November 2014, (ii) increased throughput on the White Cliffs pipeline due to an expansion of the pipeline that was placed into service in July 2014 and (iii) increased throughput on the Eagle Ford pipeline as a result of increased crude oil production, as discussed in “Net Operating Revenues and Volumes” above.

 

Maintenance Capital. Maintenance capital consists of capital expenditures for the replacement of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. The decrease in maintenance capital for the three and six months ended June 30, 2015 compared to the three and six months ended June 30, 2014 was primarily due to a reclassification of certain maintenance capital costs from our Facilities segment during the 2014 period.

 

Facilities Segment

 

Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services for crude oil, refined products, NGL and natural gas, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. The Facilities segment generates revenue through a combination of month-to-month and multi-year agreements and processing arrangements. Revenues and expenses from our Canadian based subsidiaries, which use the Canadian dollar as their functional currency, are translated at the prevailing average exchange rates for each month.

 

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

 

 

 

 

 

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

 

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

 

 

 

 

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

 

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

 

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

 

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

 

Supply and Logistics Segment

 

Our revenues from supply and logistics activities reflect the sale of gathered and bulk-purchased crude oil, as well as sales of NGL volumes purchased from suppliers and natural gas sales attributable to the activities performed by our natural gas storage commercial optimization group. Generally, we expect our segment profit to increase or decrease directionally with (i) increases or decreases in our Supply and Logistics segment volumes (which consist of lease gathering crude oil purchase volumes and NGL sales volumes), (ii) demand for lease gathering services we provide producers and (iii) the overall volatility and strength or weakness of market conditions and the allocation of our assets among our various risk management strategies. In addition, the execution of our risk management strategies in conjunction with our assets can provide upside in certain markets. We do not anticipate that future changes in revenues resulting from variances in commodity prices will be a primary driver of segment profit.

 

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

 

 

 

 

 

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

 

 

 

Because the commodities that we buy and sell are generally indexed to the same pricing indices for both the sales and purchases, revenues and costs related to purchases will fluctuate with market prices. However, the margins related to those sales and purchases will not necessarily have a corresponding increase or decrease. The absolute amount of our revenues and purchases decreased for the three and six months ended June 30, 2015 due to lower crude oil and NGL prices relative to the comparative 2014 periods.

 

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

 

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

 

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

 

 

 

 

 

 

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

 

Other Income and Expenses

 

Depreciation and Amortization

 

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

 

Interest Expense

 

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

 

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Income Tax Expense

 

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

 

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

 

Outlook

 

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

 

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

 

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

 

 

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Liquidity and Capital Resources

 

General

 

Our primary sources of liquidity are (i) cash flow from operating activities, (ii) borrowings under our credit facilities or commercial paper program and (iii) funds received from sales of equity and debt securities. Our primary cash requirements include, but are not limited to (i) ordinary course of business uses, such as the payment of amounts related to the purchase of crude oil, NGL and other products and other expenses and interest payments on outstanding debt, (ii) expansion and maintenance activities, (iii) acquisitions of assets or businesses, (iv) repayment of principal on our long-term debt and (v) distributions to our unitholders and general partner. We generally expect to fund our short-term cash requirements through cash flow generated from operating activities and/or borrowings under our commercial paper program or credit facilities. In addition, we generally expect to fund our long-term needs, such as those resulting from expansion activities or acquisitions and refinancing our long-term debt, through a variety of sources (either separately or in combination), which may include the sources mentioned above as funding for short-term needs and/or the issuance of additional equity or debt securities. As of June 30, 2015, we had a working capital deficit of $530 million and approximately $3.1 billion of liquidity available to meet our ongoing operating, investing and financing needs as noted below (in millions):

 

 

 

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We believe that we have, and will continue to have, the ability to access our commercial paper program and credit facilities, which we use to meet our short-term cash needs. We believe that our financial position remains strong and we have sufficient liquidity; however, extended disruptions in the financial markets and/or energy price volatility that adversely affect our business may have a materially adverse effect on our financial condition, results of operations or cash flows. Also, see Item 1A “Risk Factors” of our 2014 Annual Report on Form 10-K for further discussion regarding such risks that may impact our liquidity and capital resources. Usage of our credit facilities, certain of which provide the backstop for our commercial paper program, is subject to ongoing compliance with covenants. As of June 30, 2015, we were in compliance with all such covenants.

 

Cash Flow from Operating Activities

 

For a comprehensive discussion of the primary drivers of cash flow from operating activities, including the impact of varying market conditions and the timing of settlement of our derivatives, see “Liquidity and Capital Resources—Cash Flow from Operating Activities” under Item 7 of our 2014 Annual Report on Form 10-K.

 

Net cash provided by operating activities for the first six months of 2015 and 2014 was $660 million and $963 million, respectively, and primarily resulted from earnings from our operations. Additionally, changes in our inventory levels during these periods are discussed further below, including related impact, if any, to our cash flow from operating activities.

 

During the six months ended June 30, 2015, we increased the volume of crude oil inventory that we held, primarily as a result of storing such inventory due to contango market conditions. These increases were primarily funded

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with proceeds received from the seasonal sale of our NGL and natural gas inventory and thus did not significantly impact cash provided by operating activities during the period.

 

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

 

Acquisitions and Capital Expenditures

 

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

 

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

 

Equity and Debt Financing Activities

 

Our financing activities primarily relate to funding acquisitions, expansion capital projects and refinancing of our debt maturities, as well as short-term working capital and hedged inventory borrowings related to our NGL business and contango market activities. Our financing activities have primarily consisted of equity offerings, senior notes offerings and borrowings and repayments under our credit facilities or commercial paper program, as well as payment of distributions to our unitholders and general partner.

 

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

 

Continuous Offering Program. During the six months ended June 30, 2015, we issued an aggregate of approximately 1.1 million common units under our continuous offering program, generating proceeds of $59 million, including our general partner’s proportionate capital contribution of $1 million, net of $1 million of commissions to our sales agents. The net proceeds from sales were used for general partnership purposes.

 

Underwritten Offering. In March 2015, we completed an underwritten public offering of 21.0 million common units generating net proceeds of approximately $1.1 billion, including our general partner’s proportionate capital contribution of $21 million and net of costs associated with the offering. We used a portion of the net proceeds from this offering to repay outstanding borrowings under our commercial paper program and we used the remaining net proceeds for general partnership purposes, including expenditures for our 2015 capital program.

 

Credit Agreements, Commercial Paper Program and Indentures. Our credit agreements (which impact our ability to access our commercial paper program because they provide the backstop that supports our short-term credit ratings) and the indentures governing our senior notes contain cross-default provisions. A default under our credit agreements would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance

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with the provisions in our credit agreements, our ability to make distributions of available cash is not restricted. We were in compliance with the covenants contained in our credit agreements and indentures as of June 30, 2015.

 

During the six months ended June 30, 2015 we had net borrowings under our credit agreements and commercial paper program of $151 million. These net borrowings resulted primarily from funding needs for (i) internal capital projects, (ii) repayment of our $150 million, 5.25% senior notes that matured in June 2015 and (iii) other general partnership purposes.

 

During the six months ended June 30, 2014, we had net repayments under our credit agreements and commercial paper program of $344 million. The net repayments resulted primarily from cash flow from operating activities, including sales of NGL and natural gas inventory that was liquidated during the periods, as well as cash received from our debt and equity activities.

 

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

 

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

 

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

 

Distributions Paid to Our Unitholders, General Partner and Noncontrolling Interests

 

Distributions to our unitholders and general partner. We distribute 100% of our available cash within 45 days following the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements. On August 14, 2015, we will pay a quarterly distribution of $0.6950 per limited partner unit. This distribution represents a year-over-year distribution increase of approximately 7.8%. See Note 7 to our Condensed Consolidated Financial Statements for details of distributions paid. Also, see Item 5. “Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy” included in our 2014 Annual Report on Form 10-K for additional discussion regarding distributions.

 

Distributions to noncontrolling interests. We paid $1 million for distributions to noncontrolling interests during each of the six months ended June 30, 2015 and 2014.

 

We believe that we have sufficient liquid assets, cash flow from operating activities and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. We are, however, subject to business and operational risks that could adversely affect our cash flow. A prolonged material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity.

 

Contingencies

 

For a discussion of contingencies that may impact us, see Note 10 to our Condensed Consolidated Financial Statements.

 

Commitments

 

Contractual Obligations. In the ordinary course of doing business, we purchase crude oil and NGL from third parties under contracts, the majority of which range in term from thirty-day evergreen to five years with a limited number of contracts extending up to nine years. We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is

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substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. In addition, we enter into similar contractual obligations in conjunction with our natural gas operations. The table below includes purchase obligations related to these activities. Where applicable, the amounts presented represent the net obligations associated with our counterparties (including giving effect to netting buy/sell contracts and those subject to a net settlement arrangement). We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to entities that we deem creditworthy or who have provided credit support we consider adequate.

 

The following table includes our best estimate of the amount and timing of these payments as well as others due under the specified contractual obligations as of June 30, 2015 (in millions):

 

 

 

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Letters of Credit. In connection with supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil, NGL and natural gas. Additionally, we issue letters of credit to support insurance programs, derivative transactions and construction activities. At June 30, 2015 and December 31, 2014, we had outstanding letters of credit of approximately $63 million and $87 million, respectively.

 

Off-Balance Sheet Arrangements

 

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

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Recent Accounting Pronouncements

 

See Note 2 to our Condensed Consolidated Financial Statements.

 

Critical Accounting Policies and Estimates

 

For a discussion regarding our critical accounting policies and estimates, see “Critical Accounting Policies and Estimates” under Item 7 of our 2014 Annual Report on Form 10-K.

 

FORWARD-LOOKING STATEMENTS

 

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

 

 

 

 

 

 

 

 

 

 

 

 

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Other factors described herein, as well as factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please read “Risk Factors” discussed in Item 1A of our 2014 Annual Report on Form 10-K. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

 

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

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

 

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Commodity Price Risk

 

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

 

 

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

 

 

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

 

 

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

 

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

 

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

 

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

 

 

 

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

 

Interest Rate Risk

 

Our use of variable rate debt and any forecasted issuances of fixed rate debt expose us to interest rate risk. Therefore, from time to time we use interest rate derivatives to hedge interest rate risk associated with anticipated

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interest payments and, in certain cases, outstanding debt instruments. All of our senior notes are fixed rate notes and thus are not subject to interest rate risk. The majority of our variable rate debt at June 30, 2015, $885 million, is subject to interest rate re-sets, which range from one day to one month. The average interest rate on variable rate debt that was outstanding during the six months ended June 30, 2015 was 0.4%, based upon rates in effect during such period. The fair value of our interest rate derivatives is an asset of $9 million as of June 30, 2015. A 10% increase in the forward LIBOR curve as of June 30, 2015 would result in an increase of $63 million to the fair value of our interest rate derivatives. A 10% decrease in the forward LIBOR curve as of June 30, 2015 would result in a decrease of $63 million to the fair value of our interest rate derivatives. See Note 8 to our Condensed Consolidated Financial Statements for a discussion of our interest rate risk hedging activities.

 

Currency Exchange Rate Risk

 

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

 

Item 4. CONTROLS AND PROCEDURES

 

Disclosure Controls and Procedures

 

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

 

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

 

Changes in Internal Control over Financial Reporting

 

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

 

Certifications

 

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

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PART II. OTHER INFORMATION

 

Item 1.LEGAL PROCEEDINGS

 

The information required by this item is included under the caption “Litigation” in Note 10 to our Condensed Consolidated Financial Statements, and is incorporated herein by reference thereto.

 

Item 1A. RISK FACTORS

 

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

 

Item 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

 

None.

 

Item 3.DEFAULTS UPON SENIOR SECURITIES

 

None.

 

Item 4.MINE SAFETY DISCLOSURES

 

None.

 

Item 5.OTHER INFORMATION

 

None.

 

Item 6.EXHIBITS

 

The exhibits listed on the accompanying Exhibit Index are filed or incorporated by reference as part of this report, and such Exhibit Index is incorporated herein by reference.

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SIGNATURES

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

 

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EXHIBIT INDEX

 

 

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†Filed herewith.

 

††Furnished herewith.

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